Preventing Undue Discrimination and Preference in Transmission Service, 12266-12531 [E7-3636]
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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Parts 35 and 37
[Docket Nos. RM05–17–000 and RM05–25–
000; Order No. 890]
Preventing Undue Discrimination and
Preference in Transmission Service
Issued February 16, 2007.
Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule.
AGENCY:
SUMMARY: The Federal Energy
Regulatory Commission is amending the
regulations and the pro forma open
access transmission tariff adopted in
Order Nos. 888 and 889 to ensure that
transmission services are provided on a
basis that is just, reasonable and not
unduly discriminatory or preferential.
The final rule is designed to: Strengthen
the pro forma open-access transmission
tariff, or OATT, to ensure that it
achieves its original purpose of
remedying undue discrimination;
provide greater specificity to reduce
opportunities for undue discrimination
and facilitate the Commission’s
enforcement; and increase transparency
in the rules applicable to planning and
use of the transmission system.
EFFECTIVE DATE: This rule will become
effective May 14, 2007.
FOR FURTHER INFORMATION CONTACT:
Daniel Hedberg (Technical Information),
Office of Energy Markets and Reliability,
Federal Energy Regulatory Commission,
888 First Street, NE., Washington, DC
20426, (202) 502–6243.
W. Mason Emnett (Legal Information),
Office of the General Counsel—Energy
Markets, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–6540.
´
Kathleen Barron (Legal Information),
Office of the General Counsel—Energy
Markets, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–6461.
SUPPLEMENTARY INFORMATION:
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Table of Contents
I. Introduction ...........................................................................................................................................................................................
II. Background ...........................................................................................................................................................................................
A. Historical Antecedent ..................................................................................................................................................................
B. Order No. 888 and Subsequent Reforms .....................................................................................................................................
C. EPAct 2005 and Recent Developments .......................................................................................................................................
III. Need for Reform of Order No. 888 ....................................................................................................................................................
A. Opportunities for Undue Discrimination Continue to Exist .....................................................................................................
B. Lack of Transparency Undermines Confidence in Open Access and Impedes Enforcement of Open Access Requirements
C. Congestion and Inadequate Infrastructure Development Impede Customers’ Use of the Grid ...............................................
D. A Consistent Method of Measuring ATC Is Needed ..................................................................................................................
E. Discriminatory Pricing of Imbalances ..........................................................................................................................................
F. Redispatch/Conditional Firm .......................................................................................................................................................
G. EPAct 2005 Emphasized Certain Policies and Priorities for the Commission .........................................................................
IV. Summary, Scope and Applicability of the Final Rule .....................................................................................................................
A. Summary of Reforms ....................................................................................................................................................................
B. Core Elements of Order No. 888 That Are Retained ..................................................................................................................
1. Federal/State Jurisdiction ......................................................................................................................................................
2. Native Load Protection ..........................................................................................................................................................
3. The Types of Transmission Services Offered ......................................................................................................................
4. Functional Unbundling .........................................................................................................................................................
C. Applicability of the Final Rule ....................................................................................................................................................
1. Non-ISO/RTO Public Utility Transmission Providers .........................................................................................................
2. ISO and RTO Public Utility Transmission Providers and Transmission Owner Members of ISOs and RTOs ...............
3. Non-Public Utility Transmission Providers/Reciprocity .....................................................................................................
V. Reforms of the OATT ..........................................................................................................................................................................
A. Consistency and Transparency of ATC Calculations .................................................................................................................
B. Coordinated, Open and Transparent Planning ...........................................................................................................................
C. Transmission Pricing ....................................................................................................................................................................
1. General ....................................................................................................................................................................................
2. Energy and Generation Imbalances .......................................................................................................................................
3. Credits for Network Customers .............................................................................................................................................
4. Capacity Reassignment ..........................................................................................................................................................
5. ‘‘Operational’’ Penalties .........................................................................................................................................................
a. Unreserved Use Penalties ...............................................................................................................................................
b. Distribution of Operational Penalties ............................................................................................................................
c. Applicability of Operational Penalties Proposal to RTOs and Other Independent or Non-Profit Entities ...............
6. ‘‘Higher of’’ Pricing Policy ....................................................................................................................................................
7. Other Ancillary Services .......................................................................................................................................................
D. Non-Rate Terms and Conditions .................................................................................................................................................
1. Modifications to Long-Term Firm Point-to-Point Service ...................................................................................................
a. Planning Redispatch and Conditional Firm Options ...................................................................................................
b. Proposals for Transparent Redispatch ...........................................................................................................................
c. Other Requested Service Modifications ........................................................................................................................
2. Hourly Firm Service ..............................................................................................................................................................
3. Rollover Rights .......................................................................................................................................................................
4. Modification of Receipt or Delivery Points ..........................................................................................................................
5. Acquisition of Transmission Service ....................................................................................................................................
a. Processing of Service Requests ......................................................................................................................................
b. Reservation Priority ........................................................................................................................................................
6. Designation of Network Resources .......................................................................................................................................
a. Qualification as a Network Resource .............................................................................................................................
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Paragraph
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b. Documentation for Network Resources .........................................................................................................................
c. Undesignation of Network Resources ............................................................................................................................
7. Clarifications Related to Network Service ............................................................................................................................
a. Secondary Network Service ...........................................................................................................................................
b. Behind the Meter Generation .........................................................................................................................................
8. Transmission Curtailments ....................................................................................................................................................
9. Standardization of Rules and Practices ................................................................................................................................
a. Business Practices ...........................................................................................................................................................
b. Liability and Indemnification ........................................................................................................................................
10. OATT Definitions ................................................................................................................................................................
E. Enforcement ..................................................................................................................................................................................
1. General Policy ........................................................................................................................................................................
2. Civil Penalties ........................................................................................................................................................................
VI. Information Collection Statement ......................................................................................................................................................
VII. Environmental Analysis ....................................................................................................................................................................
VIII. Regulatory Flexibility Act Analysis ................................................................................................................................................
IX. Document Availability .......................................................................................................................................................................
X. Effective Date and Congressional Notification ...................................................................................................................................
Appendix A: Summary of Compliance Filing Requirements
Appendix B: Commenting Party Acronyms
Appendix C: Pro Forma Open Access Transmission Tariff
Before Commissioners: Joseph T.
Kelliher, Chairman; Suedeen G.
Kelly, Marc Spitzer, Philip D.
Moeller, and Jon Wellinghoff.
I. Introduction
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1. This Final Rule addresses and
remedies opportunities for undue
discrimination under the pro forma
Open Access Transmission Tariff
(OATT) adopted in 1996 by Order No.
888.1 This landmark rulemaking
fostered greater competition in
wholesale power markets by reducing
barriers to entry in the provision of
transmission service. In the ten years
since Order No. 888, however, the
Commission has found that the OATT
contains flaws that undermine realizing
its core objective of remedying undue
discrimination. In the Notice of
Proposed Rulemaking (NOPR) issued on
May 19, 2006, the Commission
proposed to remedy those flaws.2 After
receiving approximately 6,500 pages of
comments from close to 300 parties, we
now take final action. We highlight
below the most critical reforms being
adopted today.
1 Promoting Wholesale Competition Through
Open Access Non-discriminatory Transmission
Services by Public Utilities; Recovery of Stranded
Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21540 (May 10, 1996), FERC
Stats. & Regs. § 31,036 (1996), order on reh’g, Order
No. 888–A, 62 FR 12274 (Mar. 14, 1997), FERC
Stats. & Regs. § 31,048 (1997), order on reh’g, Order
No. 888–B, 81 FERC § 61,248 (1997), order on reh’g,
Order No. 888–C, 82 FERC § 61,046 (1998), aff’d in
relevant part sub nom. Transmission Access Policy
Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000)
(TAPS v. FERC), aff’d sub nom. New York v. FERC,
535 U.S. 1 (2002).
2 Preventing Undue Discrimination and
Preference in Transmission Service, Notice of
Proposed Rulemaking, 71 FR 32,636 (Jun. 6, 2006),
FERC Stats. & Regs. § 32,603 (2006).
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2. First, the Final Rule will increase
nondiscriminatory access to the grid by
eliminating the wide discretion that
transmission providers currently have
in calculating available transfer
capability (ATC).3 The calculation of
ATC is one of the most critical functions
under the OATT because it determines
whether transmission customers can
access alternative power supplies.
Despite this, the existing OATT does not
prescribe how ATC should be calculated
because the Commission sought to rely
on voluntary efforts by the industry to
develop consistent methods of ATC
calculation. This voluntary industry
effort has not proven successful. The
Commission therefore acts today to
require public utilities, working through
the North American Electric Reliability
Corporation (NERC), to develop
consistent methodologies for ATC
calculation and to publish those
methodologies to increase transparency.
This important reform will eliminate the
wide discretion that exists today in
calculating ATC and ensure that
customers are treated fairly in seeking
alternative power supplies.
3. Second, the Final Rule will
increase the ability of customers to
access new generating resources and
promote efficient utilization of
transmission by requiring an open,
transparent, and coordinated
transmission planning process.
Transmission planning is a critical
3 The Commission used the term ‘‘Available
Transmission Capability’’ in Order No. 888 to
describe the amount of additional capability
available in the transmission network to
accommodate additional requests for transmission
services. To be consistent with the term generally
accepted throughout the industry, the Commission
revises the pro forma OATT to adopt the term
‘‘Available Transfer Capability.’’
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function under the pro forma OATT
because it is the means by which
customers consider and access new
sources of energy and have an
opportunity to explore the feasibility of
non-transmission alternatives. Despite
this, the existing pro forma OATT
provides limited guidance regarding
how transmission customers are treated
in the planning process and provides
them very little information on how
transmission plans are developed. These
deficiencies are serious, given the
substantial need for new infrastructure
in this Nation.4 We act today to remedy
these deficiencies by requiring
transmission providers to open their
transmission planning process to
customers, coordinate with customers
regarding future system plans, and share
necessary planning information with
customers.
4. Third, the Final Rule will also
increase the efficient utilization of
4 Congress placed special emphasis on the
development of transmission infrastructure,
including the consideration of advanced
transmission technologies, in the Energy Policy Act
of 2005 (EPAct 2005). See Pub. L. 109–58, 119 Stat.
594 (to be codified in scattered titles of the U.S.C.).
The Commission has taken steps to implement that
goal in numerous contexts, including recent
rulemaking proceedings that address the promotion
of transmission investment through pricing reform
and the siting of certain transmission facilities. See
Promoting Transmission Investment through
Pricing Reform, Order No. 679, 71 FR 43294 (Jul.
31, 2006), FERC Stats. & Regs. § 31,222 (2006), order
on reh’g, Order No. 679–A, 72 FR 1152 (Jan. 10,
2007), FERC Stats. & Regs. § 31,236 (2007), reh’g
pending; Regulations for Filing Applications for
Permits to Site Interstate Electric Transmission
Facilities, Order No. 689, 71 FR 69440 (Dec. 1,
2006), FERC Stats. & Regs. § 31,234 (2006), reh’g
pending. As discussed herein, several actions taken
in this Final Rule also relate to the need for
investments in transmission infrastructure and are
consistent with the Commission’s responsibilities
under EPAct 2005.
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transmission by eliminating artificial
barriers to use of the grid. The existing
pro forma OATT allows a transmission
provider to deny a request for long-term
point-to-point service if the request
cannot be satisfied in only one hour of
the requested term. This practice
discourages the efficient use of the
existing grid and precludes access to
alternative power supplies. We reform
this practice by requiring that a
conditional firm option be offered to
customers seeking long-term point-topoint service, i.e., conditional firm
service. We also modify the redispatch
obligations of transmission providers to
increase the efficient utilization of the
grid, while also ensuring that reliability
to native load customers is maintained.
5. Fourth, by adopting these and other
reforms, the Final Rule facilitates the
use of clean energy resources such as
wind power. Conditional firm service is
particularly important to wind resources
that can provide significant economic
and environmental value even if
curtailed under limited circumstances.
Open and coordinated transmission
planning will enhance the ability of
customers to access clean energy
resources as part of their future resource
portfolio. The Final Rule also benefits
clean energy resources by reforming
energy and generator imbalance charges.
These reforms are particularly important
to intermittent resources such as wind
power because these resources have
limited ability to control their output
and, hence, must be assured that
imbalance charges are no more than
required to provide appropriate
incentives for prudent behavior.
6. Fifth, the Final Rule will strengthen
compliance and enforcement efforts. We
are increasing the transparency of pro
forma OATT administration, thereby
increasing the ability of customers and
our Office of Enforcement to detect
undue discrimination. We are adopting
operational penalties for clear violations
of an OATT, thereby enhancing
compliance while also reducing the
burdens on our Office of Enforcement.
We are also increasing the clarity of
many other OATT requirements,
thereby facilitating compliance by
transmission providers with our
regulations. This Final Rule thus reflects
the close integration of our Office of
Enforcement into policy development at
the Commission. Several of the reforms
we adopt today are informed by our
experience with OATT administration
through oversight, audits, and
investigations performed by the Office
of Enforcement.
7. Finally, we modify and improve
several provisions of the pro forma
OATT using our experience over the
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past ten years and clarify others that
have proven ambiguous. For example,
we reform our rollover rights policy to
ensure that the rights and obligations of
rollover customers are consistent with
the resulting obligations of transmission
providers to plan and upgrade the
system to accommodate rollovers. We
remove the price cap on reassigned
capacity because it is not necessary to
remedy market power and doing so will
otherwise increase the efficient use of
existing capacity. We increase the
efficient use of existing capacity by
providing a priority to certain ‘‘preconfirmed’’ requests for service. We
increase certainty by providing greater
clarity regarding the wholesale contracts
that qualify as network resources. We
also adopt numerous clarifications that
should assist transmission providers
and customers in implementing and
using the pro forma OATT
8. Our actions in this proceeding have
been informed to a great extent by the
comments received in response to our
notices of inquiry in the abovecaptioned dockets and the subsequent
NOPR.5 We appreciate the time and
thoughtfulness of all sectors of the
industry in preparing comments. We
have found them very informative and
useful in reaching our decisions in this
Final Rule.
II. Background
A. Historical Antecedent
9. In the NOPR, the Commission
explained the historical background that
led up to the issuance of Order No. 888,
and the initiation of this rulemaking
proceeding. We repeat that history here
to place in context the actions we take
today.
10. In the first few decades after
enactment of the Federal Power Act
(FPA) in 1935, the industry was
characterized mostly by self-sufficient,
vertically integrated electric utilities, in
which generation, transmission, and
distribution facilities were owned by a
single entity and sold as part of a
bundled service to wholesale and retail
customers. Most electric utilities built
their own power plants and
transmission systems, entered into
interconnection and coordination
arrangements with neighboring utilities,
and entered into long-term contracts to
make wholesale requirements sales
(bundled sales of generation and
transmission) to municipal, cooperative,
5 Preventing Undue Discrimination and
Preference in Transmission Services, Notice of
Inquiry, 112 FERC ¶ 61,299 (2005) (NOI);
Information Requirements for Available Transfer
Capability, Notice of Inquiry, 111 FERC ¶ 61,274
(2005) (ATC NOI).
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and investor-owned utilities connected
to each utility’s transmission system.
Each system covered a limited service
area, which was defined by the retail
franchise decisions of State regulatory
agencies. This structure of separate
systems arose naturally primarily due to
cost and the technological limitations
on the distance over which electricity
could be transmitted.
11. A number of statutory, economic,
and technological developments in the
1970s led to an increase in coordinated
operations and competition. Among
those was the passage of the Public
Utility Regulatory Policies Act of 1978
(PURPA),6 which was designed to
lessen dependence on foreign fossil
fuels by encouraging the development of
alternative generation sources and
imposing a mandatory purchase
obligation on utilities for generation
from such sources. PURPA also enabled
the Commission to order wheeling of
electricity under limited
circumstances.7 The rapid expansion
and performance of the independent
power industry following the enactment
of PURPA demonstrated that traditional,
vertically integrated public utilities
need not be the only sources of reliable
power. During this period, the profile of
generation investment began to change,
and a market for non-traditional power
supply beyond the purchases required
by PURPA began to emerge. The
economic and technological changes in
the transmission and generation sectors
helped encourage many new entrants in
the generating markets that could sell
electric energy profitably with smaller
scale technology at a lower price than
many utilities selling from their existing
generation facilities at rates reflecting
cost. However, it became increasingly
clear that the potential consumer
benefits that could be derived from
these technological advances could be
realized only if more efficient generating
plants could obtain access to the
regional transmission grids. Because
many traditional vertically integrated
utilities still did not provide open
access to third parties and favored their
own generation if and when they
6 Pub. L. 95–617, 92 Stat. 3117 (1978) (codified
in U.S.C. titles 15, 16, 26, 30, 42, and 43).
7 Section 211 of the FPA, 16 U.S.C. 824j. In earlier
years, a few customers were able to obtain access
as a result of litigation, beginning with the U.S.
Supreme Court’s decision in Otter Tail Power
Company v. United States, 410 U.S. 366 (1973).
Additionally, some customers gained access by
virtue of Nuclear Regulatory Commission license
conditions and voluntary preference power
transmission arrangements associated with Federal
power marketing agencies. See, e.g., Consumers
Power Co., 6 NRC 887, 1036–44 (1977); Toledo
Edison Co., 10 NRC 265, 327–34 (1979); Florida
Municipal Power Agency v. Florida Power and Light
Co., 839 F. Supp. 1563 (M.D. Fla. 1993).
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provided transmission access to third
parties, access to cheaper, more efficient
generation sources remained limited.
12. The Commission encouraged the
development of independent power
producers (IPPs), as well as emerging
power marketers, by authorizing marketbased rates for their power sales on a
case-by-case basis, and by encouraging
more widely available transmission
access on a case-by-case basis. Marketbased rates helped to develop
competitive bulk power markets by
allowing generating utilities to move
more quickly and flexibly to take
advantage of short-term or even longterm market opportunities than those
utilities operating under traditional
cost-of-service tariffs. In approving these
market-based rates, the Commission
required that the seller and its affiliates
lack market power or mitigate any
market power that they may have had.8
The major concern of the Commission
was whether the seller or its affiliates
could limit competition and thereby
drive up prices. A key inquiry became
whether the seller or its affiliates owned
or controlled transmission facilities in
the relevant service area and therefore,
by denying access or imposing
discriminatory terms or conditions on
transmission service, could foreclose
other generators from competing.
Beginning in the late 1980s, in order to
mitigate their market power to meet the
Commission’s conditions, public
utilities seeking Commission
authorization for blanket approval of
market-based rates for generation
services under section 205 of the FPA
filed ‘‘open access’’ transmission tariffs
of general applicability.9 The
Commission also approved proposed
mergers under section 203 of the FPA
on the condition that the merging
companies remedy anticompetitive
effects potentially caused by the merger
by filing ‘‘open access’’ tariffs. The early
tariffs submitted in market-based rate
proceedings under section 205 and
merger proceedings under section 203
did not, however, provide access to the
transmission system that was
comparable to the service the
transmission providers used for their
own purposes. Rather, they typically
made available only point-to-point
transmission service, i.e., service from a
single point of receipt to a single point
8 See, e.g., Dartmouth Power Associates Limited
Partnership, 53 FERC ¶ 61,117 (1990);
Commonwealth Atlantic Limited Partnership, 51
FERC ¶ 61,368 (1990); Doswell Limited Partnership,
50 FERC ¶ 61,251 (1990); Citizens Power & Light
Co., 48 FERC ¶ 61,210 (1989); Ocean State Power,
44 FERC ¶ 61,261 (1988); and Orange and Rockland
Utilities, Inc., 42 FERC ¶ 61,012 (1988).
9 See Order No. 888 at 31,644 n.52.
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B. Order No. 888 and Subsequent
Reforms
14. In April 1996, as part of its
statutory obligation under sections 205
and 206 of the FPA to remedy undue
discrimination, the Commission
adopted Order No. 888 prohibiting
public utilities from using their
monopoly power over transmission to
unduly discriminate against others. In
that order, the Commission required all
public utilities that own, control or
operate facilities used for transmitting
electric energy in interstate commerce to
file open access non-discriminatory
transmission tariffs that contained
minimum terms and conditions of nondiscriminatory service. It also obligated
such public utilities to ‘‘functionally
unbundle’’ their generation and
transmission services. This meant
public utilities had to take transmission
service (including ancillary services) for
their own new wholesale sales and
purchases of electric energy under the
open access tariffs, and to separately
state their rates for wholesale
generation, transmission and ancillary
services.13 Each public utility was
required to file the pro forma OATT
included in Order No. 888 without any
deviation (except a limited number of
terms and conditions that reflect
regional practices).14 After the
effectiveness of their OATTs, public
utilities were allowed to file, pursuant
to section 205 of the FPA, deviations
that were consistent with or superior to
the pro forma OATT’s terms and
conditions. Because certain owners,
controllers or operators of interstate
transmission facilities were not subject
to the Commission’s jurisdiction under
sections 205 and 206 and thus were not
subject to Order No. 888, the
Commission adopted a reciprocity
provision in the pro forma OATT that
conditions the use by a non-public
utility of a public utility’s open access
services on an agreement to offer nondiscriminatory transmission services in
return.
15. In addition to imposing the
functional unbundling requirement, the
Commission also encouraged broader
reforms through the formation of
independent system operators (ISOs).
The Commission stated that ISOs can
provide significant benefits such as
enhancing regional efficiencies and
further remedying undue
discrimination.15 While the
Commission declined to mandate ISOs,
it set forth eleven principles for
assessing ISO proposals submitted to
the Commission.16
16. Order No. 888 also clarified the
Commission’s interpretation of the
Federal and State jurisdictional
boundaries over transmission and local
distribution. While Order No. 888
reaffirmed that the Commission has
exclusive jurisdiction over the rates,
10 Pub. L. 102–486, 106 Stat. 2776 (1992)
(codified at, among other places, 15 U.S.C. 79z–5a
and 16 U.S.C. 796 (22–25), 824j–l).
11 15 U.S.C. 79a, repealed by EPAct 2005 sec.
1263; see Repeal of the Public Utility Holding
Company Act of 1935 and Enactment of the Public
Utility Holding Company Act of 2005, Order No.
667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. &
Regs. ¶ 31,197 (2005), order on reh’g, Order No.
667–A, 71 FR 28446 (May 16, 2006), FERC Stats.
& Regs. ¶ 31,213 (2006), order on reh’g, Order No.
667–B, 71 FERC 42750 (Jul. 28, 2006), FERC Stats.
& Regs. ¶ 31,224 (2006), reh’g pending.
12 16 U.S.C. 824j (authorizing the Commission to
require transmission utilities to provide service in
certain circumstances); 16 U.S.C. 824k (establishing
rates for service provided pursuant to an order
under section 211).
13 This is known as ‘‘functional unbundling’’
because the transmission element of a wholesale
sale is separated or unbundled from the generation
element of that sale, although the public utility may
provide both functions. See infra section IV.B.4 of
this Final Rule.
14 See Order No. 888 at 31,769–70 (noting that the
pro forma OATT expressly identified certain nonrate terms and conditions, such as the time
deadlines for determining available transfer
capability in section 18.4 or scheduling changes in
sections 13.8 and 14.6, that may be modified to
account for regional practices if such practices are
reasonable, generally accepted in the region, and
consistently adhered to by the transmission
provider).
15 Order No. 888 at 31,655.
16 Id. at 31,730–32.
of delivery. As these early tariffs were
offered only by transmission providers
that volunteered to provide service to
third parties, they resulted in a
patchwork of open access that was not
sufficient to facilitate wholesale
generation markets.
13. In response to the competitive
developments following PURPA, and
the fact that limited transmission access
and significant regulatory barriers
continued to constrain the development
of generation by independent power
producers, Congress enacted Title VII of
the Energy Policy Act of 1992 (EPAct
1992).10 EPAct 1992 reduced regulatory
barriers to entry by creating a class of
‘‘Exempt Wholesale Generators’’ that
were exempt from the requirements of
the Public Utility Holding Company Act
of 1935.11 EPAct 1992 also expanded
the Commission’s authority to approve
applications for transmission services
under sections 211 and 212 of the
FPA.12 Though the Commission
aggressively implemented expanded
section 211, it ultimately concluded that
the procedural limitations in section
211 thwarted the Commission’s ability
to effectively eliminate undue
discrimination in the provision of
transmission service.
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terms, and conditions of unbundled
retail transmission in interstate
commerce by public utilities, it
nevertheless recognized the legitimate
concerns of State regulatory authorities
regarding the transmission component
of bundled retail sales. The Commission
therefore declined to extend its
unbundling requirement to the
transmission component of bundled
retail sales. On appeal, the U.S.
Supreme Court affirmed this element of
Order No. 888, finding that the
Commission made a statutorily
permissible choice.17
17. The same day it issued Order No.
888, the Commission issued a
companion order, Order No. 889,18
addressing the separation of vertically
integrated utilities’ transmission and
merchant functions, the information
transmission providers were required to
make public, and the electronic means
they were required to use to do so.
Order No. 889 imposed Standards of
Conduct governing the separation of,
and communications between, the
utility’s transmission and wholesale
power functions, to prevent the utility
from giving its merchant arm
preferential access to transmission
information. All public utilities that
owned, controlled or operated facilities
used in the transmission of electric
energy in interstate commerce were
required to create or participate in an
Open Access Same-Time Information
System (OASIS) that was to provide
existing and potential transmission
customers the same access to
transmission information.
18. Among the information public
utilities were required to post on their
OASIS was the transmission provider’s
calculation of ATC. Though the
Commission acknowledged that beforethe-fact measurement of the availability
of transmission service is ‘‘difficult,’’ it
concluded that it was important to give
potential transmission customers ‘‘an
easy-to-understand indicator of service
availability.’’ 19 Because formal methods
did not then exist to calculate ATC and
total transfer capability (TTC), the
Commission encouraged industry efforts
to develop consistent methods for
calculating ATC and TTC.20 Order No.
889 ultimately required transmission
providers to base their calculations on
17 New
York v. FERC, 535 U.S. 1 (2002).
Access Same-Time Information System
(Formerly Real-Time Information Networks) and
Standards of Conduct, Order No. 889, 61 FR 21737
(May 10, 1996), FERC Stats. & Regs. ¶ 31,035 (1996),
order on reh’g, Order No. 889–A, FERC Stats. &
Regs. ¶ 31,049 (1997), order on reh’g, Order No.
889–B, 81 FERC ¶ 61,253 (1997).
19 Order No. 889 at 31,605.
20 Id. at 31,607.
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‘‘current industry practices, standards
and criteria’’ and to describe their
methodology in their tariffs.21 The
Commission noted that the requirement
that transmission providers purchase
only ATC that is posted as available
‘‘should create an adequate incentive for
them to calculate ATC and TTC as
accurately and as uniformly as
possible.’’ 22
19. The electric industry continued to
undergo economic and regulatory
changes in the years following the
issuance of Order No. 888. Retail access
was adopted by approximately 25 states
in the late 1990s.23 This State
restructuring activity spurred significant
changes at the wholesale level as well
by encouraging or requiring the
divestiture of generation plants by
traditional electric utilities and the
development of ISOs that could manage
short-term energy markets necessary to
support retail access. At the same time,
there was a significant increase in the
number of mergers between traditional
electric utilities and between electric
utilities and gas pipeline companies,
and large increases in the number of
power marketers and independent
generation facility developers entering
the marketplace. Trade in bulk power
markets increased significantly and the
Nation’s transmission grid was used
more heavily and in new ways as
customers took advantage of the pro
forma OATT and purchased power from
competitive sellers.
20. In the wake of these changes, in
December 1999, the Commission
adopted Order No. 2000.24 That
rulemaking recognized that Order No.
888 set the foundation upon which
competitive electric markets could
develop, but did not eliminate the
potential to engage in undue
discrimination and preference in the
provision of transmission service.25 The
rulemaking also recognized that Order
No. 888 did not address the regional
nature of the grid, including the
treatment of parallel flows, pancaked
rates, and congestion management.
Thus, the Commission encouraged the
creation of RTOs to address important
operational and reliability issues and
21 Id.
22 Id.
23 See Energy Information Administration, Retail
Unbundling—U.S. Summary (2005), https://www.
eia.doe.gov/oil_gas/natural_gas/restructure/state/
us.html.
24 Regional Transmission Organizations, Order
No. 2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. &
Regs. ¶ 31,089 (1999), order on reh’g, Order No.
2000–A, 65 FR 12088 (Mar. 8, 2000), FERC Stats.
& Regs. ¶ 31,092 (2000), aff’d sub nom. Public
Utility District No. 1 of Snohomish County,
Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).
25 Order No. 2000 at 31,015.
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eliminate any residual discrimination in
transmission services that can occur
when the operation of the transmission
system remains in the control of a
vertically integrated utility. The
Commission found that RTOs would
increase the efficiency of wholesale
markets by eliminating pancaked rates,
internalizing parallel flow, managing
congestion efficiently, and operating
markets for energy, capacity and
ancillary services. The Commission
established an open, collaborative
process that relied on voluntary regional
participation to design RTOs tailored to
the specific needs of each region. The
Commission noted, however, that ‘‘[i]f
the industry fails to form RTOs under
this approach, the Commission will
reconsider what further regulatory steps
are in the public interest.’’26
21. Following Order No. 2000, RTOs
were approved in several regions of the
country including the Northeast (PJM;
ISO New England),27 the Midwest
(MISO) and the South (SPP). In most
cases, RTOs have assumed
responsibility for calculating ATC
across the footprint of the RTO, as well
as the planning and expansion of the
transmission grid, at least for facilities
necessary for maintaining system
reliability. However, large areas of the
Nation have not developed RTOs using
the voluntary structure adopted by the
Commission in Order No. 2000.
Moreover, transmission customers have
complained that even in RTO markets
there are instances when comparable
transmission service is not provided,
particularly in the area of transmission
planning.
C. EPAct 2005 and Recent
Developments
22. Enacted on August 8, 2005, EPAct
added a number of new authorities and
priorities for the Commission and
emphasized certain of its existing
obligations. Among other things, EPAct
2005 recognized the importance of
adequate transmission infrastructure
development and its role in facilitating
the development of competitive
wholesale markets. The Congressional
directives in EPAct 2005 are intended to
reverse the decline in transmission
infrastructure investment. For example,
Congress required the Commission to
adopt a rule establishing incentive
ratemaking for transmission
infrastructure to help promote reliability
and reduce congestion.28 Congress also
26 Id.
at 30,993.
list of commenter acronyms can be found in
Appendix B.
28 EPAct 2005 sec. 1241 (to be codified at section
219 of the FPA, 16 U.S.C. 824s).
27 A
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directed the Commission to encourage
the deployment of advanced
technologies.29 Congress further
directed the Commission to ‘‘exercise its
authority’’ under EPAct 2005 ‘‘in a
manner that facilitates the planning and
expansion of transmission facilities to
meet the reasonable needs of loadserving entities.’’30 Congress also gave
the Commission certain ‘‘backstop’’
transmission siting authority, and
authorized the creation of interstate
compacts establishing transmission
siting agencies.31 EPAct 2005 also
authorized the Commission to require
unregulated transmitting utilities
(except for certain small entities) to
provide access to their transmission
facilities on a comparable basis.32
Congress further ordered the
Department of Energy (DOE) to study
the benefits of economic dispatch and
required the Commission to convene
regional joint boards to develop a report
to Congress containing
recommendations for the use of security
constrained economic dispatch within
each region.33 Congress also directed the
Commission to facilitate price
transparency in markets for the sale and
transmission of electric energy in
interstate commerce, having due regard
for the public interest, the integrity of
those markets, fair competition, and the
protection of consumers, and it
authorized the Commission to prescribe
rules to provide for the dissemination of
information about the availability and
price of wholesale electric energy and
transmission service.34 Finally,
Congress emphasized compliance with
the Commission’s regulations, adopting
and increasing the civil and criminal
penalties for violations of Commissionadministered statutes and regulations.35
29 EPAct 2005 sec. 1223 (to be codified at 42
U.S.C. 16422). Indeed, Congress provided specific
guidance as to the types of advanced technologies
that should be encouraged in infrastructure
improvements to include, among others, optimized
transmission line configurations (including
multiple phased transmission lines), controllable
load, distributed generation (including PV, fuel
cells, and microturbines), and enhanced power
device monitoring. Id.
30 EPAct 2005 sec. 1233(a) (to be codified at
section 217(b)(4) of the FPA, 16 U.S.C. 824q).
31 EPAct 2005 sec. 1221(a) (to be codified at
section 216 of the FPA, 16 U.S.C. 824p).
32 EPAct 2005 sec. 1231 (to be codified at section
211A of the FPA, 16 U.S.C. 824j–1)
33 EPAct 2005 sec. 1234 (to be codified at 42
U.S.C. 16432); EPAct 2005 sec. 1298 (to be codified
at section 223 of the FPA, 16 U.S.C. 824w). EPAct
2005 sec. 1234(b) defined economic dispatch as
‘‘the operation of generation facilities to produce
energy at the lowest cost to reliably serve
consumers, recognizing any operational limits of
generation and transmission facilities.’’
34 EPAct 2005 sec. 1281 (to be codified at section
220 of the FPA, 16 U.S.C. 824t).
35 EPAct 2005 sec. 1284(d) (to be codified at
section 316 of the FPA, 16 U.S.C. 825o); EPAct 2005
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23. Recognizing the need for reform of
Order No. 888 in light of the
Commission’s continuing concern
regarding whether the pro forma OATT
adequately remedies undue
discrimination, the Commission issued
an NOI on September 16, 2005 36
seeking comments on appropriate
reforms of the Order No. 888 pro forma
OATT. In the NOI, the Commission
expressed its preliminary view that
reforms to the pro forma OATT and
public utilities’ OATTs are necessary to
avoid undue discrimination or
preference in the provision of
transmission service. The NOI sought
comments on how best to accomplish
the Commission’s goals, specifically
with respect to enhancements that are
needed to (1) Remedy any unduly
discriminatory or preferential
application of the pro forma OATT or
(2) improve the clarity of the Order No.
888 pro forma OATT and the individual
public utility tariffs in order to more
readily identify violations and facilitate
compliance.
24. The Commission received over
4,000 pages of initial and reply
comments on the NOI. Based on these
comments, the comments submitted in
response to the ATC NOI,37 our
experience in implementing Order No.
888, and the changes in the industry
since we adopted it, the Commission
proposed to reform the pro forma OATT
in a number of ways. The Commission
issued the NOPR on May 19, 2006
proposing a number of reforms aimed at
remedying undue discrimination in the
provision of open access transmission
service and improving the clarity of the
pro forma OATT and the individual
tariffs of transmission providers in order
to more readily identify violations and
facilitate compliance. The Commission
received over 5,700 pages of initial and
reply comments in response. In
response to comments on the particular
issue of redispatch and conditional firm
service (discussed in more detail
below), the Commission issued a Notice
of Request for Supplemental Comments
on November 15, 2006,38 that resulted
in receipt of an additional 750 pages of
comments.
25. Based on this voluminous record,
the Commission concludes that reform
of the pro forma OATT and associated
amendments to its regulations are
necessary to reduce the potential for
undue discrimination and provide
sec. 1284(e) (to be codified at section 316A of the
FPA, 16 U.S.C. 825o–1).
36 See supra note 5.
37 Id.
38 Preventing Undue Discrimination and
Preference in Transmission Service, 117 FERC
¶ 61,185 (2006).
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12271
clarity in the obligations of transmission
providers and customers alike. We turn
next to a more complete explanation of
this need for reform.
III. Need for Reform of Order No. 888
A. Opportunities for Undue
Discrimination Continue To Exist
26. Although Order No. 888 has been
successful in many important respects,
the need for reform of the Order No. 888
pro forma OATT has been apparent for
some time. In 1999, the Commission
held, in adopting Order No. 2000, that
the pro forma OATT could not fully
remedy undue discrimination because
transmission providers retained both the
incentive and the ability to discriminate
against third parties, particularly in
areas where the pro forma OATT left the
transmission provider with significant
discretion.39 The Commission made a
similar finding in Order No. 2003,40
holding that opportunities for undue
discrimination continue to exist in areas
where the pro forma OATT leaves
transmission providers with substantial
discretion.41 The NOPR reaffirmed these
findings, preliminarily concluding that
opportunities for undue discrimination
continue to exist in the provision of
open access transmission service. The
Commission therefore proposed a
number of reforms to the pro forma
OATT to address the opportunities and
incentives transmission providers have
to unduly discriminate.
Comments
27. Many commenters agree with the
Commission that reforms to the pro
forma OATT are needed because there
continue to be both the opportunity and
incentive for transmission providers to
engage in undue discrimination.42
28. Several commenters offered
examples of their experiences with
transmission providers, where they
believe transmission providers have
acted in an unduly discriminatory
39 Order
No. 2000 at 31,105.
Standardization of Generator
Interconnection Agreements and Procedures, Order
No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats.
& Regs. ¶ 31,146 at P 11–12 (2003), order on reh’g,
Order No. 2003–A, 69 FR 15932 (Mar. 26, 2004),
FERC Stats. & Regs. ¶ 31,160 (2004), order on reh’g,
Order No. 2003–B, 70 FR 265 (Jan. 4, 2005), FERC
Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order
No. 2003–C, 70 FR 37,661 (Jun. 30, 2005), FERC
Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom.
National Association of Regulatory Utility
Commissioners v. FERC, No. 04–1148, 2007 U.S.
App. LEXIS 626 (D.C. Cir. Jan. 12, 2007).
41 Order No. 2003 at P 11–12.
42 E.g., APPA, EPSA, East Texas Cooperatives,
Fayetteville, NRG, Occidental, TAPS, TDU Systems,
Williams, Entegra Reply, and NRECA Reply.
40 See
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fashion.43 Constellation claims that on
multiple occasions it has been denied a
transmission request when the
transmission provider’s OASIS indicates
that ATC is available, but Constellation
had no effective and timely way to
challenge that determination because of
the ATC ‘‘black box.’’ Constellation
states that given that its needs for
transmission service are often near-term
or immediate—e.g., to facilitate a loadserving obligation or wholesale
transaction that must be consummated
quickly—seeking redress at the
Commission for improperly denied
service generally is not time- or costeffective. Instead, Constellation asserts,
it is often forced to accept the
determination of the transmission
provider that ATC is not available (even
though its OASIS may indicate
otherwise) and seek alternate
transmission paths and/or products to
consummate its transaction.
29. Powerex also describes instances
where a transmission provider has
granted short-term firm point-to-point
transmission service requests to
transmission customers who have been
allowed to remain in the queue, even
when zero ATC is posted, in the hopes
that a transmission provider’s OASIS
site wrongly indicates zero ATC or will
soon be updated. Powerex asserts that
such practices clog the short-term pointto-point transmission queue with
multiple requests and result in
duplicative requests for service that
reflect customers’ attempts to secure
service, rather than the actual quantity
of service needed. Moreover, Powerex
argues, transmission provider discretion
in this area and the lack of transparency
raise customer concerns about
preferential treatment.
30. Occidental claims that it has firsthand experience with a vertically
integrated transmission provider that,
despite having an OATT, appears to
have persistently used its transmission
system to preferentially benefit its
merchant function. Similarly, Williams
alleges that its interests have been
consistently and significantly
compromised by the discretion afforded
transmission providers in the
interpretation of the OATT and the lack
of transparency in requesting,
scheduling and interrupting of
transmission service.
31. Other commenters, however,
argue that the Commission’s proposed
reforms are based on unsupported
allegations of undue discrimination. EEI
maintains that any opportunities to
engage in undue discrimination have
43 See, e.g., Dow, Fayetteville, Occidental, and
Williams.
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been largely mitigated by current
regulatory policies and changes in the
industry. EEI explains that, unlike the
situation that existed when the
Commission enacted Order No. 888,
much of the country’s transmission
facilities are now under the control of
RTOs and ISOs. In addition, EEI states,
other transmission providers have
transferred (or are in the process of
transferring) the administration of their
OATTs and OASIS functions to
independent transmission service
coordinators. Even among the
transmission providers who have taken
neither of those steps, EEI argues that
the open access requirements of Order
No. 888 and the Standards of Conduct
of Order Nos. 889 and 2004 have largely
eliminated the ability of transmission
providers to engage in undue
discrimination in the provision of
transmission service.44 In addition, EEI
states, the Commission’s expanded civil
penalty authority added to the FPA by
EPAct 2005 gives the Commission a
powerful tool that will further eliminate
any remaining incentive of transmission
providers to engage in undue
discrimination in the provision of
transmission service. Therefore, EEI
asserts, any modifications to the OATT
should be narrowly tailored to address
the perceptions of residual undue
discrimination. To the extent that such
perceptions exist, however, Community
Power Alliance states that, in the
absence of concrete record evidence,
they are just that—perceptions.
32. Although Duke strongly supports,
as a policy matter, OATT reforms that
will eliminate the perception that undue
discrimination is possible and/or likely,
Duke argues that the FPA does not
provide the Commission the authority to
remedy mere ‘‘opportunities’’ to
discriminate. Duke states that, in some
cases, the Commission is attempting to
remedy an opportunity for undue
discrimination that does not exist or is
proposing to impose a remedy that does
not actually remedy the perceived
opportunity. Duke notes, however, that
some OATT terms and conditions are
subject to multiple interpretations and
argues that the Commission can, and
should, justify the OATT reforms
proposed in the NOPR as reforms
needed to provide clarity to existing
policies.
33. With regard to specific allegations
made by commenters, several
transmission providers respond that the
examples given by transmission
customers do not illustrate instances of
undue discrimination. Rather, they
assert, these examples demonstrate the
44 See
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transmission customers’ lack of
understanding of the OATT
requirements, and the data available on
OASIS.45
34. New Mexico Attorney General
argues that the traditional Stateregulated, vertically-integrated cost-ofservice world is not in need of reform.
Contrary to the ‘‘conspiracy theorists’’
who argue that utilities have an
incentive to engage in undue
discrimination and preference in
transmission services, New Mexico
Attorney General asserts that utilities
have an incentive to maximize
throughput and revenue between Statelevel rate cases because incremental
transmission revenue is not deducted
from the State-jurisdictional retail
revenues between rate cases. Similarly,
Southern, in its reply comments, asserts
that broad claims of undue
discrimination fail to take into
consideration that vertically-integrated
utilities have more of an incentive to act
appropriately than do independent
utilities because the former have more
to lose (e.g., loss of market-based rates,
state prudence reviews of costs, etc.) if
they are found to have engaged in
wrong-doing. Southern states that any
OATT revisions ultimately adopted by
the Commission must be reasonably
tailored to address an identified
problem or to provide a specific
improvement.
35. Other commenters argue that the
Commission’s focus should be on
transmission providers in non-organized
markets, arguing that remaining
concerns about undue discrimination
have already been addressed in the
world of ISOs and RTOs.46 According to
ISO/RTO Council, this proceeding
provides an opportunity for the
Commission to harmonize the worlds of
organized and non-organized markets in
a manner that encourages competition,
promotes non-discriminatory access,
and maximizes the flow of electricity
across various ISO/RTO and non-ISO/
RTO regions. ISO/RTO Council states
that, in the existing regulatory
environment, a utility that is not a
member of an ISO or RTO can sell into,
or purchase from, an ISO or RTO market
even though the non-ISO/RTO utility
operates under tariff rules that are less
open and transparent, particularly in
terms of access to generation resources
and pricing/system information, than
their competitors that belong to an ISO
or RTO. Such asymmetry, ISO/RTO
Council argues, operates as an
45 See, e.g., Entergy Reply, Progress Energy Reply,
and Southern Reply.
46 E.g., Indicated New York Transmission
Owners, ISO/RTO Council, and Northeast Utilities.
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impediment to fair and nondiscriminatory transmission access and
management of grid congestion.
36. ISO/RTO Council states that its
members do not seek to impose their
market designs on the rest of the nation.
At the same time, ISO/RTO Council
argues that meaningful reform should
ensure a level of transparency (of both
price and the dispatch utilized by nonISO/RTO vertically-integrated entities)
in regions without an ISO or RTO that
can assist the flow of electricity and
enhance reliability and planning in both
ISO/RTO and non-ISO/RTO regions.
37. Exelon urges the Commission to
hold the transmission providers outside
ISOs or RTOs to the same standard of
non-discrimination that exists within
those organizations. Further, MISO/PJM
States argue that in order to achieve
some level of independence in non-RTO
regions, non-independent transmission
providers should be encouraged to turn
over operational control of their
transmission systems to an independent
coordinator of transmission whose
functions would include security
coordination, determination of ATC,
granting of transmission service and
oversight for transmission planning.
38. Finally, EPSA suggests that the
Commission establish a one-year review
period for the reformed pro forma
OATT. EPSA urges the Commission to
revisit this Final Rule after one year of
operation under the reformed pro forma
OATT to ensure that the revisions
adopted here do, in fact, protect against
non-discriminatory or preferential
behavior by transmission providers.
NRECA responds that, after this
comprehensive rulemaking process,
there is simply no need for another
major look at the OATT in one year.
Moreover, NRECA states, one year is
likely too short a period for the
Commission and industry participants
to fully appreciate all of the
consequences of those elements of
OATT reform resulting from this
proceeding. At the same time, NRECA
agrees that the Commission should
carefully monitor implementation of the
reformed OATT. This monitoring,
NRECA states, must be an ongoing
process and cannot wait a year to begin.
Commission Determination
39. The Commission concludes that
reforms are needed to address
deficiencies in the pro forma OATT that
have become apparent since 1996, by
limiting remaining opportunities for
undue discrimination. As the
Commission found in Order No. 888, it
is in the economic self-interest of
transmission monopolists, particularly
those with high-cost generation assets,
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to deny transmission or to offer
transmission on a basis that is inferior
to that which they provide to
themselves.47 Such an incentive can
lead to unduly discriminatory behavior
against third parties, particularly if
public utilities have unnecessarily
broad discretion in the application of
their tariffs. This discretion also can
create problems for transmission
providers seeking to comply with our
regulations in good faith because so
many issues are left for their
interpretation, thereby increasing the
possibility of disputes with
transmission customers and
enforcement actions by the
Commission.48 Transmission customers
also have found ways to use the tariffs
to their own advantage, particularly in
the scheduling and queuing processes.49
40. As some commenters note,
opportunities for undue discrimination
persist, particularly in areas where the
pro forma OATT leaves the
transmission provider with substantial
discretion. The Commission has a
responsibility under section 206 of the
FPA to remedy undue discrimination.
Indeed, the court concluded in
Associated Gas Distributors v. FERC,50
that, like the Natural Gas Act,51 the FPA
‘‘fairly bristles’’ with concern over
undue discrimination. Based on AGD,
the Commission determined in Order
No. 888 that:
The Commission has a mandate under
sections 205 and 206 of the FPA to ensure
that, with respect to any transmission in
interstate commerce or any sale of electric
energy for resale in interstate commerce by
a public utility, no person is subject to any
undue prejudice or disadvantage. We must
determine whether any rule, regulation,
practice or contract affecting rates for such
transmission or sale for resale is unduly
discriminatory or preferential, and must
prevent those contracts and practices that do
not meet this standard. * * * AGD
demonstrates that our remedial power is very
broad and includes the ability to order
industry-wide non-discriminatory open
access as a remedy for undue discrimination.
47 Order
No. 888 at 31,682.
e.g., Order No. 2003 at P 11–12.
49 See, e.g., Potomac Economics, Ltd., 2004 State
of the Market Report: Midwest ISO at 30–31, 34–35
(Jun. 2005), https://www.midwestmarket.org/
publish/Document/2b8a32_103ef711180_-7bf20a
48324a/2004%20MISO%20SOM%20Report.pdf?
action=download&_property=Attachment
(explaining that the queuing process, by giving
customers the opportunity to submit multiple
requests for service, provides a low- or no-cost
option that restricts other customers’ access to
congested interfaces, and the scheduling process, by
allowing customers to leave transmission requests
unconfirmed, provides a free option that may invite
hoarding or result in underutilized capacity).
48 See,
50 824
51 15
PO 00000
F.2d 981 (D.C. Cir. 1987) (AGD).
U.S.C. 717.
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12273
Order No. 888 at 31,669. Through this
Final Rule, the Commission exercises
that remedial authority again to limit
further opportunities for undue
discrimination, by minimizing areas of
discretion, addressing ambiguities and
clarifying various aspects of the pro
forma OATT.
41. We disagree with commenters
who assert that the Commission is
relying on unsubstantiated allegations of
discriminatory conduct to justify OATT
reform. The courts have made clear that
the Commission need not make specific
factual findings of discrimination in
order to promulgate a generic rule to
eliminate undue discrimination.52 In
AGD, the court explained that the
promulgation of generic rate criteria
involves the determination of policy
goals and the selection of the means to
achieve them and that courts do not
insist on empirical data for every
proposition upon which the selection
depends: ‘‘[a]gencies do not need to
conduct experiments in order to rely on
the prediction that an unsupported
stone will fall.’’ 53 During this multi-year
proceeding, the Commission has
received many comments arguing that
commenters have either experienced or
perceived that they have experienced
unduly discriminatory conduct by
transmission providers. Even
transmission providers have
acknowledged that there is a continuing
perception that there is the opportunity
for them to unduly discriminate against
their competitors and, accordingly, they
state their support for our reform
effort.54 Moreover, it is undisputed that
the existing pro forma OATT provides
wide discretion in implementing some
of its basic requirements, such as the
assessment of whether sufficient ATC
exists to grant third party access to the
grid and the manner in which new
facilities are planned to satisfy third
party needs. This wide discretion, when
coupled with a transmission provider’s
incentive to discriminate, creates
opportunities for discrimination under
the pro forma OATT. We have an
obligation under section 206 to remedy
that discrimination.
42. It is thus clear to us that,
notwithstanding the Commission’s
efforts in Order No. 888, opportunities
to engage in undue discrimination can
and will persist unless the existing pro
forma OATT is reformed. We therefore
exercise our broad remedial authority
today to limit these remaining
52 TAPS v. FERC, 225 F.3d at 667, 688; National
Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C.
Cir. 2006) (National Fuel).
53 824 F.2d at 1008.
54 See, e.g., Duke and EEI.
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opportunities for undue discrimination.
The Commission concludes that any
additional costs incurred by
transmission providers to implement
the reforms required in this Final Rule
are fully justified by the need to ensure
open, transparent and nondiscriminatory access to transmission
service. We also believe it is appropriate
to adopt these reforms by rulemaking,
rather than rely on complaints filed by
transmission customers or other parties.
Case-by-case application of the reforms
adopted in this Final Rule would be
inappropriate since the most
fundamental problems addressed here
arise from deficiencies in the pro forma
OATT itself, not simply the
implementation of the pro forma OATT
by a few transmission providers. Also,
we decline to establish a one-year
review period for the reformed pro
forma OATT, as EPSA recommends.
The Commission will continue to
actively monitor compliance with its
orders and, as necessary, institute
further proceedings to meet its statutory
obligation to remedy undue
discrimination.
43. The Commission will not catalog
each and every basis for its reform of the
pro forma OATT in this section. Rather,
we identify the bases for some of the
most fundamental reforms herein and,
in addition, we explain in each
individual section of the Final Rule the
inadequacies of the existing pro forma
OATT provisions being addressed there
and the reasons why our reforms are
necessary to remedy undue
discrimination or otherwise provide for
rates, terms and conditions of service
under the pro forma OATT that are just
and reasonable.
B. Lack of Transparency Undermines
Confidence in Open Access and
Impedes Enforcement of Open Access
Requirements
44. Following the issuance of the NOI,
the Commission received a number of
comments asserting that increased
transparency would aid transmission
customers in their participation in the
wholesale market. A common theme in
the comments was that a lack of
transparency could lead to claims of
discrimination and could make such
claims more difficult to resolve.
Commenters urged the Commission to
improve transparency in a number of
areas, particularly the evaluation of ATC
and the planning of the transmission
system, as well as the processing of
transmission service requests and
studies.
45. In the NOPR, the Commission
agreed that a lack of transparency both
increases the potential for undue
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discrimination and makes it more
difficult to detect. The Commission
reasoned that this lack of sufficient
transparency was caused in part by
inadequate compliance with the existing
OASIS regulations and in part by
inadequate transparency requirements.
The Commission stated that the
proposed reforms were intended to
address both elements of the problem in
an effort to increase confidence in open
access tariffs and to facilitate
compliance with the Commission’s
regulations and its enforcement of them.
Comments
46. Williams states that its interests
have been consistently and significantly
compromised by the discretion afforded
transmission providers in the
interpretation of the OATT and the lack
of transparency in requesting,
scheduling and interrupting of
transmission service. According to
Williams, simply being told that service
is being curtailed for reliability
purposes under opaque local
procedures, in the absence of a NERC
Transmission Loading Relief (TLR)
event, leaves market participants
suffering the consequences without
knowing on what basis the decision was
reached, and without assurance that the
decision was made in a nondiscriminatory manner. Ultimately,
Williams adds, the lack of transparency
and latitude taken by the transmission
provider to determine which requests
for service are confirmed or denied and
which are curtailed or interrupted in
real time frustrates the Commission’s
goal of preventing undue discrimination
and preference in the provision of
transmission service. Furthermore,
Williams states, the same lack of
transparency exists around the opaque
processes utilized, assumptions made,
and basis on which the results of
transmission planning studies are
conducted to grant or deny requests for
service.
47. APPA agrees that additional
transparency in the administration of
public utility transmission providers’
OATTs will be of material assistance to
both the Commission and transmission
customers. However, APPA argues that
the Commission must go beyond
increasing transparency in the
administration of public utility
transmission providers’ OATTs.
According to APPA, more transparency
will not change the basic industry
paradigm with transmission customers
depending on monopoly transmission
providers for service. In APPA’s view,
customers are often reluctant to file
complaints or bring problems to the
Commission’s attention because they
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depend on their transmission providers’
systems for the vital services they need
to serve their loads. APPA argues that
the Commission not only has an
obligation to act to remedy undue
discrimination when it sees it, but also
has an affirmative duty to look for it.
According to APPA, the Commission
must continue to actively regulate the
transmission services that public utility
transmission providers offer, even if full
transparency is achieved through the
revisions to the OATT implemented in
the instant docket.
48. EPSA agrees that greater
transparency will help enable market
participants and the Commission to
monitor and audit the behavior of
transmission providers. EPSA states that
the several ‘‘black boxes’’ shielding
discriminatory transmission service
over the past ten years must be opened.
However, EPSA argues, there must be
meaningful clarity and obligations set
out in the rules and OATT
requirements—transparency simply for
the sake of knowing why transmission
service has been denied only
illuminates a ‘‘bridge to nowhere’’ and
fails to satisfy the Federal Power Act.
49. Entergy also supports the
Commission’s efforts to provide greater
clarity in the rights and obligations of
transmission providers and
transmission customers under the
OATT. According to Entergy, many of
the improvements proposed by the
Commission will reduce the likelihood
of disputes and promote greater
confidence on the part of customers that
they are being treated fairly. Entergy
states that, while it recognizes that the
lack of clarity makes it difficult for the
Commission to detect instances of noncompliance by transmission providers,
Entergy also believes that this lack of
clarity often makes it easier for
transmission customers to convert every
practice or policy into a claim of
discrimination or other misconduct.
50. Although not convinced that there
is a compelling need for increased
transparency since transmission
providers are already required to
disclose voluminous amounts of
information, Southern states that it
recognizes that some reforms in the
availability of information may be
advantageous. However, Southern
asserts, providing additional
transparency must not simply impose
additional reporting requirements; any
such transparency-related reforms
should be made after taking into
consideration the extent and type of
data and information that is already
provided.
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Commission Determination
51. The Commission concludes that
inadequate transparency requirements,
combined with inadequate compliance
with existing OASIS regulations,
increases the opportunities for undue
discrimination under the pro forma
OATT and makes instances of undue
discrimination more difficult to detect.
We find that the reforms we adopt in
this Final Rule will improve
transparency in the OATT, reduce
opportunities for undue discrimination,
and increase our ability to detect undue
discrimination.
C. Congestion and Inadequate
Infrastructure Development Impede
Customers’ Use of the Grid
52. The Commission noted in the
NOPR that the ability and incentive to
discriminate increases as the
transmission system becomes more
congested. The Commission observed
that the pro forma OATT contained only
minimal requirements regarding
transmission planning, which have
proven to be inadequate as the Nation
faces insufficient transmission
investment in many areas. The
Commission preliminarily concluded
that the inadequacy of the existing
obligation to conduct transmission
system planning, coupled with the lack
of transparency surrounding system
planning generally, required reform of
the pro forma OATT to ensure that
transmission infrastructure is
constructed on a nondiscriminatory
basis and is otherwise sufficient to
support reliable and economic service to
all eligible customers. The Commission
therefore proposed to require public
utilities to engage in an open and
transparent planning process at both the
local and regional levels.
sroberts on PROD1PC70 with RULES
Comments
53. APPA agrees that the lack of
adequate transmission infrastructure is
one of the core problems facing the
electric utility industry. APPA supports
revisions to the pro forma OATT to
enhance and improve transmission
planning on both an individual system
and regional basis. Several commenters
go further, arguing that the proposed
reforms are insufficient and urging the
Commission to more strongly encourage
infrastructure development. EPSA
asserts that successful implementation
of the Congressional policy in favor of
wholesale competition and State
policies in favor of competitive
procurement is frustrated by the lack of
sufficient open access to the
transmission grid. According to EPSA,
new power plant investment is highly
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unlikely to occur, except by the
transmission provider or its affiliate on
a ‘‘sole source’’ or ‘‘no bid’’ basis
(despite Federal and State policies to
the contrary), if unaffiliated suppliers
cannot effectively and efficiently obtain
transmission service. EPSA argues that
failure to boldly reform the
Commission’s open access transmission
rules at this critical juncture would
effectively hand an undeserved victory
to the very transmission providers who,
by the Commission’s own findings, have
the motive and the opportunity to
discriminate. International
Transmission argues that tariff reform is
no substitute for prudent investment in
the transmission infrastructure needed
to increase the underlying physical
capability of the transmission system.
54. On the other hand, some
commenters dispute the Commission’s
assertion in the NOPR that verticallyintegrated utilities operating in nonRTO regions have an incentive to
discriminate and, therefore, are not
adequately expanding the transmission
grid to accommodate new entry by more
efficient competitors. New Mexico
Attorney General argues that verticallyintegrated utilities operating under the
traditional rate-base, rate-of-return
model of regulation in fact have been
historically criticized for having
incentives to overbuild. New Mexico
Attorney General asserts that most
transmission projects are in reality
derailed by strong ‘‘NIMBY’’ opposition
to the actual siting of transmission lines.
Another countervailing factor to the
utility’s incentive to overbuild, in New
Mexico Attorney General’s view, is the
fact that State regulators attempt to limit
capacity investment to reasonable levels
only necessary to serve native load.
55. Southern states that the
Commission’s assertion in the NOPR
that vertically-integrated utilities do not
have an incentive to expand the grid
overlooks the fact that many such
utilities are under State legal duties to
procure generation supplies through
open, non-discriminatory requests for
proposals, with the winners of those
requests for proposals often being
competitors of the vertically-integrated
utility. Southern maintains that the
winning competitive generation is then
integrated into the host utility’s
transmission system and dispatch, and
the transmission system is expanded to
ensure the deliverability of this
competitive generation. Furthermore,
Southern states, a competitive generator
can also have the output of its generator
planned into the transmission
provider’s system if it takes long-term
firm service under the OATT, with the
transmission provider then being under
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a legal duty to expand its transmission
system accordingly. Southern notes that
it alone has invested $3.2 billion in
transmission over the past decade and
plans to invest another $2.8 billion over
the next five years (2006–2010).
56. Community Power Alliance also
argues that the Commission’s own June
2005 ‘‘State of the Markets Report’’
contradicts the Commission’s assertion
that vertically-integrated utilities do not
have the proper incentives to expand
the grid. Community Power Alliance
contends that this report shows that the
amount of transmission investments
made in the non-RTO regions, where
vertically-integrated utilities typically
operate, substantially exceeds the
amount of transmission investments
made in RTO regions.
Commission Determination
57. The Commission concludes that
reforms are needed to ensure that
transmission infrastructure is evaluated,
and if needed, constructed on a
nondiscriminatory basis and is
otherwise sufficient to support reliable
and economic service to all eligible
customers. As noted above, verticallyintegrated utilities do not have an
incentive to expand the grid to
accommodate new entries or to facilitate
the dispatch of more efficient
competitors. Despite this, the existing
pro forma OATT contains very few
requirements regarding how
transmission planning should be
conducted to ensure that undue
discrimination does not occur.
58. Our concern over this flaw is
heightened by the critical need for new
transmission infrastructure in this
Nation. As the Commission explained in
the NOPR, transmission capacity is
being constructed at a much slower rate
than the rate of increase in customer
demand, with transmission capacity per
MW of peak demand declining at an
average rate of 2.1 percent per year
during the period 1992 to 2002.55 The
projections suggest that this trend will
continue through 2012.56 As a result,
there has been a significant decrease in
transmission capacity relative to load in
every NERC region.57 In light of this
trend, there is a compelling need to
build new transmission and respond to
increasing demand through other
55 Eric Hirst, U.S. Transmission Capacity: Present
Status and Future Prospects (Aug. 2004), https://
www.eei.org/industry_issues/energy_infrastructure/
transmission/USTransCapacity10–18–04.pdf
(Present Status and Future Prospects).
56 Present Status and Future Prospects at v.
57 Brendan Kirby (Oak Ridge National Laboratory,
U.S. Department of Energy), Barriers to
Transmission Investment, Technical Conference
Presentation, (Docket No. AD05–5–000) (April 22,
2005).
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means. EEI estimates that capital
spending must increase by 25 percent,
from $4 billion annually to $5 billion
annually, to ensure system reliability
and to accommodate wholesale electric
markets.58 The legacy systems
constructed by vertically-integrated
utilities prior to the adoption of Order
No. 888 support ‘‘only limited amounts
of inter-regional power flows and
transactions. Thus, existing systems
cannot fully support all of society’s
goals for a modern electric-power
system.’’ 59
59. Expansion of the transmission
system, as well as more efficient use of
the grid, will alleviate the growth of
congestion in most regions of the
country. Transmission congestion has
created fairly small local load pockets in
primarily urban areas, e.g., New York
City, Long Island, Boston, parts of
Connecticut, and the San Francisco Bay
Area. Other load pocket concerns have
arisen in parts of northern Virginia, and
various load centers in SPP. Still other
constraints are more regional in scope:
from the Midwest to the Mid-Atlantic,
from the Midwest to TVA, into and
within California, from TVA and
Southern into Entergy, from MidAmerica Interconnected Network into
Wisconsin-Upper Michigan Systems,
and into Florida.
60. Transmission congestion can have
significant cost impacts on consumers.
In 2002, DOE issued a study estimating
the costs of congestion in four U.S.
regions: California, PJM, New York and
New England.60 DOE found that, despite
58 Energy Policy Act of 2005: Hearings before the
Subcommittee on Energy and Air Quality of the
House Committee on Energy and Commerce, 109th
Congress, First Sess. (2005) (Prepared statement of
Thomas R. Kuhn, President of EEI).
59 Present Status and Future Prospects at v.
60 U.S. Department of Energy, National
Transmission Grid Study at 11, 16–17 (May 2002),
available at https://www.ferc.gov/industries/electric/
indus-act/transmission-grid.pdf. To conduct this
study, DOE estimated the benefits of interregional
wholesale power markets using the Policy Office
Electricity Modeling System (POEMS). POEMS is a
national energy model designed specifically to
examine the impacts of electricity restructuring.
The model includes economic, regional, and
temporal detail that is needed to analyze the
economics of interregional trade. In the first step of
the study, DOE used POEMS to examine the cost
reductions that would occur if increased electricity
transfers across congested paths were allowed in
these four regions, assuming generators bid their
marginal costs. Under this assumption, consumer
costs declined by $157 million per year. In the
second step, DOE calculated the increase in
congestion costs under the assumption that
generators bid above their marginal operating costs
when supplies are tight and additional electricity
cannot be imported. The price spikes were assumed
to occur during hours when at least one
transmission link into a sub-region was congested
and demand was greater than 90 percent of peak
demand. When prices spike an additional $50 per
MWh (above the price predicted when generators
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the overall savings of wholesale
electricity markets that lowered
consumers’ electricity bills by nearly
$13 billion annually, interregional
transmission congestion cost consumers
hundreds of millions of dollars
annually. DOE concluded that relieving
bottlenecks in these four regions alone
could save consumers about $500
million annually.61 In 2006, DOE
released another study identifying two
areas of the country with severe existing
or growing congestion problems: the
Atlantic coastal area from metropolitan
New York southward through Northern
Virginia, and Southern California.62
61. The decline in transmission
investment and increase in transmission
congestion underscore our concerns
over inadequate planning provisions of
the existing pro forma OATT. The
existing pro forma OATT, as indicated
above, contains very little specificity
regarding how transmission planning
should be conducted, how customers’
needs are incorporated into that process,
and what information is publicly
available regarding the transmission
providers’ assumptions, criteria and
data used in the planning process.
These inadequacies are sufficiently
severe, standing alone, to merit reform
of the OATT. However, they are of even
greater concern given the current state
of the transmission grid. With
inadequate levels of investment in the
grid and increasing transmission
congestion, customers’ ability to access
alternatives to the transmission
provider’s resources is limited. It is
therefore imperative for the Commission
to ensure that the planning process
under each transmission provider’s
OATT is sufficient to prevent undue
discrimination and transparent enough
to detect any remaining instances of
undue discrimination. We have done so
in the reforms adopted and explained in
section V.B.
D. A Consistent Method of Measuring
ATC Is Needed
62. Another area in which
transmission providers have significant
discretion under the pro forma OATT is
the calculation of ATC. While Order No.
888 obligated each public utility to
calculate the amount of transfer
capability on its system available for
sale to third parties, the Commission
bid their marginal operating cost) during these
periods, congestion costs nearly double to $300
million.
61 Id. at xi and ii.
62 U.S. Department of Energy, National Electric
Transmission Congestion Study, Executive
Summary at 2 (August 2006), available at https://
www.ferc.gov/industries/electric/indus-act/doecongestion-study-2006.pdf.
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did not standardize the methodology for
calculating ATC, nor did it impose any
specific requirements regarding the
disclosure of the methodologies used by
each transmission provider.63 As a
result, there are a variety of ATC
calculation methodologies in use today
and very few clear rules governing their
use. Moreover, there is often very little
transparency about the nature of these
calculations, given that many
transmission providers have filed only
summary explanations of their ATC
methodologies in Attachment C to their
OATTs.
63. In the NOPR, the Commission
noted that, although the industry has
sought to pursue greater consistency in
ATC calculations through existing
NERC processes, these efforts to date
have been largely unsuccessful. The
Commission expressed its preliminary
determination that the lack of a
consistent, industry-wide methodology
for calculating ATC gives transmission
providers the ability and the
opportunity to unduly discriminate
against third parties. The Commission
therefore proposed a number of reforms
to the process of calculating ATC to
provide clarity and transparency to
users of the grid.
Comments
64. As discussed further in section
V.A below, most commenters support
the Commission’s goal of requiring
greater consistency in the manner in
which ATC is calculated and additional
transparency of ATC calculations.
Commenters generally favor the
Commission’s proposal to increase
consistency in the calculation of ATC,
including consistent definitions of its
components, data inputs, modeling
assumptions, and data exchange and
coordination protocols. For example,
Exelon argues that each ATC component
should be used in the same manner for
all purposes (e.g., granting transmission
service to third parties or for the
transmission provider’s own network
load). Some commenters assert that
industry-wide standardization of ATC
calculation might not be possible and
that the Commission should consider
interconnection-wide, regional or even
sub-regional standardization. Others
suggest allowing flexibility in order to
capture differences in system operation,
usage, market operations and topology.
65. At the technical conference
organized in this proceeding on October
12, 2006 (October 12 Technical
Conference), the entire panel agreed that
definitions must be consistent and a
panelist representing Constellation
63 Order
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asserted that broad differences in the
core definitions of the ATC calculation
are neither rational nor explainable.64
NERC, however, recognized that the
goal of achieving consistency may not
mean that a single ATC methodology is
required.65 NERC explained that
consistency can be achieved with a
limited number of methodologies if the
requirements of those methodologies are
properly coordinated and
communicated.
66. Numerous commenters support
the Commission’s proposals to increase
transparency in the manner in which
transmission providers derive ATC,
including greater OASIS posting.
Commenters opposing the transparencyrelated reforms focus on the
Commission’s proposal to require the
posting of narratives on OASIS
explaining reasons for changes in
monthly and yearly ATC values on
constrained paths. They argue that such
a requirement would be too burdensome
and would not provide customers with
any significant new information.
67. Several commenters believe that
making substantial ATC calculation and
modeling data transparent will
compromise Critical Energy
Infrastructure Information (CEII) but
provide suggestions for resolving the
issue. Others express concern that the
data required for posting on OASIS is
not CEII but commercially sensitive.
Finally, commenters provide
suggestions regarding the requirement to
post metrics on OASIS related to the
provision of transmission service under
the pro forma OATT, including various
additional metrics the Commission
should consider. Others state that this
information is already available on
OASIS.
sroberts on PROD1PC70 with RULES
Commission Determination
68. We find that the lack of a
consistent and transparent methodology
for calculating ATC gives transmission
providers the ability and opportunity to
unduly discriminate in the provision of
open access transmission service. There
are few clear rules respecting ATC
calculation, and transmission providers
retain unnecessarily broad discretion in
this area. This resulting discretion is a
significant problem because calculation
of ATC, which varies greatly depending
on the criteria and assumptions used,
may allow the transmission provider to
discriminate in subtle ways against its
competitors. On systems where
64 Transcript of October 12 Technical Conference
at 149–50, available at Preventing Undue
Discrimination and Preference in Transmission
Service, Technical Conference (Docket No. RM05–
25–000).
65 Id. at 125–50.
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transmission capacity is congested, this
lack of consistency, coupled with a lack
of transparency, is of heightened
importance and has led to recurring
disputes over whether the transmission
provider is exercising its discretion to
discriminate against its competitors.
This discretion also hampers the
detection of undue discrimination and,
thereby, undermines the Commission’s
ability to enforce the general
requirement in Order No. 888 that
transmission service be provided on a
not unduly discriminatory basis.
69. As discussed more fully below in
section V.AIII.D, this Final Rule adopts
a number of reforms that address the
potential for remaining undue
discrimination in the determination of
ATC by requiring consistency in how
ATC is evaluated, as well as providing
greater transparency about how a
transmission provider calculates and
allocates ATC.
E. Discriminatory Pricing of Imbalances
70. Order No. 888 focused primarily
on the adoption of non-rate terms and
conditions of service, rather than
instituting broad reform of the
Commission’s transmission pricing
policies. Consistent with this focus, the
Commission did not propose broad
transmission pricing reform in the
NOPR, but rather focused on instances
where current pricing practices under
the pro forma OATT may no longer be
sufficient to remedy undue
discrimination or ensure just and
reasonable rates. One significant reform
proposed in the NOPR related to charges
for imbalance energy. The Commission
preliminarily found that the existing
policies provide wide discretion in the
development of these charges and hence
the potential for undue discrimination.
The Commission therefore proposed
certain principles to remedy that
potential and sought comment on
whether a specific imbalance pricing
method would be appropriate.
Comments
71. In general, transmission customers
complain about the level and scope of
energy and generator imbalance charges
that are levied under the pro forma
OATT and under individual
interconnection agreements.66
Customers complain that energy
imbalance charges are excessive and not
66 Energy imbalance charges, including penalties
on some systems, are imposed on a transmission
customer when the amount of energy scheduled for
delivery to the transmission grid does not equal the
amount of energy withdrawn by that customer.
Generator imbalance charges are levied on
generators for deviations between the amount of
energy they schedule and the amount they actually
deliver to the grid.
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related to the actual costs incurred by
transmission providers. They also argue
that the inconsistency between these
charges in different control areas is
unnecessary, and that other means of
compensating the transmission
provider, such as return-in-kind, should
be considered. Generators likewise
complain that generator imbalance
charges are excessive, that transmission
providers refuse to credit generators
with the revenues resulting from
imbalance penalties that are collected,
and that transmission providers prevent
unaffiliated generators from purchasing
or self-supplying generator imbalance
services. In addition, owners of
intermittent resources complain that
generator imbalance charges, which are
imposed to provide an incentive for
generators to schedule accurately, are
inappropriate given their lack of control
and ability to cure deviations.
Commission Determination
72. The Commission agrees that
imbalance charges should provide
appropriate incentives to keep
schedules accurate without being
excessive. We also find that consistency
in imbalance charges, both between and
among energy and generator imbalances,
is preferable to the wide variety of
imbalance provisions in place today. All
imbalances have the same net effect on
the transmission system in that they
require other generation to be ramped
up or down to compensate for the
imbalance. As such, the Commission
adopts two pro forma OATT provisions
(Schedule 4 for energy imbalances and
Schedule 9 for generator imbalances)
based on a tiered structure similar to the
imbalance provision used by
Bonneville, as described further below.
Such an approach recognizes the link
between escalating deviations and
potential reliability impacts on the
system while keeping imbalance charges
closely related to incremental costs. The
Commission finds, however, that
intermittent resources should be exempt
from the highest-tier deviation band. We
also require transmission providers to
credit to all non-offending transmission
customers the revenues they collect in
excess of incremental costs.
F. Redispatch/Conditional Firm
73. In the NOPR, the Commission
examined whether existing methods for
evaluating requests for long-term firm
point-to-point service continue to be
just and reasonable. When a
transmission provider considers a new
resource to serve native load, the
transmission provider does not
eliminate an otherwise economic option
because the resource may not be
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deliverable during a few hours of the
year. For transmission customers,
however, the transmission provider
evaluates whether service can be
granted in every hour of the year that is
modeled and, if not, it informs the
customer that service cannot be
provided out of existing transfer
capability. Only if the transmission
customer agrees to pay for facilities
studies does the transmission provider
evaluate redispatch options, including
whether they are less expensive than the
upgrade costs. The Commission
therefore proposed to reform the
existing pro forma OATT planning
redispatch 67 obligation, or, in the
alternative, to add a conditional firm
service to the pro forma OATT. As
proposed by the Commission,
conditional firm would have been a
long-term service allowing the
transmission provider to give a lower
curtailment priority than firm to the
transmission customer during a prespecified number of hours.
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Comments
74. Some commenters support the
inclusion of both a modified planning
redispatch obligation and a conditional
firm service in the pro forma OATT,
stating that both are required to remedy
undue discrimination and provide for
comparable transmission service. These
commenters urge the Commission to
require transmission providers to offer
planning redispatch and conditional
firm service and allow customers to
choose the option that best suits their
physical, commercial and economic
circumstances.
75. Others opine that conditional firm
service may be simpler and less costly
to implement. These commenters prefer
the development of conditional firm
service over the modifications to the
planning redispatch service because of
the complexities surrounding redispatch
costs and protocols. For example,
Entergy believes conditional firm
service can provide benefits to
transmission customers without unfairly
socializing costs to native load and
network customers of the transmission
provider.
76. On the other hand, many
commenters argue that the Commission
should not require either option because
the services are unnecessary,
operationally unworkable, and legally
unjustified, or because they would harm
reliability and the quality of existing
67 Although pro forma OATT section 13.5 refers
to ‘‘redispatch,’’ we refer to it here as ‘‘planning
redispatch’’ to distinguish it from the reliability
redispatch provisions in the network integration
transmission service sections of the pro forma
OATT. See infra notes 552 and 557.
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network service and provide
disincentives for transmission
investment. Several commenters state
that these services would make
curtailments of existing firm service
more likely and limit opportunities for
use of secondary network service,
thereby harming native load protections
and reducing reliability, contrary to FPA
sections 215 and 217 respectively.
While it recognizes that conditional firm
service has been successful in parts of
the Western Interconnection, NRECA
contends that a mandate would
undermine responsible planning and
expansion of the transmission grid by
harnessing the transmission provider’s
planning and dispatch functions to
frame elaborate service conditions for
conditional firm service.
77. Several commenters argue that, if
the services are required, the
Commission should ensure that
reliability is not adversely affected.
Others urge the Commission to make the
new services an interim option until
transmission upgrades are in place to
provide firm service. Some commenters
believe planning redispatch and
conditional firm customers should bear
the actual costs of the services received,
including costs associated with system
operational changes needed to
accommodate the services. A few
commenters believe that the
Commission should allow for regional
differences in development of the new
services.
Commission Determination
78. The Commission believes it is
necessary to modify the manner in
which transmission providers assess
point-to-point service requests to
eliminate the potential for undue
discrimination in transmission service.
We find that both techniques—planning
redispatch and conditional firm
service—are currently used under
certain circumstances by transmission
providers to serve native load and,
therefore, that transmission customers
should have comparable services in
order to avoid undue discrimination,
facilitate the provision of long-term
transmission service and provide
customers with greater flexibility in
choosing resources to meet their needs.
We expect that both options will help
integrate new generation more quickly.
This can be particularly beneficial to
renewable generation resources, such as
wind, that can be constructed more
quickly than the transmission upgrades
necessary to deliver their power on a
firm basis over the long-run.
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G. EPAct 2005 Emphasized Certain
Policies and Priorities for the
Commission
79. Finally, we note that the reforms
adopted in this proceeding are
consistent with the policies and
priorities embodied in EPAct 2005, in
which Congress emphasized many of
the same principles reflected in this
Final Rule. First, in EPAct 2005,
Congress placed special emphasis on
the development of transmission
infrastructure. Congress required the
Commission to adopt a rule establishing
incentive-based rates for new
transmission infrastructure investment.
The stated purpose of new FPA section
219 is to benefit ‘‘consumers by
ensuring reliability and reducing the
cost of delivered power by reducing
transmission congestion.’’ 68 Among
other steps, FPA section 219 requires
the Commission to ‘‘(1) Promote reliable
and economically efficient transmission
and generation of electricity by
promoting capital investment in the
enlargement, improvement,
maintenance, and operation of all
facilities for the transmission of electric
energy in interstate commerce,
regardless of the ownership of the
facilities; (2) provide a return on equity
that attracts new investment in
transmission facilities (including related
transmission technologies); [and] (3)
encourage deployment of transmission
technologies and other measures to
increase the capacity and efficiency of
existing transmission facilities and
improve the operation of the
facilities.’’ 69 In addition, Congress
directed the Commission to encourage
the deployment of advanced
transmission technologies.70 Congress
also gave the Commission certain
‘‘backstop’’ transmission siting
authority, and authorized the creation of
interstate compacts establishing
transmission siting agencies.71 Finally,
the Commission was directed to
exercise its authority under EPAct 2005
‘‘in a manner that facilitates the
planning and expansion of transmission
facilities to meet the reasonable needs of
load-serving entities to satisfy the
68 EPAct 2005 sec. 1241 (to be codified at section
219 of the FPA, 16 U.S.C. 824s). The Commission
has issued a Final Rule implementing such an
incentive rate program. See Order Nos. 679 and
679–A.
69 FPA Sec. 219(b)(1).
70 EPAct 2005 sec. 1223 (to be codified at 42
U.S.C. 16442).
71 EPAct 2005 sec. 1221(a) (to be codified at
section 216 of the FPA, 16 U.S.C. 824p). The
Commission implemented new regulations in
accordance with this section to establish filing
requirements and procedures for entities seeking to
construct electric transmission facilities in Order
No. 689.
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service obligations of the load-serving
entities, and enables load-serving
entities to secure firm transmission
rights * * * on a long-term basis for
long-term power supply arrangements
made, or planned, to meet such
needs.’’ 72 Although these provisions
have been, or will be, addressed
primarily in other proceedings, we
conclude that the Final Rule is
consistent with these provisions
because it supports improvements in
infrastructure by reforming the
transmission planning process to ensure
that it is open, transparent and
nondiscriminatory.
80. Second, Congress emphasized the
need for greater transparency in
electricity markets, including
transmission service. EPAct 2005 added
section 220 to the FPA, which requires
the Commission to facilitate ‘‘price
transparency in markets for the sale and
transmission of electric energy in
interstate commerce, having due regard
for the public interest, the integrity of
[that market], fair competition, and the
protection of consumers.’’ 73 The
Commission was authorized to
‘‘prescribe such rules as the
Commission determines necessary and
appropriate to carry out the purposes
of’’ FPA section 220. Those rules ‘‘shall
provide for the dissemination, on a
timely basis, of information about the
availability and prices of wholesale
electric energy and transmission service
to the Commission, State commissions,
buyers and sellers of wholesale electric
energy, users of transmission services,
and the public.’’ This Final Rule
similarly will promote greater
transparency in the provision of
transmission service in many important
areas, including ATC calculation and
transmission planning.
81. Finally, Congress emphasized
compliance with the Commission’s
regulations, increasing the civil and
criminal penalties for violations of
Commission-administered statutes and
regulations.74 This new authority
buttresses the Commission’s efforts to
enforce public utility OATTs and the
regulations requiring transmission
information to be posted on OASIS. As
we explained in the Policy Statement on
Enforcement, however, this new
72 EPAct 2005 sec. 1233(a) (to be codified at
section 217(b)(4) of the FPA, 16 U.S.C. 824q). The
Commission implemented FPA section 217(b)(4) in
Long-Term Firm Transmission Rights in Organized
Electricity Markets, Order No. 681, 71 FR 43564
(Aug. 1, 2006), FERC Stats. & Regs. ¶ 31,226 (2006),
order on reh’g, Order No. 681–A, 117 FERC ¶ 61,201
(2006), reh’g pending.
73 EPAct 2005 sec. 1281 (to be codified at 16
U.S.C. 824t).
74 EPAct 2005 sec. 1284(e)(1) (to be codified at
section 316(A) of the FPA, 16 U.S.C. 825o–1).
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authority carries with it the
responsibility to ensure that
enforcement is firm but fair and that our
rules are as clear as practicable to
facilitate compliance.75 We conclude
that this Final Rule is fully consistent
with these principles because it clarifies
our rules, in many areas, which will
facilitate compliance by transmission
providers.
IV. Summary, Scope and Applicability
of the Final Rule
82. This section provides a summary
of the major components of the Final
Rule, a description of the core elements
of Order No. 888 that we retain, and a
discussion of the applicability of the
proposed rule to various entities.
A. Summary of Reforms
83. Consistency and transparency of
ATC calculations. The Commission
affirms the finding in the NOPR that the
lack of a consistent, industry-wide
methodology for calculating ATC, and
the lack of adequate transparency in
ATC calculations, increases the
potential for undue discrimination and
also makes undue discrimination more
difficult to detect. The lack of consistent
standards can facilitate undue
discrimination by giving a transmission
provider the discretion, and hence the
ability and opportunity, to favor itself
and its affiliates over third parties in
how it calculates and allocates ATC. In
this Final Rule, we give the industry
specific guidance regarding the
calculation of ATC and establish a firm
deadline to develop certain
requirements to make more consistent
the ATC calculation process and the
process of exchanging data between
transmission providers about ATC. In
addition, we amend pro forma OATT
requirements as well as our OASIS
regulations to increase the transparency
in how ATC is calculated.
84. Requirement for coordinated,
open and transparent transmission
planning. The Commission also affirms
the finding in the NOPR that Order No.
888 does not contain sufficient
protections to guard against undue
discrimination in transmission system
planning. Without adequate
coordination and open participation,
market participants have minimal input
or insight into whether a particular
transmission plan treats all loads and
generators comparably. To ensure that
truly comparable transmission service is
provided by all public utility
transmission providers, including RTOs
75 Enforcement of Statutes, Orders, Rules and
Regulations, Policy Statement on Enforcement, 113
FERC ¶ 61,068 (2005) (Policy Statement on
Enforcement).
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12279
and ISOs, we amend the pro forma
OATT to require coordinated, open, and
transparent transmission planning on
both a sub-regional and regional level.
To implement this remedy, we adopt
the eight planning principles proposed
in the NOPR, as well as one additional
principle, that each public utility
transmission provider will be required
to follow. We recognize that many
regions have made significant progress
in recent years in creating greater
openness and transparency in
transmission planning and believe our
proposed reforms will build upon,
strengthen, and improve this progress to
reform transmission planning.
85. Transmission Pricing Reforms.
Consistent with the focus of Order No.
888 on the non-rate terms and
conditions of open access, the
Commission does not initiate broad
reform of transmission pricing policy
through this Final Rule. However, we
have identified several pricing rules that
are part and parcel of OATT service that
merit reform.
• Energy and Generator Imbalance
Charges. We find that energy and
generator imbalance charges we have
previously accepted are excessive, too
varied, and otherwise unrelated to the
cost of providing the service and,
therefore, we reform energy and
generator imbalance pricing. We adopt
tiered pro forma OATT energy and
generator imbalance provisions similar
to those in use by Bonneville and
exempt intermittent resources from the
highest deviation band. In these new
provisions, imbalance charges are based
on incremental cost and escalate as the
imbalance increases. Any deviations
from these provisions must be
consistent with or superior to the pro
forma OATT as modified by this Final
Rule and must meet the following
criteria: the charges must (1) Be related
to the cost of correcting the imbalance,
(2) be tailored to encourage accurate
scheduling behavior, such as by
increasing the percentage of the adder as
the deviations become larger, and (3)
account for the special circumstances
presented by intermittent generators,
such as by waiving the higher ends of
the deviation penalties.
• Capacity Reassignment Pricing. We
find that the existing cap on the
reassignment of point-to-point service is
no longer just and reasonable and,
therefore, we eliminate the cap. We
believe that removing the cap will
eliminate an unnecessary impediment
to the resale of capacity, which in turn
should increase utilization of the grid
and otherwise ensure that point-to-point
service is just, reasonable, and not
unduly discriminatory.
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• Crediting of Customer-Owned
Facilities. We retain most elements of
our existing policy respecting the
crediting of customer-owned facilities,
including the requirement that such
facilities meet the integration standard.
However, we eliminate the requirement
that new facilities can receive credits
only if they are ‘‘jointly planned’’
because this requirement provides a
disincentive to coordinated planning.
Rather, we provide that such new
facilities are eligible for credits if such
facilities are integrated into the
operations of the transmission
provider’s facilities. Customer-owned
facilities shall be presumed to be
integrated if those facilities, if owned by
the transmission provider, would be
eligible for inclusion in the transmission
provider’s annual transmission revenue
requirement.
86. Improvements to Point-to-Point
Service. The Commission concludes that
the existing methods for evaluating
requests for long-term firm point-topoint service are no longer just,
reasonable, and not unduly
discriminatory. The existing pro forma
OATT allows the transmission provider
to deny a request for long-term point-topoint service if that service is not
available in a single hour of the period
studied. We find that this approach is
not comparable because, when a
transmission provider considers a new
resource to serve native load, the
transmission provider does not
eliminate an otherwise economic option
because the resource may not be
deliverable in a few hours of the year.
To remedy this problem, the
Commission adopts a ‘‘conditional
firm’’ component to long-term point-topoint service that addresses the
situation where firm service can be
provided for most, but not all, hours of
the period requested. We also reform the
existing requirements for the provision
of redispatch service to ensure that they
are of greater use to transmission
customers and more consistent with
reliability planning and operation of the
system.
87. Reform of rollover rights. The
Commission concludes that section 2.2
of the pro forma OATT, which grants an
ongoing right to transmission customers
to renew or ‘‘roll over’’ their contracts,
should be reformed. The current
rollover rights do not provide
consistency between the rights of
rollover customers and the resulting
obligations of transmission providers to
plan and upgrade the system to
accommodate rollovers. The
Commission therefore amends section
2.2 to ensure greater consistency with
transmission planning and construction
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timelines and modifies the minimum
term of the rollover rights to five years,
rather than the current minimum term
of one year. The Commission also
requires that a transmission customer
eligible for rollover rights provide notice
of whether or not it will exercise its
right of first refusal to renew the
contract no less than one year before the
expiration date of the transmission
service agreement, rather than within
the current 60-day period.
88. Increases in transparency to
lessen the opportunities to discriminate
and reduce transaction costs. In
addition to the increased transparency
we require regarding the calculation of
ATC and transmission planning, we
increase the transparency of
transmission service provided under the
pro forma OATT in several other
respects. For example, we require
transmission providers and their
network customers to use the
transmission providers’ OASIS to
request designation of a new network
resource and to terminate the
designation of an existing network
resource. In addition, we require
transmission providers to modify their
OASIS so that requests to designate and
terminate a network resource can be
queried, allowing all parties access to
such information. We also require
transmission providers to post a list of
their current designated network
resources and all network customers’
current designated network resources on
their OASIS. Finally, we require
transmission providers to post on
OASIS all their business rules, practices
and standards that relate to transmission
services provided under the pro forma
OATT.
89. Strengthening enforcement of the
pro forma OATT. The reforms adopted
in this Final Rule provide greater clarity
in the terms and conditions of the pro
forma OATT, resolving ambiguities in
the existing pro forma OATT that have
made undue discrimination easier to
accomplish and more difficult to detect.
Our new civil penalty authority under
EPAct 2005 gives us ample power to
remedy tariff violations, but it also
places upon us an increased
responsibility to make the rules as clear
as possible. We fulfill that responsibility
in the Final Rule by providing greater
clarity where appropriate to several
critical OATT provisions. We also adopt
a number of posting and reporting
requirements that will provide the
Commission and market participants
with information about each
transmission provider’s performance of
pro forma OATT obligations. For
example, we require transmission
providers to post specific performance
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metrics related to their completion of
studies required under the pro forma
OATT. We note that the Commission
will continue to audit compliance with
the pro forma OATT, and toward that
end require transmission information
kept on OASIS to be retained for audit
purposes for five years. Finally, we
adopt a number of reforms to
operational penalties assessed under the
pro forma OATT, including so-called
‘‘over-use’’ penalties and the treatment
of operational penalty revenues
collected from transmission providers
and their affiliates.
90. Miscellaneous OATT
improvements. Finally, we implement a
number of improvements to the terms
and conditions of the pro forma OATT
to incorporate the lessons learned over
the past ten years. We briefly note these
below:
• Designation of network resources.
We provide clarification regarding the
types of agreements that may be
designated as network resources, the
process for verifying whether
agreements meet the requirements in the
pro forma OATT, and the requirement
for transmission providers to designate
and undesignate network resources. We
also require customers to submit an
attestation with each application to
designate a new network resource.
• Reservation priorities. We change
the priority rules to give certain priority
to pre-confirmed transmission service
requests submitted in the same time
period. We also add price as a tiebreaker in determining reservation
queue priority when the transmission
provider is willing to discount
transmission service.
• Clarifications related to network
service. We provide clarification related
to use of network service on an ‘‘as
available basis’’ and to ‘‘redirects’’ of
network service.
B. Core Elements of Order No. 888 That
Are Retained
91. Although we are adopting many
important reforms to Order No. 888 and
the pro forma OATT in this Final Rule,
we emphasize that many of the core
elements of Order No. 888 are retained.
As the Commission noted in the NOPR,
many of these core elements enjoy broad
support from many sectors of the
industry. A variety of commenters—in
response to the NOI issued earlier in
this proceeding and again in response to
the NOPR—have urged the Commission
to focus on meaningful incremental
reforms to the pro forma OATT, rather
than on industry restructuring. We share
the view that Order No. 888 can be
strengthened without discarding its
fundamental structure. We discuss
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below the core elements that are being
retained and the comments received on
these points.
1. Federal/State Jurisdiction
92. In Order No. 888, the Commission
stated that it has exclusive jurisdiction
over the rates, terms, and conditions of
unbundled retail transmission in
interstate commerce.76 Though the
Commission adopted a test for
determining what constitute
Commission-jurisdictional transmission
facilities and what constitute Statejurisdictional local distribution facilities
in situations involving unbundled
wholesale wheeling and unbundled
retail wheeling,77 the Commission
stated that it generally would defer to
determinations by State regulatory
authorities concerning where to draw
the jurisdictional line under that test.78
The Commission declined to assert
jurisdiction over bundled retail
transmission, reasoning that ‘‘when
transmission is sold at retail as part and
parcel of the delivered product called
electric energy, the transaction is a sale
of electric energy at retail.’’ 79 The U.S.
Supreme Court affirmed the
Commission’s decision to assert
jurisdiction over unbundled but not
bundled retail transmission, finding that
the Commission made a statutorily
permissible choice.80 In the NOPR, the
Commission proposed to retain the
jurisdictional divide established in
Order No. 888.
Comments
93. Several commenters support the
Commission’s proposal to retain the
existing jurisdictional divide.81 Though
APPA concludes that the most politic
course at this juncture is to leave the
current jurisdictional boundaries in
place and develop cooperative
mechanisms in each region to
coordinate Federal policy
implementation with the relevant State
regulators, APPA notes that there is
disagreement among its members about
whether the current jurisdictional lines
are properly drawn. APPA explains that
a substantial number of its members
believe that all interstate transmission
services (both retail and wholesale)
should be provided under one
consistent set of tariff terms and
conditions. Other APPA members,
however, believe that the Commission
made the proper jurisdictional call in
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76 Order
No. 888 at 31,781.
at 31,771 (setting forth the seven-factor test).
78 Id. at 31,781.
79 Id.
80 See New York v. FERC, 535 U.S. at 28.
81 E.g., Ameren, APPA, North Carolina
Commission Reply, PNM–TNMP, and Southern.
Order No. 888. NARUC urges the
Commission to clarify that its planning
proposals will not reopen or attempt to
change the jurisdictional split over
transmission facilities delineated in
Order No. 888.
Commission Determination
94. The Commission will retain the
existing jurisdictional divide that was
established in Order No. 888, which has
been affirmed by the U.S. Supreme
Court and accepted by the industry and
State regulatory authorities.82 We also
reiterate our recognition of the need for
heightened cooperation between Federal
and State regulators in areas where there
are overlapping Federal and State policy
concerns. As explained in greater detail
in the planning section below, and in
response to NARUC’s concern, the
planning reforms adopted in the Final
Rule contemplate coordinated and open
transmission planning, but do not
reopen or otherwise change the existing
jurisdictional divide for transmission
facilities.
2. Native Load Protection
95. In Order No. 888, the Commission
did not require transmission providers
to unbundle transmission service to
their retail native load. The Commission
also did not require that bundled retail
service be taken under the terms of the
pro forma OATT.83 Moreover, the
Commission allowed a transmission
provider to reserve, in its calculation of
ATC, transmission capacity necessary to
accommodate native load growth
reasonably forecasted in its planning
horizon.84 Order No. 888 also granted a
rollover right to existing firm service
customers,85 but allowed transmission
providers to restrict that rollover right if
the capacity was reasonably forecasted
as needed to serve native load
customers, as long as that restriction
was set forth in the customer’s initial
service contract.86
96. Congress, in section 1233 of EPAct
2005, added section 217 to the FPA,
entitled ‘‘Native Load Service
Obligation,’’ which addresses
transmission rights held by load-serving
entities (LSEs). FPA section 217 allows
LSEs to use their own and contractedfor transmission capacity to deliver
energy as required to meet their service
obligations, without being subject to
charges of unlawful discrimination. The
provision makes clear, however, that
this requirement does not abrogate any
77 Id.
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82 See
New York v. FERC, 535 U.S. at 28.
No. 888 at 31,745.
84 Id. at 31,694.
85 Id.; see pro forma OATT section 2.2.
86 Order No. 888–A at 30,198.
83 Order
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contract or service agreement for firm
transmission service or rights in effect
as of the date of enactment of EPAct
2005.87 In the NOPR, the Commission
concluded that the protection of native
load embodied in Order No. 888 is
consistent with FPA section 217, and
reaffirmed its commitment to the
protection of native load.
Comments
97. Several commenters agree with
the Commission’s preliminary
conclusion that the protection of native
load embodied in Order No. 888 is
consistent with FPA section 217 and
support the Commission’s continued
commitment to the protection of native
load.88 While APPA 89 and TAPS
generally agree with the Commission
that the overall OATT regime is
consistent with section 217, they urge
the Commission to maintain and
reinforce the comparability requirement.
APPA urges the Commission to broaden
its preliminary conclusion in the NOPR
and conclude instead that the protection
of native load and the provision of fully
comparable transmission service to
other LSEs with long-term service
obligations, as embodied in Order No.
888, are consistent with FPA section
217. TAPS also supports the
Commission’s reading of FPA section
217 as consistent with the Order No.
888 pro forma OATT’s ‘‘native load’’
priority, recognizing that FPA section
217 reinforces the OATT’s commitment
to comparable treatment of all LSEs—
e.g., transmission providers and
network customers.
98. Other commenters dispute the
Commission’s preliminary conclusion
that the native load protection
embodied in Order No. 888 is consistent
with FPA section 217.90 Many
commenters argue that FPA section 217
protects all load, not just native load.91
Constellation states that the
Commission must recognize that there
are other market participants besides the
transmission providers themselves that
are LSEs under FPA section 217. Under
the definition of LSEs in FPA section
87 16
U.S.C. 217(f).
Ameren, E.ON, Tacoma, Arkansas
Commission, EPSA, Southern, and TAPS.
89 APPA argues that the proposed definition of
native load customers in section 1.21 is not
technically consistent with FPA section 217
because FPA section 217 does not distinguish
among the types of power supply arrangements that
an LSE must have to enjoy the protection of FPA
section 217. Nevertheless, APPA states that it
would not be fruitful to reopen the entire OATT
framework to address this technical (but very
important) definitional difference.
90 E.g., Arkansas Municipal, Constellation, Duke,
Salt River, and South Carolina E&G.
91 E.g., Constellation, EPSA, and South Carolina
E&G.
88 E.g.,
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217, EPSA argues that many entities
other than traditional, verticallyintegrated utilities are in the business of
serving load. The statute, EPSA asserts,
applies to any native load service
obligation, whether that obligation is
served by a competitive supplier, an
affiliate of the transmission provider, or
by the transmission provider itself. Salt
River contends that FPA section 217 is
self-implementing, though it urges the
Commission to act to remove
impediments to the full exercise of
rights granted to LSEs.
99. Constellation argues that the
Commission should require native load
and OATT customers to take service
under the same terms and conditions
because experience has proven that
discrimination has occurred as a result
of having two different sets of rules
applicable to transmission customers.
EPSA urges the Commission to further
clarify that the transmission provider
has an affirmative obligation to serve
native load in a non-discriminatory
manner. According to EPSA, section 217
supports the Commission’s paramount
statutory mission of ensuring nondiscrimination and makes clear that a
transmission provider, when utilizing
transmission capacity or rights reserved
to serve native load, must ‘‘put its
blinders on’’ to ensure that the load’s
needs are being met in the most
economical way available, whether that
decision means the deployment of its
own affiliated generation, or the
deployment of available non-utility
alternatives.
100. Arkansas Municipal asserts that
FPA section 217 recognizes the need to
give priority to LSEs in certain
situations, such as when the
transmission grid may be constrained
and one group of customers may be
denied service at the expense of other
customers. Arkansas Municipal states
that a priority list could be instituted in
this reform proceeding that places LSEs
at the top of the list in competing
requests for transmission service when
not all requests could be granted or
honored by the transmission provider.
101. New Mexico Attorney General
argues that native load is fundamentally
different than merchant load and
therefore, in the planning process, the
needs of merchants should not be
treated comparably with the needs of
New Mexico utilities’ native loads. New
Mexico Attorney General asserts that
New Mexico utilities have a statutory
obligation to serve retail load while
merchants are free to come and go with
cycles inherent in wholesale markets.
According to New Mexico Attorney
General, the transmission requirements
of the utilities’ native loads amount to
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an ongoing long-term firm contract,
while the transmission needs of
merchants are, by comparison, shortterm and speculative.
102. Several commenters urge the
Commission to revisit various aspects of
the reforms proposed in the NOPR in
order to enhance the protection of
native load. For example, some
commenters urge the Commission to
modify the rollover proposal in the
NOPR. Salt River argues that the
Commission’s regulations must include
a clear provision for a transmission
owner anticipating, or unexpectedly
facing, load growth to recapture
capacity temporarily made available to
the wholesale market. Arkansas
Commission disagrees with the
Commission’s proposal to require a
transmission provider to compete for
transmission capacity rather than
reclaim it through its rights to reserve
capacity for future load growth. The
proposal is inequitable, Arkansas
Commission argues, because native load
customers have historically paid for
most of the transmission providers’
assets and will continue to do so in the
future. Because of this, Arkansas
Commission asserts, native load
customers should be given preference in
the reservation of transmission capacity.
In response to Arkansas Commission’s
position, MDEA urges the Commission
to make clear, consistent with the
comparability principle adopted in
Order No. 888 and reaffirmed in the
NOPR, and with FPA section 217, that
any reservation of rights or preference
available to a transmission provider’s
native load customers must be available
to network customer loads as well.
South Carolina E&G argues that the
Commission’s interpretation of
‘‘reasonably forecasted’’ capacity under
section 2.2 of the pro forma OATT has
been effectively impossible to meet and,
therefore, the Commission should now
provide clear standards for evaluation of
native load protecting rollover
restrictions. A clear standard, South
Carolina E&G states, would have the
Commission consider rollover
restrictions in light of a utility’s
transmission planning process. On
reply, Progress Energy supports South
Carolina E&G’s comments. Progress
Energy urges the Commission to revisit
the rollover rights policy to develop a
policy by which an LSE may be assured
of future transmission service for
reasonably forecasted native load
growth.
103. South Carolina E&G also asks the
Commission to revise section 13.6 of the
pro forma OATT, regarding curtailment
of firm point-to-point transmission
service. South Carolina E&G urges the
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Commission to comply with the
mandate of Northern States Power Co. v.
FERC,92 which South Carolina E&G
asserts held that the Commission had
exceeded its authority in rejecting a
vertically-integrated transmission
provider’s proposal to modify section
13.6 of the OATT to give a higher
curtailment priority to native load.
According to South Carolina E&G, the
Commission has responded by applying
the court’s decision narrowly, but FPA
section 217 requires the Commission to
change that position and recognize the
primacy of service to native load in
section 13.6 of the OATT. In its reply
comments, Progress Energy supports the
comments of South Carolina E&G and
states that the Commission must
affirmatively recognize the priority of
service to LSEs in the application of the
curtailment priorities in section 13.6 of
the OATT.
104. Duke argues that several of the
Commission’s proposed reforms—such
as hourly firm service, redispatch, and
conditional firm service—actually
reduce the protection afforded native/
network load. Salt River suggests that
the Commission should modify its ATC
proposal to bring the Commission’s
native load priority policies in line with
FPA section 217. Salt River asserts that,
in calculating ATC, the transmission
provider must be able to exercise
reasonable professional judgment as to
the amount of transmission that must be
reserved to meet native load service
obligations; the Commission should not
get into the business of dictating
forecasting methodology. Salt River
proposes that a native load forecast that
is used by an LSE as the basis for
committing capital for generation
expansion or procurement should be
presumed to be valid for purposes of
establishing available capacity. EPSA,
however, argues that, unless and until
the Commission mandates a hard and
enforceable definition of ATC,
transmission-owning utilities that also
own affiliated generation will continue
to hide behind the native load service
obligation as an excuse for being unable
to find ATC for any but self-serving
purposes.
105. EPSA also argues that the
Commission must ensure that
transmission owners’ planning
accommodates all supply options. EPSA
urges the Commission to clarify that
transmission capacity reserved for
native load is to be made available
(including for study and other purposes)
to competitive suppliers who wish to
92 176 F.3d 1090, 1096 (8th Cir. 1999), cert.
denied sub nom. Enron Power Marketing, Inc. v.
Northern States Power Co., 528 U.S. 1182 (2000).
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serve native load as allowed by State
law. According to EPSA, all generation
assets ultimately serve load and the pro
forma OATT should be clarified to
ensure that the transmission system is
available on a non-discriminatory basis
now and in the future to ensure that
load is optimally served—regardless of
which generation resources are serving
that load. In its reply comments, EPSA
also challenges the initial comments of
New Mexico Attorney General, which
EPSA argues incorrectly interpret FPA
section 217 as drawing a distinction
between the types of generation that
serve load. EPSA argues that the statute
protects the customer load that all
suppliers would seek to serve regardless
of the source.
106. APPA agrees with the
Commission’s response in the NOPR to
Metropolitan Water District that the
specific issues related to an RTO’s
provision of long-term transmission
rights are better left to the rulemaking in
Docket Nos. RM06–8–000 and AD05–7–
000, and the proceedings in each RTO
region to implement the Final Rule
issued in those dockets on July 20, 2006.
APPA notes, however, that the
Commission has not proposed in this
docket to exempt RTOs from the
provisions of the NOPR. Rather, APPA
notes, departures from the pro forma
OATT, including departures in RTO
OATTs, must be justified under the
‘‘consistent with or superior to’’
standard. APPA argues that the
Commission should apply this standard
to long-term transmission rights, as well
as to the other terms and conditions of
OATT transmission service that RTOs
provide.
Commission Determination
107. In Order No. 888, the
Commission gave public utilities the
right to reserve existing transmission
capacity needed for native load growth
reasonably forecasted within the
utility’s current planning horizon. The
Commission also allowed transmission
providers to restrict rollover rights
based on reasonably forecasted need at
the time the contract is executed. We
continue to believe these protections for
native load are appropriate and do not
eliminate them in this Final Rule, as
suggested by some commenters. We also
believe that the protection of native load
embodied in Order No. 888, as
enhanced by the reforms adopted in this
Final Rule, is consistent with FPA
section 217, which protects the
transmission rights of entities with
service obligations to end-users or a
distribution utility, to the extent
required to meet their service
obligations. The additional reforms
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proposed by commenters are not
necessary at this time to remedy undue
discrimination. We conclude that the
native load priority established in Order
No. 888 continues to strike the
appropriate balance between the
transmission provider’s need to meet its
native load obligations and the need of
other entities to obtain service from the
transmission provider to meet their own
obligations.
108. In response to comments
regarding reforms needed to ATC
calculation and transmission planning
to bring the native load priority policies
in line with FPA section 217, we believe
that the Commission’s reforms in this
Final Rule appropriately reflect the
transmission provider’s obligation to
serve native load. As discussed more
fully in the ATC and planning sections
below, the processes we adopt herein
are open, transparent and nondiscriminatory and assume that the
transmission provider is meeting its
obligations, including its native load
service obligation. We disagree with
Duke’s assertion that the reforms
proposed in the NOPR will result in a
reduction of the protection afforded
native or network load. Not only have
we reaffirmed the fundamental
protections for native load contained in
Order No. 888, but we have modified,
where appropriate, the pro forma OATT
to ensure that a transmission provider’s
obligations can be met consistent with
maintaining the reliability to existing
customers, including native load. For
example, we are eliminating the current
requirement to provide planning
redispatch over long periods of time
(e.g., 10–30 years) because it is
unnecessary to remedy undue
discrimination and can create problems
in forecasting system conditions
consistent with maintaining reliability
to native load customers.93
109. With regard to APPA’s comments
regarding long-term transmission rights
in organized markets, we note that the
Commission has issued its Final Rule in
Docket Nos. RM06–8–000 and AD05–7–
000.94 As discussed more fully in the
applicability section of this rulemaking,
and in response to APPA’s comments,
we reiterate that any departures from
the pro forma OATT proposed by an
ISO or an RTO must be ‘‘consistent with
or superior to’’ the pro forma OATT in
this Final Rule.
93 Proposals related to other reforms, such as
curtailments and rollovers, are discussed in the
sections below dealing with each of those issues.
94 See supra note 72.
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3. The Types of Transmission Services
Offered
110. In Order No. 888, the
Commission required all public utilities
to offer, on a non-discriminatory, openaccess basis, firm network service and
firm and non-firm point-to-point
service. In the NOPR, the Commission
proposed to retain these services and
did not propose to require transmission
providers to adopt a network contract
demand service, either as a replacement
for network or point-to-point service or
as a third category of service under the
OATT.
Comments
111. Several commenters support the
Commission’s proposal to retain the
current services in the pro forma OATT
and to not adopt contract demand
service.95 While APPA supports the
Commission’s proposal, it states that the
Commission should remain open to
individual public utility transmission
provider’s proposals to add ‘‘hybrid’’
service to the base network and pointto-point services.
112. Other commenters, such as AMPOhio and Nevada Companies, argue that
the Commission should require all
transmission providers to offer network
contract demand service. Nevada
Companies argue that the Commission’s
network designation process can
substantially interfere with State
jurisdiction over resource acquisition,
especially for transmission providers
that are required to purchase substantial
amounts of power to serve their retail
customers instead of relying primarily
on their own generation. Nevada
Companies reason that allowing
transmission providers to move to a
contract demand-based network service
would remove them from the dilemma
of being forced to make resource
procurement decisions that are
inconsistent with State requirements.
On reply, MidAmerican, Newmont
Mining, and Utah Municipals oppose
the suggestion that the contract demand
service should be made a mandatory
service offering in the pro forma OATT.
In its reply comments, Newmont Mining
states that, if the Commission is
inclined to provide some relief to allow
Nevada Companies to comply with both
the pro forma OATT and their Stateapproved resource plans, that relief
should come only after an investigation
of how similar problems are handled on
other systems and should be a narrowly
and carefully monitored exception to
the resource designation requirements.
95 E.g.,
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113. Alberta Intervenors argue that
undue discrimination is most likely to
occur in situations where there is a
single or dominant network customer
and that customer either has a dual
mandate for serving the network
customers or that customer has a ‘‘free
option’’ for procuring transmission.96
Alberta Intervenors recommend that the
Commission implement standardized
rules with respect to the ‘‘free option’’
concept while offering regional
flexibility to ensure the objectives of
open access and the absence of undue
discrimination continue to be advanced.
Alberta Intervenors also argue that,
despite the Commission’s proposal to
address undue discrimination against
transmission customers in attempting to
redirect to new receipt and delivery
points, undue discrimination remains a
concern since network customers retain
a flexibility of receipt and delivery
points that is not granted to third party
point-to-point customers. This
flexibility provided to the network
customer allows the use of the system
for activities known as ‘‘parking’’ 97 and
‘‘hubbing.’’ 98 Alberta Intervenors urge
the Commission to eliminate this unfair
competitive advantage under the OATT
by making a common service available
to all participants rather than differing
service for network customers, or
alternatively, by restricting the use of
96 Alberta Intervenors assert that the purchase of
point-to-point service by dominant network
customers results in an equal and offsetting
reduction to the network customer’s network
charges, resulting in a net cost of zero. They state
that point-to-point service is a net cost to all
competitors except the dominant network customer.
Thus, they argue, a dominant network customer can
buy point-to-point service for an extended period
and use this service for a limited number of hours
at little (or no) net cost compared to not purchasing
point-to-point service for an extended period. In
Alberta Intervenors’ view, this ‘‘free option’’
provides network customers with a competitive
advantage when reserving point-to-point service
because it enables the network customers to overconsume or buy excess point-to-point service than
they would if the true net cost were reflected.
Alberta Intervenors contend that such overconsumption reduces access to point-to-point
service for other customers.
97 Alberta Intervenors define ‘‘parking’’ as a
network customer reserving point-to-point service
using a network load point of delivery to purchase
energy that it intends to sell but where no buyer has
been identified at the time of the reservation. The
energy notionally reduces network load. Once a
buyer is found, the network customer completes the
sale by delivering the energy from freed-up
generation at a generation point of receipt to a
buyer’s point of delivery.
98 Alberta Intervenors define ‘‘hubbing’’ as a
practice very similar to ‘‘parking,’’ but involving
multiple buyers and sellers. The network customer
can reserve point-to-point transmission to purchase
energy from multiple sellers and to sell energy to
multiple buyers by creating a hub within its
network load. Alberta Intervenors explain that this
allows the network customer to organize purchases
and sales by physically matching the requirements
of multiple buyers and sellers.
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point-to-point services by the network
customer to exclude its use for
‘‘parking’’ and ‘‘hubbing.’’
114. MidAmerican states that in the
Western Interconnection, a utility’s
loads are not necessarily located within
a confined geographical boundary
served by a single transmission owner.
In these cases, MidAmerican argues,
neither network nor point-to-point
service under the current pro forma
OATT is suitable to serve those loads.
To remedy these shortcomings in
standard OATT service, MidAmerican
states that the Commission should
require the incorporation of dynamic
scheduling and long-term, seasonallyshaped, firm point-to-point as new
service offerings under the pro forma
OATT.
Commission Determination
115. The Commission will not alter
the types of services that we required in
Order No. 888. We continue to believe
that network and point-to-point services
are the appropriate base-line service
offerings in the OATT, and we will not
mandate that transmission providers
adopt new service offerings such as
network contract demand service.
Although the Commission has accepted
forms of network contract demand
service proposed by individual
transmission providers, and the service
may provide benefits to certain
customers, we do not believe the service
is necessary to remedy undue
discrimination. For example, the service
would require a departure from full
load-ratio pricing for network
customers, which may not be warranted
to the extent the transmission provider
plans its system to serve all native load.
However, while the Commission
concludes that it will not require all
transmission providers to offer this
service, in response to the arguments
raised by commenters such as AMPOhio and Nevada Companies, we
reiterate that the Commission already
has accepted forms of network contract
demand service and will continue to
entertain such proposals on a voluntary
basis from transmission providers.
116. The Commission also is not
persuaded by Alberta Intervenors’ and
MidAmerican’s arguments in support of
further alternative services under the
pro forma OATT. As with network
contract demand service, transmission
providers may propose such services if
appropriate for their region. We do not
believe mandating that such services be
provided by all transmission providers
is necessary at this time to prevent
undue discrimination.
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4. Functional Unbundling
117. In Order No. 888, the
Commission chose to mandate
functional, rather than corporate (in
which a public utility’s transmission
and generation assets would be placed
in separate corporate entities),
unbundling of transmission and
generation services. The Commission
explained that functional unbundling
has three components:
1. A public utility must take
transmission services (including
ancillary services) for all of its new
wholesale sales and purchases of energy
under the same tariff of general
applicability as do others;
2. A public utility must state separate
rates for wholesale generation,
transmission, and ancillary services;
3. A public utility must rely on the
same electronic information network
that its transmission customers rely on
to obtain information about its
transmission system when buying or
selling power.99
118. In the years following Order No.
888, a number of public utilities
nonetheless underwent corporate
unbundling. Many of these entities did
so as a result of State-mandated
restructuring laws. Others did so for
corporate or tax reasons. Some entities
divested all of their generation assets to
a non-affiliate, while others simply
restructured internally to place the
generation assets in a different corporate
subsidiary than the transmission assets.
There remain, however, a significant
number of vertically-integrated public
utilities that operate under the
functional unbundling approach.
119. In the NOPR, we proposed to
preserve the functional unbundling
approach adopted in Order No. 888,
rather than impose a corporate or
structural unbundling requirement.
While the Commission expressed its
continued support for voluntary efforts
to adopt structural changes (such as
transmission-only companies, RTOs, or
other reforms), the Commission found
that the more intrusive and costly
corporate unbundling was not necessary
at this time. The Commission also
declined to mandate an independent
transmission coordinator for all
transmission providers. Though the
Commission has previously found that
such entities may be appropriate in
certain circumstances and we support
voluntary efforts to rely on them,100 the
99 Order
No. 888 at 31,654.
Duke Power, 113 FERC ¶ 61,288 (2005);
MidAmerican Energy Co., 113 FERC ¶ 61,274
(2005); see also Entergy Services, Inc., 110 FERC
61,295 (2005), order on clarification, 111 FERC
¶ 61,222 (2005), order conditionally approving
filing, 115 FERC ¶ 61,095 (2006).
100 See
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Commission concluded that there was
not a sufficient basis for requiring them
as a generic remedy for undue
discrimination.
Comments
120. Commenters generally support
the Commission’s proposal to retain
functional unbundling.101 APPA also
supports the Commission’s decision not
to mandate an independent
transmission coordinator for all public
utility transmission providers.
Similarly, Tacoma supports the
Commission’s decision to continue to
view participation in an RTO or ISO as
voluntary actions. While PJM and EPSA
would prefer a structural remedy, they
generally support the Commission’s
proposal to retain functional
unbundling. However, EPSA states that
given the Commission’s proposal to
continue to rely on functional
unbundling, it is critical, particularly in
those areas without organized markets,
that OATT rules regarding unbundled
transmission service be clear,
transparent, consistent, and rigorously
enforced. APPA states that it will be
vital to obtain the cooperation of State
regulators in each region where the
OATT reforms will be implemented to
ensure that the current functional
unbundling regime in fact is sufficient
to do the job.
121. E.ON and TVA express concern
that the Commission may yet choose a
structural remedy. E.ON urges the
Commission to look at the full depth
and breadth of its existing powers to
monitor and fully redress any abuses in
the allocation of transmission services
before considering structural
unbundling. Similarly, TVA notes that
the Commission already has the option
to impose a structural remedy on a caseby-case basis.102
Commission Determination
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122. The Commission will, as
proposed in the NOPR, continue to
require functional—rather than
corporate or structural—unbundling. As
explained in the NOPR, for public
utilities that keep transmission and
generation assets in the same corporate
entity, the Commission has strict
Standards of Conduct that require the
separation of the utilities’ transmission
system operations and wholesale
101 E.g., Santee Cooper, LPPC, TVA, Tacoma,
Southern, MISO Transmission Owners, and E.ON.
102 Some commenters argue that adoption of the
‘‘open dispatch’’ proposals raised by commenters
such as Chandley-Hogan and PJM would constitute
a departure from functional unbundling. We
discuss the ‘‘open dispatch’’ and similar proposals
in section V.C below.
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marketing functions.103 These rules
require that employees engaged in
transmission functions operate
separately from employees of energy
affiliates and marketing affiliates. A
number of information sharing
restrictions also apply, which prohibit
transmission providers from allowing
employees of their energy and
marketing affiliates to obtain access to
transmission or customer information,
except via OASIS.
123. The Commission aggressively
enforces the Standards of Conduct and,
as referenced by APPA, cooperates with
State regulators to ensure that the
functional unbundling regime is
sufficient to prevent undue
discrimination. The Commission’s
Office of Enforcement is well-suited to
investigate potential violations of the
Standards of Conduct and to propose
remedies, including structural remedies
if necessary, to ensure that the
separation of functions and information
restrictions are fully implemented. We
believe that the increased clarity and
transparency adopted in other parts of
this Final Rule, when coupled with the
Standards of Conduct rules and our
rigorous enforcement program, will
ensure that the functional unbundling
requirement will serve its original
purpose.
C. Applicability of the Final Rule
1. Non-ISO/RTO Public Utility
Transmission Providers
124. In the NOPR, the Commission
proposed to apply the Final Rule to all
public utility transmission providers,
including those that are approved ISOs
and RTOs. With respect to non-ISO/
RTO transmission providers, the
Commission proposed to require all
103 The rules were first established in Order No.
889. See Order No. 889 at 31,595. The Standards
of Conduct rules were later replaced by a broader
set of rules adopted in Order No. 2004, which were
subsequently vacated in part by the United States
Court of Appeals pending remand proceedings
before the Commission. See Standards of Conduct
for Transmission Providers, Order No. 2004, 68 FR
69134 (Dec. 11, 2003), FERC Stats. & Regs. ¶ 31,155
(2003), order on reh’g, Order No. 2004–A, 69 FR
23562 (Apr. 29, 2004), FERC Stats. & Regs. ¶ 31,161
(2004), order on reh’g, Order No. 2004–B, 69 FR
48371 (Aug. 10, 2004), FERC Stats. & Regs. ¶ 31,166
(2004), order on reh’g, Order No. 2004–C, 70 FR 284
(Jan. 4, 2005), FERC Stats. & Regs. ¶ 31,172 (2005),
order on reh’g, Order No. 2004–D, 110 FERC
¶ 61,320 (2005), vacated, National Fuel, 468 F.3d
831. The Commission has issued an interim rule
promulgating temporary regulations consistent with
the Court’s decision and initiated a further
rulemaking to propose permanent regulations. See
Standards of Conduct for Transmission Providers,
Order No. 690, 72 FR 2427 (Jan. 19, 2007), FERC
Stats. & Regs. ¶ 31,327 (2007); Standards of Conduct
for Transmission Providers, Notice of Proposed
Rulemaking, 72 FR 3958 (Jan. 29, 2007), FERC Stats.
& Regs. ¶ 32,611 (2007) (Standards of Conduct
NOPR).
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such transmission providers to submit
FPA section 206 compliance filings,
within 60 days after the publication of
the Final Rule in the Federal Register,
that contain the non-rate terms and
conditions set forth in the Final Rule.
The Commission also acknowledged
that certain non-rate terms and
conditions, such as Attachment C
(relating to the transmission provider’s
ATC calculation methodology) and
Attachment K (relating to the
transmission provider’s transmission
planning process), may require more
than 60 days to prepare and sought
comment on an appropriate time period
in which to require the submission of
these attachments.
125. Following their FPA section 206
compliance filings, the Commission
proposed that transmission providers
could submit filings under FPA section
205 proposing rates for the services
provided for in the tariff, as well as nonrate terms and conditions that differ
from those set forth in the Final Rule if
those provisions are ‘‘consistent with or
superior to’’ the pro forma OATT.
Comments
126. Several commenters ask the
Commission to clarify and/or revise the
proposal for dealing with previouslyapproved provisions that depart from
the existing (Order No. 888) pro forma
OATT. APPA contends that after this
multi-phase rulemaking (NOI/NOPR/
Final Rule) to revise the OATT, the
Commission should hold those public
utility transmission providers that
propose non-rate terms and conditions
differing from the new pro forma OATT
to a high standard of proof under the
‘‘consistent with or superior to’’
standard. According to APPA, any nonrate term and condition that differs from
the revised pro forma OATT should be
‘‘additive’’ in nature (for example, a new
service offering, such as network
contract demand service) or should
propose substantive improvements in
transmission service to customers.
APPA argues that a public utility
transmission provider should not be
able to make an FPA section 206
compliance filing to implement the pro
forma OATT and then ‘‘water down’’ its
new OATT through an FPA section 205
filing that degrades its transmission
service offerings or diminishes the
quality of that service.
127. In its reply comments, APPA
recommends that the Commission
require non-ISO/RTO transmission
providers to file the new pro forma
OATT set out in the Final Rule and add
in redline—either in that filing, or a
companion one—all previously
approved transmission provider-specific
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provisions. APPA states that
transmission providers should then
explain whether they propose to include
these provisions in their revised OATTs,
why they propose to retain or delete
these provisions, and whether they
believe these provisions are ‘‘affected by
the revisions adopted in the Final
Rule.’’
128. In contrast, Duke and EEI ask the
Commission to clarify that transmission
providers with previously-approved
departures from the OATT that are not
related to the reforms adopted in this
Final Rule will not be required to
rejustify these provisions in their FPA
section 206 compliance filings. They
also ask that transmission providers not
be required first to adopt all of the
provisions of the revised pro forma
OATT and then make an FPA section
205 filing to refile a departure
previously approved by the
Commission. They recommend that
existing, approved departures from the
pro forma OATT that are not affected in
a substantive way by the changes to the
pro forma OATT should be included in
the initial FPA section 206 filing.104 On
reply, Indianapolis Power agrees with
Duke and EEI and urges the Commission
to consider the unwieldy and cost
prohibitive nature of a process that
would require transmission providers to
demonstrate that previously-accepted
elements of their OATTs are acceptable.
129. Duke and EEI, in their reply
comments, argue that APPA’s approach
would be inefficient and would cause a
substantial disruption to transmission
service because both transmission
providers and transmission customers
would be required to abandon tariff
provisions that the Commission has
previously found to be consistent with
or superior to the pro forma OATT and
that are regularly being used. For
example, Duke notes, Duke Carolina has
an Attachment K that covers the
Independent Entity that will oversee the
provision of transmission service by
Duke. Duke asserts that a literal
interpretation of the NOPR proposal
would mean that it would have to delete
this attachment and replace its entire
OATT with the revised pro forma OATT
and then refile its entire Independent
Entity proposal with its FPA section 205
filing. Similarly, Entergy states that it
currently has a pro forma Generator
Imbalance Agreement in place that was
agreed to by the IPPs on its system and
accepted by the Commission. Entergy
urges the Commission to permit
104 Duke and EEI propose that a utility would
redline its compliance filing OATT against the
revised pro forma OATT so that the Commission
can readily identify the ‘‘already-approved’’
differences.
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transmission providers to propose their
own imbalance pricing methodology as
long as the proposed generator
imbalance charges are consistent with or
superior to the generator imbalance
provisions ultimately adopted in the
OATT.
130. On reply, NRECA opposes EEI’s
compliance proposal. NRECA states that
the Commission should retain the twophased compliance procedure proposed
in the NOPR because it strikes a fair
balance by providing transmission
providers the opportunity to suggest
changes to their pro forma OATTs
under FPA section 205, while allowing
transmission customers and others the
opportunity to argue that the deviations
from the new pro forma OATT are
neither consistent with nor superior to
the pro forma OATT.
131. NRECA acknowledges that there
will be a burden on the transmission
provider to prepare a compliance filing;
however, it urges the Commission to
retain its proposal and require
transmission providers to identify those
terms and conditions that differ from
the pro forma OATT. NRECA agrees
that, if a term or condition unrelated to
any modification of the pro forma
OATT in the instant rulemaking has
already been found to be consistent with
or superior to the existing Order No. 888
pro forma OATT, it likely continues to
be consistent with or superior to the
revised pro forma OATT term or
condition. NRECA argues, however, that
a public utility transmission provider
should still be required in a compliance
filing to identify these deviations from
the revised pro forma OATT and,
ultimately, to justify them in the event
that they are fairly contested. Otherwise,
NRECA contends, the Commission and
industry lose the consistency and
related advantages the pro forma OATT
seeks to provide.
132. Several commenters addressed
the deadlines proposed in the NOPR.
APPA suggests that the Commission set
a 60 or 90-day deadline for those
provisions the transmission provider
can complete itself and a 120 or 180-day
deadline for those provisions and
attachments that will require the
transmission provider to incorporate
regional practices and protocols, such as
Attachments C and K. Tacoma proposes
180 days for transmission providers to
submit Attachments C and K. PGP
recommends that transmission
providers be given one year to file
Attachment K.
133. EEI and National Grid urge the
Commission to align the compliance
filing deadlines for ISOs and RTOs and
their transmission-owning members in
order to eliminate any potential
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Fmt 4701
Sfmt 4700
confusion and to enhance coordination
within the ISOs and RTOs. To the extent
that public utility transmission owners
whose transmission facilities are under
the control of RTOs and ISOs have filing
rights under the RTO or ISO tariffs, EEI
asks that such public utility
transmission owners be required to
submit any necessary tariff filings
within 90 days after the effective date of
the Final Rule, rather than the currentlyproposed 60 days. National Grid
suggests that the Commission establish
a single deadline for ISOs/RTOs and
their transmission-owning members, set
at six months from the date of
publication of the Final Rule.
134. TDU Systems recommend that
the Commission adopt a staggered filing
approach for the compliance filings (i.e.,
have transmission providers come in at
different times based on criteria chosen
by the Commission, such as
alphabetically or by size). TDU Systems
argue that this would ensure that
transmission customers are not forced to
review all of their transmission
providers’ filings at the same time.
Commission Determination
135. The Commission adopts the twotiered implementation process proposed
in the NOPR, with certain clarifications
and modifications, as discussed below.
As the Commission proposed in the
NOPR, all transmission providers that
have not been approved as ISOs or
RTOs, and whose transmission facilities
are not under the control of an ISO or
RTO, are required to submit FPA section
206 compliance filings that contain the
revised non-rate terms and conditions
set forth in the Final Rule, within 60
days after the publication of the Final
Rule in the Federal Register.105
However, this filing only need to
contain the revised provisions adopted
in the Final Rule, rather than the
transmission provider’s entire pro forma
OATT.106 After the submission of their
105 The Commission clarifies that existing waivers
of the obligation to file an OATT or otherwise offer
open access transmission service in accordance
with Order No. 888 shall remain in place. The
reforms to the pro forma OATT adopted in this
Final Rule therefore do not apply to transmission
providers with such waivers, although we expect
those transmission providers to participate in the
regional planning processes in place in their
regions, as discussed in more detail in section V.B.
Whether an existing waiver of OATT requirements
should be revoked will be considered on a case-bycase basis in light of the circumstances surrounding
the particular transmission provider.
106 As explained below, the Commission is not
requiring transmission providers to submit in their
compliance filing tariff sheets associated with
provisions of the pro forma OATT that have not
been modified in this proceeding. To the extent,
however, a transmission provider desires to refile
its entire OATT in order to simplify pagination or
other tariff designation issues associated with
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FPA section 206 compliance filings,
these transmission providers may
submit FPA section 205 filings
proposing rates for the services
provided for in the tariff, as well as nonrate terms and conditions that differ
from those set forth in the Final Rule if
those provisions are ‘‘consistent with or
superior to’’ the pro forma OATT.
136. The Commission recognizes that,
since the issuance of Order No. 888,
some non-ISO/RTO transmission
providers have received approval from
the Commission to adopt variations
from the non-rate terms and conditions
of the pro forma OATT that are
consistent with or superior to the Order
No. 888 pro forma OATT. Under the
compliance procedure adopted above,
those variations that are not affected in
a substantive manner by the reforms to
the pro forma OATT adopted in this
Final Rule may remain in place. We
disagree with the implementation
procedures proposed by APPA, which
would require non-ISO/RTO
transmission providers with provisions
in their OATTs that depart from the pro
forma OATT, but which are not
substantively affected by the reforms in
this NOPR, to make a filing that
explains whether and why they would
retain or delete these provisions. We see
no need to require non-ISO/RTO
transmission providers to ‘‘rejustify’’
such provisions if they are not
substantively affected by the reforms in
this Final Rule, given that the
Commission has already found these
provisions to be consistent with or
superior to terms and conditions set
forth in the pro forma OATT that
remain unchanged, and the Commission
has not otherwise found these
provisions to be unjust and
unreasonable.
137. In other circumstances, however,
non-ISO/RTO transmission providers
may have provisions in their existing
OATTs that the Commission deemed to
be consistent with or superior to terms
and conditions of the Order No. 888 pro
forma OATT that are being modified by
the Final Rule. Such transmission
providers must demonstrate that these
previously-approved variations
continue to be consistent with or
superior to the pro forma OATT as
modified by the Final Rule. We
continue to believe that use of the
‘‘consistent with or superior to’’
implementing the modifications required under the
Final Rule, it may do so. We note that such a filing
is a compliance filing and, therefore, the only
deviations in this filing should be the revised
provisions in this Final Rule. If a transmission
provider wishes to propose different terms and
conditions, it must make a separate FPA section 205
filing.
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standard is appropriate when reviewing
variations from the pro forma OATT
and reject APPA’s proposal to adopt a
higher burden of proof.
138. The two-tiered compliance
process adopted above will allow
transmission providers with previouslyapproved variations an opportunity to
show that their existing deviations
continue to be consistent with or
superior to the pro forma OATT as
modified in the Final Rule. However,
the Commission recognizes that it may
cause disruption for some transmission
providers that wish to continue to rely
on previously-approved variations
during the compliance process. The
Commission therefore offers an optional
implementation process for non-ISO/
RTO transmission providers seeking
approval of previously-approved
variations.
139. Transmission providers that have
not been approved as ISOs or RTOs and
whose transmission facilities are not
under the control of an ISO or RTO may
submit an FPA section 205 filing, within
30 days after the publication of the Final
Rule in the Federal Register, seeking a
determination that a previouslyapproved variation from the Order No.
888 pro forma OATT that has been
substantively affected by the reforms
adopted in this Final Rule continues to
be consistent with or superior to the
revised pro forma OATT adopted
here.107 Each applicant should request
that the proposed tariff provisions be
made effective as of the date of the
transmission provider’s section 206
compliance filing, to be submitted
within 60 days after the publication of
the Final Rule in the Federal Register
(as provided above). As a condition of
that request, however, the transmission
provider should state that the
Commission has 90 days following the
date of submission of the filing to act
under section 205. In other words, the
Commission is offering this optional
implementation process to applicants
that allow the Commission 90 days to
act on the filing. This procedure will
streamline the compliance process by
allowing existing variations from terms
and conditions of the pro forma OATT
that have been modified by the Final
Rule to remain in effect until further
Commission action, while also
providing the Commission with
adequate time to act on the filings. The
subsequent section 206 compliance
filing would then contain tariff sheets
necessary to implement the remaining
107 Transmission providers must provide citations
to the Commission orders where the variation was
accepted by the Commission as consistent with or
superior to the pro forma OATT.
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12287
modifications required under the Final
Rule, i.e., modifications related to tariff
provisions that did not implicate
previously-approved variations.
140. As the Commission
acknowledged in the NOPR, certain
non-rate terms and conditions, such as
Attachment C (relating to the
transmission provider’s ATC calculation
methodology) and Attachment K
(relating to the transmission provider’s
transmission planning process) may
require more than 60 days to prepare.
Accordingly, we will require non-ISO/
RTO transmission providers to file their
Attachment C within 180 days after the
publication of the Final Rule in the
Federal Register and their -Attachment
K (or the transmission providers’
equivalent thereof) within 210 days after
the publication of the Final Rule in the
Federal Register. A summary of the
more significant filing requirements
established in this Final Rule is
provided in Appendix A.108
141. Other reforms adopted in the
Final Rule will involve coordination
with the North American Energy
Standards Board (NAESB) to establish
OASIS functionality or uniform
business practices. The Commission
requests that NAESB file a status report
within 90 days of publication of the
Final Rule in the Federal Register that
contains a work plan for development of
such OASIS functionality and business
practices. This work plan should
indicate, for each reform, what actions
are necessary and an estimate of the
timeframe for completing those actions.
Pending resolution of these issues with
NAESB, the Commission requires that
each transmission provider develop its
own OASIS functionality or business
practice necessary to implement each
such reform within 90 days of
publication of the Final Rule in the
Federal Register, unless a different
compliance requirement is otherwise
specified in this Final Rule. Upon
review of this work plan, the
Commission will issue an order
establishing further compliance
deadlines as necessary.
142. We are not persuaded to adopt a
staggered compliance filing approach in
this proceeding as TDU Systems
suggest. However, we will align the
compliance filing deadlines for ISOs
and RTOs and their transmission108 For further information related to the Final
Rule, such as electronic versions of the pro forma
OATT showing tariff changes adopted in the Final
Rule in redline/strikeout format, and further
information regarding docketing of compliance
filings and specific filing instructions, please visit
our Web site at the following location https://
www.ferc.gov/industries/electric/indus-act/oattreform.asp.
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owning members in order to eliminate
any potential confusion and to enhance
coordination within the ISOs and RTOs.
Thus, we will require public utility
transmission owners whose
transmission facilities are under the
control of RTOs and ISOs to make any
necessary tariff filings required to
comply with the Final Rule within 210
days after the publication of the Final
Rule in the Federal Register.
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2. ISO and RTO Public Utility
Transmission Providers and
Transmission Owner Members of ISOs
and RTOs
143. With respect to an ISO or RTO
public utility transmission provider, the
Commission recognized in the NOPR
that such an entity may already have
tariff terms and conditions that are
superior to the pro forma OATT. The
Commission also noted that the purpose
of this rulemaking is not to redesign
approved, fully-functioning RTO or ISO
markets. Thus, the Commission
proposed to require ISO and RTO
transmission providers to submit FPA
section 206 compliance filings, within
90 days after the publication of the Final
Rule in the Federal Register, that
contain the non-rate terms and
conditions set forth in the Final Rule or
that demonstrate that their existing tariff
provisions are consistent with or
superior to the revised provisions to the
pro forma OATT. The Commission also
proposed to allow ISO and RTO
transmission providers, after making
their FPA section 206 compliance
filings, to submit filings under FPA
section 205 proposing rates for the
services provided for in their tariffs, as
well as non-rate terms and conditions
that differ from their existing tariffs and
those set forth in the Final Rule if those
provisions are consistent with or
superior to the pro forma OATT. The
Commission did not address the specific
obligations of transmission owning
members of ISOs and RTOs.
Comments
144. Several commenters support
applying the revised pro forma OATT to
ISOs and RTOs and requiring ISOs and
RTOs to justify any variations
therefrom. MidAmerican argues that
universal application of the revised pro
forma OATT is important because not
every ISO or RTO transmission provider
has existing tariff terms and conditions
that are consistent with or superior to
the OATT. Old Dominion also supports
the Commission’s compliance proposals
for ISOs and RTOs. NRECA similarly
states that RTOs, ISOs and ITCs should
not be automatically exempt from any
aspect of the rules governing open
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access transmission service, including
the planning requirements. APPA
asserts that in their filings, RTOs should
be required to show how their
transmission service packages,
including features such as long term
transmission rights, ancillary services,
and treatment of losses, are consistent
with or superior to the newly revised
pro forma OATT. Moreover, APPA
argues, the Commission should not
allow RTOs to use their avowed
independence as a justification for
transmission services that in fact do not
meet the consistent with or superior to
standard.109
145. On the other hand, numerous
commenters argue that the proposed
compliance process is burdensome and
could require ISOs and RTOs to have to
relitigate already-approved OATT
provisions. The ISOs and RTOs
generally argue that, given the nature of
the services they offer, many of the
proposed revisions do not apply to their
OATTs. Many commenters urge the
Commission to adopt a more limited
compliance filing process. Some
commenters, for example, argue that the
Commission should only require ISOs
and RTOs to submit compliance filings
that are limited to the specific pro forma
tariff revisions set forth in the Final
Rule. Duke argues that ISOs and RTOs
should only be required to make a single
filing that revises their OATTs in a
manner that takes into account the
nature of the OATT service provided by
that ISO or RTO and whether a reform
adopted in the Final Rule is relevant to
the ISO’s or RTO’s OATT. EEI urges the
Commission to require ISOs and RTOs
to adopt only those OATT reforms that
are necessary to improve the quality of
transmission service that is provided by
an ISO or RTO. EEI adds that those who
protest an ISO’s or RTO’s assertion that
an existing provision is consistent with
or superior to the revised pro forma
OATT should have the burden to
demonstrate otherwise. The ISOs and
RTOs similarly argue that, absent a
specific demonstration that an ISO’s or
RTO’s OATT provisions are unjust and
unreasonable, the compliance filing
requirements should not apply to ISOs
and RTOs.
146. EEI urges the Commission to
clarify that the 90-day filing should
include the following materials:
Revisions of tariff provisions that
conform to the revisions in the pro
forma OATT that are appropriate, given
the ISO or RTO’s market structure;
statements supporting the provisions of
the tariff that the ISO or RTO believes
are consistent with or superior to the
109 See
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Frm 00024
Fmt 4701
Sfmt 4700
revised pro forma OATT; and
justifications that support excluding
revisions of the provisions that the ISO
or RTO believes are not consistent with
or superior to the revised pro forma
OATT. EEI also interprets the NOPR
proposal to mean that an ISO or RTO
immediately may make a separate filing
proposing further modifications,
including revisions to the newlyeffective provisions of the pro forma
OATT, that are consistent with or
superior to the just-filed modifications.
147. SPP urges the Commission to
affirm that ISOs and RTOs will not be
required to rejustify their previouslyapproved non-pro forma tariff
provisions, but rather only the new or
revised tariff provisions expressly
prescribed in the Final Rule. In its reply
comments, SPP notes that the terms and
conditions of its OATT are interrelated
and work together to achieve a system
of administration that fosters open and
transparent transmission service and
function as an integrated whole.
Therefore, SPP asserts, the modification
of one provision of its OATT will
impact several other provisions and the
process of rejustifying one aspect of the
tariff likewise will implicate other terms
and conditions.
148. Indianapolis Power argues that
tariff changes resulting from this
rulemaking should be included only
with the support of the ISO and RTO
members who bear the costs and are in
the best position to judge the benefits.
149. On reply, ISO/RTO Council
generally argues that there is no factual
or legal support for the ISO/RTO
compliance procedures advocated by
commenters such as APPA. ISO/RTO
Council states that the OATTs of ISOs
and RTOs were developed through
extensive stakeholder procedures and
subject to the Commission’s filing,
notice, comment, and approval
processes under FPA section 205. ISO/
RTO Council asserts that to adopt the
post-hoc, open-ended review advocated
by these parties would give disgruntled
participants a ‘‘second bite’’ at legally
effective OATT terms and would
undermine the very stakeholder and
regulatory processes by which ISOs and
RTOs were established. MISO in
particular argues that APPA’s proposal
ignores that ISO and RTO tariffs have
already been determined to be just and
reasonable and consistent with or
superior to the Order No. 888 pro forma
OATT, is profoundly inconsistent with
the Commission’s policy of encouraging
RTOs as an option to ensure nondiscriminatory open access transmission
service, and is impracticable unless the
intent is to grind RTO markets to a halt.
MISO states that each RTO tariff has
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dozens, or perhaps hundreds, of
Commission-approved deviations and,
in its view, reopening these issues
would not be in the public interest and
would consume enormous resources of
both the RTOs and the Commission.
150. Southern, in its reply comments,
argues that ISOs and RTOs are
essentially requesting to be exempted
from the requirements of this
proceeding. Southern states that all
transmission service revisions/reforms
adopted in this proceeding should apply
uniformly to all transmission providers,
including ISOs and RTOs. Southern
contends that ISOs and RTOs are
increasingly subject to complaints
alleging discriminatory treatment and
asserts that the highly partisan attacks
made by several RTOs against verticallyintegrated utilities further calls into
question whether ISOs and RTOs are
not susceptible to taking discriminatory
actions. In addition, Southern argues,
such exemptions would likely result in
seams issues.
151. Some commenters state that the
Commission should identify the specific
reforms it will apply to RTOs and ISOs
and provide more general guidance as to
how it intends to apply the consistent
with or superior to standard to ISO/RTO
tariff provisions. National Grid asserts
that the Commission properly identified
these provisions in the NOPR when the
Commission concluded that there may
be elements of the proposed reforms
that are superior to what currently exist
in some RTOs or ISOs, e.g.,
transparency, data exchange, or
planning. MISO/PJM States identify six
areas as potentially applicable to RTOs:
Hourly firm transmission service;
obligation to expand capacity; joint
ownership; reservation priority;
ancillary services; and pro forma OATT
definitions. MISO/PJM States also
identify eleven areas as not applicable
to RTOs: Undue discrimination
generally; transmission pricing;
remedies, penalties and enforcement;
changes in receipt and delivery points
(redirects); rollover rights; rules,
standards and practices governing the
provision of transmission service; joint
transmission planning; tariff compliance
review; hoarding of transmission
capacity; curtailments; and ancillary
services. APPA, in its reply comments,
opposes granting a blanket exemption
for ISOs and RTOs from any portion of
the compliance filing requirement.
152. CAISO urges the Commission to
clarify how it should provide for
changes in the Final Rule to
transmission services that it does not
provide or which are clearly
incompatible with the transmission
service model it employs. In their reply
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comments, CMUA and APPA oppose
this request for clarification. CMUA
argues that CAISO’s failure to provide
any long-term transmission service
renders its transmission service
markedly inferior to the firm
transmission service under the pro
forma OATT. CMUA maintains that,
instead of affirmatively embracing its
obligation to show that its transmission
service offering, once supplemented
with long-term transmission rights that
fully comply with all seven guidelines
set out in Order No. 681, will meet the
‘‘consistent with or superior to’’
standard of Order No. 888, CAISO
instead asks to be exempted from any
such requirement.
153. Xcel and Indicated New York
Transmission Owners assert that the
Commission should allow regional
variations to the extent that ISOs/RTOs
can demonstrate that their OATT
provisions meet the objectives of the
Final Rule. Xcel argues that the
consistent with or superior to standard
may be too narrow because some
changes to the OATT made by ISOs/
RTOs are not as much ‘‘superior’’ or
‘‘consistent with,’’ as they are simply
necessary because the tariff is regional.
Indicated New York Transmission
Owners argue that the Commission
should not impose a consistent with or
superior to standard generally reserved
for transmission providers that are not
members of an ISO/RTO. Indicated New
York Transmission Owners assert that,
to the extent that certain improvements
could or should be made to the ISO/
RTO OATTs, the Final Rule should
permit the necessary flexibility for each
ISO/RTO to propose and adopt such
changes through their stakeholder
governance processes, in order to
address the unique market features and
circumstances of each region.
154. PJM urges the Commission to
include an ‘‘independent entity
variation’’ standard similar to that used
in Order No. 2003, which permitted an
RTO to adopt interconnection
procedures that are responsive to
specific regional needs. NRECA
responds that the Commission should
not entertain PJM’s request. While PJM’s
requested standard may have made
sense in the context of generator
interconnections, NRECA contends that
it is inapposite to reform of the OATT.
NRECA states that ISOs and RTOs
should not be allowed to keep on file
tariff provisions that possess the
potential to allow for undue
discrimination, even if the entity
publishing the tariff is ostensibly
independent of market participants and
even if the proposed reforms do not
directly improve the ‘‘quality of’’
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12289
transmission service, since the purpose
of this rulemaking is to prevent undue
discrimination in the provision of
transmission service.
155. To whatever extent the
Commission elects to exempt RTOs and
ISOs from certain aspects of the pro
forma OATT, E.ON asserts that the same
consideration should be given to
utilities that have entered into
arrangements with alternative,
Commission-approved, independent
transmission organizations. In their
reply comments, TDU Systems oppose
this proposal arguing that these
alternative constructs may not meet the
independence criteria of Order Nos. 888
and 2000.
156. Several commenters urge the
Commission to extend the proposed 90day deadline for ISOs and RTOs to
submit their compliance filings. EEI
recommends that the Commission
clarify that it will grant an extension of
time if the stakeholder process prevents
an ISO or RTO from obtaining
stakeholder approval of tariff changes
within the 90-day deadline. SPP
requests a minimum of 120 days for
compliance. National Grid and MISO (in
its reply comments) propose that the
Commission establish a single deadline
for ISOs/RTOs and their transmissionowning members set at six months from
the date of publication of the Final Rule.
Commission Determination
157. The Commission adopts the
compliance procedures proposed in the
NOPR, with certain revisions and
clarifications. We will require ISO and
RTO transmission providers to submit
FPA section 206 compliance filings,
within 210 days after the publication of
the Final Rule in the Federal Register,
that contain the non-rate terms and
conditions set forth in the Final Rule or
that demonstrate that their existing tariff
provisions are consistent with or
superior to the revised provisions of the
pro forma OATT. As with non-ISO/RTO
transmission providers, however, we
will not require ISO and RTO
transmission providers to ‘‘rejustify’’
existing provisions in their OATTs that
are not affected in a substantive manner
by the revisions to the pro forma OATT
in the Final Rule. As we explained
above, we find that such a process is
unnecessary, given that we have already
found these provisions to be consistent
with or superior to the Order No. 888
pro forma OATT and these provisions
are not substantively affected by the
reforms we adopt today.
158. We also recognize, as we did in
the NOPR, that some of the changes
adopted in the Final Rule may not be as
relevant to ISO/RTO transmission
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providers as they are to nonindependent transmission providers.
For example, many ISOs and RTOs use
bid-based locational markets and
financial rights to address transmission
congestion, rather than the first-come,
first-served physical rights model set
forth in the pro forma OATT. As we
indicated in the NOPR, nothing in this
rulemaking is intended to upset the
market designs used by existing ISOs
and RTOs. We also recognize that ISOs
and RTOs may well have adopted
practices that are already consistent
with or superior to the reforms adopted
here. For example, ISOs and RTOs tend
to have transmission planning processes
that are significantly more open and
transparent than the processes used by
non-independent transmission
providers. We encourage ISOs and RTOs
to meet with their stakeholders to
discuss whether any improvements are
necessary to comply with the Final
Rule.
159. We reject Indianapolis Power’s
proposal to require tariff changes
resulting from this rulemaking only
with the support of the ISO and RTO
members who may bear the costs
associated with the revision.
Indianapolis Power effectively asks that
we allow ISO and RTO members to veto
our decisions here, which is contrary to
our duty to prevent undue
discrimination in the provision of
transmission service.
160. Regarding CAISO’s request for
clarification of how it should address
changes in the Final Rule to
transmission services that it does not
provide or which are incompatible with
its service model, we reiterate that
CAISO—like any other ISO or RTO—has
the opportunity to demonstrate that a
variation from the tariff revisions
adopted in the Final Rule satisfies the
consistent with or superior to standard.
We do not believe that the adoption of
an ‘‘independent entity variation,’’
proposed by PJM, or a regional variation
standard, proposed by Xcel and
Indicated New York Transmission
Owners, would be appropriate. Again,
the Commission finds that the reforms
adopted in this Final Rule are necessary
to prevent undue discrimination in the
provision of transmission service and
any transmission provider, including an
ISO or RTO, must demonstrate that
variations from the tariff modifications
required here satisfy the consistent with
or superior to standard.
161. As discussed above, however, we
will align the compliance filing
deadlines for ISOs and RTOs and their
transmission-owning members and
require public utility transmission
owners whose transmission facilities are
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under the control of RTOs or ISOs to
make any necessary tariff filings
required to comply with the Final Rule
within 210 days after the publication of
the Final Rule in the Federal Register.
A summary of the more significant filing
requirements established in this Final
Rule is provided in Appendix A.110
3. Non-Public Utility Transmission
Providers/Reciprocity
162. In Order No. 888, the
Commission conditioned non-public
utilities’ use of public utility open
access services on an agreement to offer
comparable transmission services in
return.111 The Commission found that,
while it did not have the authority to
require non-public utilities to make
their systems generally available, it did
have the ability and the obligation to
ensure that open access transmission is
as widely available as possible and that
Order No. 888 did not result in a
competitive disadvantage to public
utilities.
163. Under the reciprocity provision
in section 6 of the pro forma OATT, if
a public utility seeks transmission
service from a non-public utility to
which it provides open access
transmission service, the non-public
utility that owns, controls, or operates
transmission facilities must provide
comparable transmission service that it
is capable of providing on its own
system. Under the pro forma OATT, a
public utility may refuse to provide
open access transmission service to a
non-public utility if the non-public
utility refuses to reciprocate. A nonpublic utility may satisfy the reciprocity
condition in one of three ways. First, it
may provide service under a tariff that
has been approved by the Commission
under the voluntary ‘‘safe harbor’’
provision. A non-public utility using
this alternative submits a reciprocity
tariff to the Commission seeking a
declaratory order that the proposed
reciprocity tariff substantially conforms
to, or is superior to, the pro forma
OATT. The non-public utility then must
offer service under its reciprocity tariff
to any public utility whose transmission
service the non-public utility seeks to
use. Second, the non-public utility may
provide service to a public utility under
110 For further information related to the Final
Rule, such as electronic versions of the pro forma
OATT showing tariff changes adopted in the Final
Rule in redline/strikeout format, and further
information regarding docketing of compliance
filings and specific filing instructions, please visit
our Web site at the following location https://
www.ferc.gov/industries/electric/indus-act/oattreform.asp.
111 These entities are not FPA public utilities and
therefore are not subject to the Commission’s
jurisdiction under sections 205 and 206 of the FPA.
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a bilateral agreement that satisfies its
reciprocity obligation. Finally, the nonpublic utility may seek a waiver of the
reciprocity condition from the public
utility.112
164. In EPAct 2005, Congress
authorized, but did not require, the
Commission to order non-public
utilities (or ‘‘unregulated transmitting
utilities’’) to provide transmission
services under a new section 211A in
Part II of the FPA. This section states in
part that the Commission ‘‘may, by rule
or order, require an unregulated
transmitting utility to provide
transmission services’’ at rates that are
comparable to those it charges itself and
under terms and conditions (unrelated
to rates) that are comparable to those it
applies to itself, and that are not unduly
discriminatory or preferential. The
language does not limit the Commission
to ordering transmission services only to
the public utility from whom the nonpublic utility takes transmission
services, but rather permits the
Commission to order the non-public
utility to provide ‘‘open access’’
transmission service, i.e., service to all
eligible customers.
165. In the NOPR, the Commission
proposed to retain the current
reciprocity language in the pro forma
OATT, as well as Order No. 888’s three
alternative provisions for satisfying the
reciprocity condition, i.e.: A non-public
utility that owns, controls, or operates
transmission and seeks transmission
service from a public utility must either
satisfy its reciprocity obligation under a
bilateral agreement, seek a waiver of the
OATT reciprocity condition from the
public utility, or file a safe harbor tariff
with the Commission.113
166. The Commission did not propose
a generic rule to implement the new
FPA section 211A.114 Rather, the
Commission proposed to apply its
provisions on a case-by-case basis, such
as when a public utility seeks service
112 See
Order No. 888–A at 30,285–86.
non-public utilities that choose to use the
safe harbor tariff, the Commission noted in the
NOPR that the existing safe harbor provisions
would need to be substantially conforming or
superior to the new pro forma OATT. A non-public
utility that already has a safe harbor tariff would
therefore be required to amend its tariff so that its
provisions substantially conform or are superior to
the new pro forma OATT if it wishes to continue
to qualify for safe harbor treatment. As the
Commission stated in Order No. 888–A, a nonpublic utility may limit the use of its voluntarily
offered safe harbor reciprocity tariff only to those
transmission providers from whom the non-public
utility obtains open access service, as long as the
tariff otherwise substantially conforms to the pro
forma OATT. See Order No. 888–A at 30,289.
114 The Commission noted in the NOPR that LPPC
has committed to voluntary compliance with a set
of guidelines for the provision of comparable
service under FPA section 211A.
113 For
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from an unregulated transmitting utility
that has not requested service under the
public utility’s OATT and the
reciprocity obligation therefore does not
apply. The Commission stated that such
a customer may file an application with
the Commission seeking an order
compelling the unregulated transmitting
utility to provide transmission service
that meets the standards of FPA section
211A. The Commission further
proposed to amend its regulations to
make clear that an applicant in an FPA
section 211A proceeding against a nonpublic utility that has submitted an
acceptable safe harbor tariff has the
burden of proof to show why service
under the safe harbor tariff is not
sufficient and why an FPA section 211A
order should be granted. In addition, the
Commission stated in the NOPR its
expectation that unregulated
transmission providers would
participate in the proposed open and
transparent regional planning processes
and noted that, if there were complaints
about such participation, they would
also be addressed on a case-by-case
basis.
167. The NOPR proposed to retain the
existing reciprocity policy as applied to
foreign utilities doing business in the
United States, which we adopted
pursuant to sections 205 and 206 of the
FPA. By maintaining the same
reciprocity requirement for these foreign
utilities as for domestic, non-public
utilities, the Commission stated that it
would ensure that foreign entities will
continue to be treated no less favorably
than domestic, non-public utilities.
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Comments
168. The majority of the commenters
support the Commission’s decisions to
retain the reciprocity provision and to
adopt a case-by-case approach to FPA
section 211A.115 These commenters
reason that there is no evidence of a
general problem of non-public utilities
failing to provide transmission service
and that, for the most part, non-public
utilities already provide transmission on
an as-available basis under comparable
terms, regardless of whether a tariff is
on file with the Commission. In
addition, Santa Clara and TANC state
that the Commission’s proposal
apparently respects the
nonjurisdictional status of public
power.
169. LPPC reiterates its prior offer of
voluntary compliance with a set of
115 E.g., APPA, Bonneville, LPPC, Newfoundland,
NRECA, PGP, Sacramento, Salt River, Santa Clara,
Santee Cooper, Seattle, TANC, TAPS, TVA,
Tacoma, WAPA, CMUA Reply, East Texas
Cooperatives Reply, Lassen Reply, and Public
Power Council Reply.
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guidelines for the provision of
comparable open access service, which
it contends will provide a significant
degree of standardization for such
service. Thus, LPPC believes that
generic action under section 211A is not
necessary. In addition, LPPC asserts that
there is no evidence on record of undue
discrimination by a nonjurisdictional
entity that would justify the
Commission reversing the NOPR
decision to act on a case-by-case basis
under FPA section 211A.116
170. On the other hand, several
commenters urge the Commission to
implement FPA section 211A on a
generic basis.117 AWEA argues that
reciprocity tariffs do not subject the
nonpublic utilities to Commission
enforcement as would an OATT
established under FPA section 211A.
AWEA urges the Commission to
proceed on a generic basis to ensure that
nonjurisdictional utilities comply with
the reformed OATT under exactly the
same terms and conditions as
jurisdictional utilities. On reply,
however, APPA argues that the
comparability standard does not mean
that unregulated transmitting utilities
must comply with the reformed OATT
under exactly the same terms and
conditions as jurisdictional entities.
171. In its reply comments, EEI states
that, while LPPC’s voluntary proposal is
a step in the right direction, LPPC’s
proposal does not go far enough to
assure that reciprocal transmission
service is provided in a nondiscriminatory manner. EEI asserts that
LPPC’s proposal still gives the
individual non-public utility
transmission provider the discretion to
decide what is or is not comparable and
not unduly discriminatory. Moreover,
EEI notes, LPPC does not represent the
universe of non-public utility
transmission providers, rather only 24
of the largest governmentally-owned
transmission providers.
172. Some commenters argue that the
case-by-case approach proposed in the
NOPR does not satisfy the Commission’s
stated goal of remedying undue
discrimination and its intent to provide
transparent, consistent and clear rules
for use of the nation’s transmission
grid.118 Calpine contends that the
administrative burden of monitoring
and administering customer complaints
or processing applications that seek to
compel unregulated transmitting
utilities in different parts of the country
116 See also Public Power Council Reply and
Sacramento Reply.
117 E.g., AWEA, California Commission, Calpine,
EEI, MidAmerican, San Diego G&E, and Xcel.
118 E.g., Calpine, MidAmerican, and Xcel.
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12291
to provide comparable service would
create a ‘‘patchwork of open and
closed’’ unregulated transmitting
utilities, just like the patchwork of open
and closed jurisdictional transmission
systems the Commission sought to
eliminate when it issued Order No. 888.
Calpine also states that its comments on
the NOI in this proceeding provide
several examples of the kinds of
problems it has experienced in seeking
transmission service from unregulated
transmitting utilities in a variety of
regions and across multiple
transmission systems.
173. California Commission argues
that FPA section 211A gives the
Commission the authority to require
previously nonjurisdictional entities to
file tariffs with the Commission that
would be subject to the due process and
the ‘‘just and reasonable’’ requirements
of the FPA. California Commission
urges the Commission to actively
explore a set of mandatory actions that
the Commission may impose on
nonjurisdictional entities and states
that, if the Commission is reluctant to
do so in this proceeding, it should
initiate a new rulemaking to consider
such rules. California Commission
asserts that there are a number of sound
policy reasons for taking generic action
to address the mandate of FPA section
211A. First, it argues that Commission
action would prevent the balkanization
of the grid that can result if a
nonjurisdictional transmission owner
refuses to participate in an RTO or ISO
whose service area surrounds,
encompasses, or overlaps it. Second,
California Commission argues that
Congress has given the Commission
explicit authority to require previously
nonjurisdictional entities to provide
transmission service on a nonpreferential and non-discriminatory
basis. Finally, California Commission
asserts, the Commission would be able
to squarely address generic seams issues
created by the existence of control areas
operated by previously unregulated
transmission owners and the ability of
such entities to ‘‘free ride’’ on the
systems and open access requirements
of the jurisdictional entities.
174. In its reply comments, CMUA
contests California Commission’s
assertion that those outside CAISO
operations are ‘‘free riders.’’ CMUA
notes that its members post their excess
transmission capacity on wesTTrans (an
OASIS site serving the Western
Interconnection) thus making it
available to third parties, and that its
members outside the CAISO also pay a
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host of CAISO fees.119 CMUA states that
it does not contest that there are
‘‘seams’’ between organized markets and
neighbors, but it asserts that this docket
is not the place for this discussion and
FPA section 211A is not the remedy. In
its reply comments, APPA also urges the
Commission to reject California
Commission’s proposal. APPA argues
that section 211A was not intended, nor
could the Commission use it, to require
nonjurisdictional transmission
providers to participate in an RTO and,
therefore, California Commission’s
proposal exceeds the Commission’s
authority under section 211A.120
175. EPSA, in its reply comments,
disagrees with commenters who appear
to believe that nonjurisdictional
transmitting utilities will not have to
take any steps to comply with a final
order in this rulemaking. EPSA states
that its understanding is that the
Commission’s principle of reciprocity
would apply to any changes in the pro
forma OATT adopted in the Final Rule.
Accordingly, both jurisdictional and
nonjurisdictional transmitting utilities
that adopted the Order No. 888 pro
forma OATT would have to make
compliance filings. In addition, EPSA
argues that nonjurisdictional
transmitting utilities that previously
received an Order No. 888 waiver or
that wish to request such a waiver
should have an affirmative duty to file
a request for a waiver. In the event that
a nonjurisdictional entity wishes to file
a bilateral contract, EPSA contends that
it should be required to file a
‘‘reciprocity’’ contract pursuant to FPA
section 205. If a nonjurisdictional
transmitting utility does not adopt a
revised pro forma OATT as a ‘‘safe
harbor,’’ EPSA argues the Commission’s
standard of review should be whether
the nonjurisdictional transmitting
utility’s alternative tariff is ‘‘equal or
superior to’’ a revised pro forma OATT.
176. EPSA, in its reply comments,
supports implementing the rate
provisions of FPA section 211A in a
proceeding separate from this particular
proceeding. EPSA states that such a
proceeding could take a generic
approach, in that nonjurisdictional
transmitting utilities could be required
to set transmission rates for third-party
transmission services that are computed
using rate determinants that are
comparable to the determinants that the
non-public utility uses to calculate
transmission rates for its native load.
177. With regard to specific
reciprocity obligations, LPPC argues that
the Commission should revise section 6
119 See
also APPA Reply.
120 See also CMUA Reply and Santa Clara Reply.
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of the pro forma OATT to reflect the
comparability standards now contained
in FPA section 211A. LPPC states that,
with the implementation of FPA section
211A, it is appropriate to revise the pro
forma OATT language in order to reflect
the unregulated utility’s obligation ‘‘to
provide transmission service
comparable to the service the customer
provides itself’’ as the ‘‘quid pro quo’’
for receiving reciprocal service. LPPC
also argues that, with respect to the
existing safe harbor option, the
Commission should revise its test for
evaluating a safe harbor OATT from one
which asks whether the proposal is
equivalent or superior to the pro forma
OATT, to one which asks whether the
service provided under the proposed
OATT is comparable to the service that
the unregulated utility provides itself.
178. EPSA replies that LPPC’s
suggestion to revise the language of
section 6 ironically would require
nonjurisdictional transmitting utilities
to offer third party customers
transmission services that are
comparable to network transmission
service, which is a higher quality of
transmission service than the revised
OATT and which is unlikely to be
supported by nonjurisdictional
transmitting utilities. EPSA states that it
believes that FPA section 211A requires
a nonjurisdictional transmitting utility
to provide transmission service (at its
interfaces with jurisdictional public
utilities and internal sources) that is
comparable to the service it is taking at
interfaces or internal sources. EPSA
therefore argues that the appropriate
standard for determining whether a
nonjurisdictional transmitting utility’s
tariff is comparable is whether the
nonjurisdictional utility’s tariff is ‘‘equal
or superior’’ to the revised pro forma
OATT.
179. LPPC also argues that the two
categorical exemptions from FPA
section 211A articulated in FPA section
211A(c)(3) (based on size and the value
of the unregulated system to the
integrated grid) should not be exclusive.
Rather, LPPC contends that the two
exemptions should guide the
Commission in considering similar
requests for exemption. For example,
LPPC argues that relatively small
utilities, which nevertheless exceed an
express threshold, should be permitted
to demonstrate that their systems are
simply too small, and that their facilities
are not sufficiently strategic, to call for
full inclusion in the FPA section 211A
regime. Similarly, LPPC states that, in
certain public systems, only some
discrete portions of the system would
fairly be considered part of the
integrated system. In these cases as well,
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LPPC argues, it would make sense for
the Commission to entertain requests for
partial waiver.
180. If the Commission does not
reconsider its proposal not to act
generically under FPA section 211A,
EEI contends that there are other actions
the Commission should take. In order to
facilitate full compliance with the
reciprocity obligation, EEI urges the
Commission at least to clarify and
strengthen the obligations of non-public
utility transmission providers under the
reciprocity provision,121 exercise
oversight and monitor their compliance
with the reciprocity obligation, and
require them to provide greater
transparency of the transmission
services and the terms and conditions of
service they offer so that those seeking
transmission service under the
reciprocity provision are able to
determine whether they are complying
with their reciprocity obligation.
181. With respect to the reciprocity
provision in the pro forma OATT, EEI
requests that the Commission update it
by including reference to transmission
service by ISOs and RTOs. EEI asks that
the reciprocity provision be modified to
provide that, if an ISO or RTO is the
transmission provider, the reciprocity
obligation is owed to all members of the
ISO or RTO. EEI notes, however, that
even this action would not require nonpublic utility transmission providers to
provide transmission services to other
entities who are eligible customers
under the ISO or RTO OATT and who
are not transmission providers, such as
independent generators. EEI asserts that
non-public utility transmission
providers may discriminate against
certain transmission customers unless
the reciprocity obligation is expanded.
Sempra Global also asks the
Commission to clarify that the right to
seek transmission service from an
unregulated transmitting utility
pursuant to FPA section 211A is
available to any entity that qualifies as
an eligible customer under the
Commission’s pro forma OATT.
182. EEI acknowledges that the
Commission declined in Order No. 888–
A to expand the reciprocity provision
beyond the specific transmission
provider from which the transmission
customer takes service on the ground
that requiring ‘‘non-public utilities to
offer transmission service to entities
other than public utility transmission
providers increases the chances that
they could lose tax-exempt status.’’ 122
However, EEI states, in 2002, the
121 Xcel and MidAmerican support EEI’s proposal
on this issue.
122 Citing Order No. 888–A at 30,287.
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Department of the Treasury adopted
final regulations that in effect provide
that providing open access transmission
does not constitute private use.123
Therefore, EEI argues, this reason for
limiting the services provided under the
reciprocity obligation is no longer
applicable.124
183. Moreover, EEI argues, as
originally established in Order Nos. 888
and 888–A, the Commission stated that
it was ‘‘conditioning the use of public
utility open access tariffs, by all
customers including non-public
utilities, on an agreement to offer
comparable (not unduly discriminatory
services) in return.’’ 125 However, EEI
states, the reciprocity provision of the
pro forma OATT refers to ‘‘similar terms
and conditions’’ but does not make clear
what they should be ‘‘similar’’ to. EEI
argues that the term ‘‘similar’’ does not
necessarily encompass the requirement
that is part of comparability that the
services provided be ‘‘not unduly
discriminatory’’ as Order Nos. 888 and
888–A require. EEI proposes that the pro
forma OATT be amended to refer to
‘‘comparable terms and conditions’’
rather than ‘‘similar’’ to align it with
Order Nos. 888 and 888–A. Finally, EEI
also states that the Commission should
also reaffirm that the reciprocity
obligation is binding on Canadian
utilities.
184. On reply, APPA urges the
Commission to reject EEI’s proposed
expansion of the reciprocity provision.
APPA notes that EEI’s proposed
application of the reforms to all nonpublic utility transmission providers
would potentially include a broader
universe of public power entities than
those subject to FPA section 211A.
Moreover, APPA argues, many of the
goals that EEI claims it wishes to
accomplish would be accomplished
even if the Commission takes no action.
185. In its reply comments, the
Canadian Electricity Association urges
the Commission to reject EEI’s proposal
to strengthen the reciprocity obligation
so as to require the offering of
transmission service to all eligible
customers. The Canadian Electricity
Association argues that the effect of
EEI’s proposal would be to enable a
generator generating power in Canada to
obtain access on a Canadian utility’s
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123 Treas.
Reg. § 1.141–7(g).
124 EEI asserts that the Commission also has the
authority to make this change under FPA section
211A, which provides that the Commission may not
require a State or municipality to take action under
that section that would violate a private utility bond
rule. If a non-public utility transmission provider is
concerned about the impact on the tax-exempt
status of its bonds, EEI suggests that it could seek
a waiver from the Commission.
125 Citing Order No. 888–A at 30,285.
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transmission system, which is not the
situation under the current reciprocity
requirement. Consequently, the
Canadian Electricity Association asserts,
EEI’s proposal would allow the
Commission to fully impose open access
requirements in Canada and would
violate the principles of comity and
undermine Canadian jurisdictional
sovereignty.
186. The Canadian Electricity
Association also repeats its earlier
arguments made in response to the NOI
that, to the extent the Commission
adopts the comparability standard in
FPA section 211A for non-public
utilities, the Commission must apply
the same changes to Canadian utilities.
187. EEI also urges the Commission to
take certain steps to increase
transparency and accountability in
complying with the reciprocity
requirement.126 For example, EEI states,
the Commission could include on its
Web site a list of all non-public utility
transmission providers that have
Commission-approved safe harbor
reciprocity tariffs. According to EEI,
such a list of entities would facilitate
use of their transmission systems,
provide transparency, and provide
recognition to these entities for their
voluntary efforts in accomplishing these
goals.127
188. EEI requests that the Commission
also establish minimal transparency
requirements for non-public utility
transmission providers.128 EEI asserts
that the Commission has ample
authority under FPA section 211A and
under the reciprocity provision of the
126 According to EEI, the new authority granted to
the Commission under EPAct 2005 section 1281
(new FPA section 220) (Electricity Market
Transparency Rules), which applies to all ‘‘market
participants,’’ provides another basis for requiring
greater transparency under the pro forma OATT by
non-public utility transmission providers. EEI
argues that the Commission could rely on this new
authority to require greater transparency in
transmission service provided under the reciprocity
obligation.
127 EEI notes that, in the NOPR, the Commission
referenced voluntary guidelines being developed by
members of the LPPC. EEI believes this is a step in
the right direction and looks forward to the
opportunity to provide input on the proposed
guidelines. In EEI’s view, however, if any LPPC
member wishes to use these guidelines as a safe
harbor tariff, it must meet the safe harbor standard
that the terms of service must be ‘‘substantially
conforming or superior to’’ the revised OATT. The
reciprocity obligation requires that the terms and
conditions of service be comparable to those that
the non-public utility transmission provider applies
to itself and not be unduly discriminatory.
128 EEI states that this informational filing should
include information such as: whether or not they
have a reciprocity or other tariff and how it can be
obtained, whether they have an OASIS and location
URL, whether they have standards of conduct and
where they are posted, whether they have posted
business practices, their contact for regional
transmission planning, and their ATC methodology.
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12293
pro forma tariff to apply this
information reporting requirement to
those large non-public utility
transmission providers that are not
exempted by section 211A(c).129
189. On reply, several commenters
oppose EEI’s transparency proposal.
Among other things, they argue that
EEI’s proposal is unnecessary and
duplicative of information that is
already publicly available—e.g., the
non-public utility’s Web site, the
Commission’s Web site, or in some
instances a regional entity’s Web site
(such as the wesTTrans OASIS).130
APPA further notes that LPPC has
proposed that the terms and conditions
in non-public utility transmission
provider’s tariffs would be publicly
available on the individual utility’s or a
regional entity’s Web site. In addition,
NRECA asserts that, absent waivers, any
non-public utility transmission provider
that has adopted a ‘‘safe-harbor’’ tariff
has adopted all of the OATT, OASIS,
and Standards of Conduct requirements
that apply to public utilities. NRECA
and TANC both assert that the
Commission does not have similar
informational filing requirements for
public utilities. Furthermore, TANC
argues that it would be a waste of
Commission resources to compile a list
of all non-public utility transmission
providers that have Commissionapproved safe harbor tariffs. TANC also
argues that to provide such an
information filing would be unduly
burdensome and a waste of
nonjurisdictional utility transmission
provider time and limited resources.
Commission Determination
190. The Commission retains the
reciprocity language in the Order No.
888 pro forma OATT, but updates it to
include references to ISOs and RTOs, as
suggested by EEI. We also modify the
reciprocity provision to provide that, if
an ISO or RTO is the transmission
provider, the reciprocity obligation is
owed to all members of that ISO or RTO.
We concur with EEI’s assessment that
such modifications will more accurately
reflect the current state of the industry.
However, we will not adopt EEI’s
proposal to extend the reciprocity
obligation to all eligible customers or
129 Section 211A authorizes the Commission to
require certain unregulated transmitting utilities to
provide transmission services at rates that are
comparable to those that the unregulated
transmitting utilities charges itself and on terms and
conditions (not related to rates) that are comparable
to those under which the unregulated transmitting
utility provides transmission services to itself and
that are not unduly discriminatory or preferential.
130 E.g., APPA Reply, CMUA Reply, LPPC Reply,
Lassen Reply, NRECA Reply, Sacramento Reply,
and TANC Reply.
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LPPC’s proposal to revise the pro forma
OATT language regarding
comparability. We are not persuaded
that either proposal is necessary at this
time to prevent undue discrimination
absent a complaint.
191. We will also retain Order No.
888’s three alternative provisions for
satisfying the reciprocity condition, i.e.:
A non-public utility that owns, controls,
or operates transmission and seeks
transmission service from a public
utility must either satisfy its reciprocity
obligation under a bilateral agreement,
seek a waiver of the OATT reciprocity
condition from the public utility, or file
a safe harbor tariff with the
Commission. Thus, for non-public
utilities that choose to use the safe
harbor tariff, its provisions must be
substantially conforming or superior to
the revised pro forma OATT in this
Final Rule. A non-public utility that
already has a safe harbor tariff must
amend its tariff so that its provisions
substantially conform or are superior to
the revised pro forma OATT if it wishes
to continue to qualify for safe harbor
treatment. As the Commission stated in
Order No. 888–A, a non-public utility
may limit the use of its voluntarily
offered safe harbor reciprocity tariff only
to those transmission providers from
whom the non-public utility obtains
open access service, as long as the tariff
otherwise substantially conforms to the
pro forma OATT.131 We reiterate that
these reciprocity requirements apply
equally to all non-public utility
transmission providers, including those
located in foreign countries.
192. As the Commission proposed in
the NOPR, we will not adopt a generic
rule to implement the new FPA section
211A. Rather, we will apply its
provisions on a case-by-case basis, such
as when a public utility seeks service
from an unregulated transmitting utility
that has not requested service under the
public utility’s OATT and the
reciprocity obligation therefore does not
apply. A potential customer may file an
application with the Commission
seeking an order compelling the
unregulated transmitting utility to
provide transmission service that meets
the standards of FPA section 211A. We
adopt the NOPR proposal to amend our
regulations to make clear that an
applicant in an FPA section 211A
proceeding against a non-public utility
that has submitted an acceptable safe
harbor tariff shall have the burden of
proof to show why service under the
safe harbor tariff is not sufficient and
why an FPA section 211A order should
131 See
Order No. 888–A at 30,289.
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be granted.132 Further, as we indicate
below, we restate our expectation that
unregulated transmission providers will
participate in the open and transparent
regional planning processes ordered
below and note that, if there are
complaints about such participation or
the lack thereof, we will address them
on a case-by-case basis.
V. Reforms of the OATT
A. Consistency and Transparency of
ATC Calculations
193. In the NOPR, the Commission
proposed to take action under FPA
section 206 to remedy undue
discrimination in the provision of
transmission service. The Commission
recognized that while Order Nos. 888
and 889 require transmission providers
to offer and post any available transfer
capability (ATC) on their OASIS, and
file the methodology they use to
calculate ATC as Attachment C to their
OATTs, the industry has not developed
a consistent methodology for evaluating
ATC nor have transmission providers
adequately made their ATC calculation
methodology transparent. This
inconsistency and lack of transparency
creates the potential for undue
discrimination in the provision of open
access transmission service.
194. In the NOPR, the Commission
proposed to address this potential for
undue discrimination by requiring
industry-wide consistency and
transparency of all components of the
ATC calculation methodology and
certain definitions, data, and modeling
assumptions. The Commission proposed
to provide guidance regarding aspects of
ATC calculations that should be more
consistent and proposed to direct public
utilities, working through NERC 133 and
NAESB, to revise reliability standards
and business practices that are relevant
to ATC calculations. The Commission
also proposed to require increased detail
in Attachment C of each transmission
provider’s OATT and proposed
amending the OASIS regulations to
require increased transparency.
Although commenters challenged
aspects of this proposed remedy, no
commenters challenged the underlying
finding that ATC reform is necessary to
remedy undue discrimination in the
provision of transmission service.
195. The Commission also indicated
that the lack of consistent, industrywide ATC calculation standards poses a
threat to the reliable operation of the
bulk-power system, particularly because
132 See
revised 18 CFR 35.28(e)(1)(ii).
references to NERC in the context of
developing reliability standards are to NERC as the
Electric Reliability Organization (ERO).
133 All
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a transmission provider may not know
of its neighbors’ system conditions
affecting its own ATC values. As a result
of this reliability impact, the
Commission observed that the proposed
ATC reforms are also supported by FPA
section 215(d)(5), through which the
Commission has the authority to direct
the ERO to submit a reliability standard
that the Commission considers
appropriate to implement FPA section
215.
196. In light of these concerns, we
direct public utilities, working through
NERC reliability standards and NAESB
business practices development
processes, to produce workable
solutions to complex and contentious
issues surrounding improving the
consistency and transparency of ATC
calculations. We are directing our
guidance to public utilities and require
that they implement our direction by
working with NERC to develop
reliability standards that accomplish the
ATC reforms required in this
rulemaking. We will coordinate our
directives here with the ATC-related
reliability standards that are pending in
Docket No. RM06–16–000.134 The
specifics of our findings with respect to
ATC reform are discussed below.
1. Consistency
197. In order to address the potential
for remaining undue discrimination in
the determination of ATC, the
Commission proposed to require
industry-wide consistency of certain
definitions, data, and modeling
assumptions of the ATC calculation.
a. Necessary Degree of Consistency
NOPR Proposal
198. In the NOPR, the Commission
recognized that transmission providers
use several basic types of ATC
calculation methodologies (with various
permutations), and did not propose to
require a single ATC calculation
methodology to be applied by all
transmission providers. However, the
Commission proposed to achieve greater
consistency in ATC calculations by
directing the development of consistent
definitions of the ATC components,135
as well as consistent data inputs,
modeling assumptions, and data
134 We note that many of the ATC-related
reliability standards filed in Docket No. RM06–16–
000 were not addressed by the NOPR in that
proceeding, pending the submittal of additional
information. See Mandatory Reliability Standards
for the Bulk-Power System, 71 FR 64770 (Nov. 3,
2006), FERC Stats. & Regs. ¶ 32,608 at Appendix A
(2006) (Reliability Standards NOPR).
135 The ATC components are total transfer
capability (TTC), existing transmission
commitments (ETC), capacity benefit margin (CBM),
and transmission reserve margin (TRM).
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exchange and coordination protocols.
The Commission also required each
transmission provider using an
Available Flowgate Capacity (AFC)
methodology to explain its definition of
AFC, its calculation methodology and
assumptions, and its process for
converting AFC into ATC.
sroberts on PROD1PC70 with RULES
Comments
199. While the majority of
commenters 136 support the NOPR’s
proposal to increase consistency in the
calculation of ATC, several caution the
Commission to allow flexibility 137 in
order to capture differences in system
operations,138 usage, market
operations,139 and topology. Many
assert that industry-wide
standardization of the ATC calculation
might not be possible and suggest that
the Commission consider
interconnection-wide,140 regional,141 or
even sub-regional standardization.
NARUC urges the Commission to
facilitate State commission participation
in efforts to reform ATC methodologies
and calculations on a regional or subregional basis. Conversely, several
commenters suggest that, if the
Commission considers allowing use of
different ATC calculations, it must
impose a heavy burden on any entity
seeking to justify a departure from the
interconnection-wide or regional ATC
standard.142
200. Constellation proposes that the
Final Rule establish a rebuttable
presumption that the basic ATC
calculation formula 143 set forth in
NERC’s current ATC definition be
identical within a region and that each
element of the calculation have the
same meaning for all transmission
providers. Williams requests on reply
that the Commission establish an
136 E.g., Alcoa, Alliance, Ameren, Arkansas
Commission, Arkansas Municipal, AWEA, Duke,
E.ON, EEI, ELCON, EPSA, Exelon, LDWP,
MidAmerican, NRECA, NPPD, NERC, Occidental,
Powerex, PJM, PPL, Progress Energy, Project for
Sustainable FERC Energy Policy, Santee Cooper,
Southern, Suez Energy NA, SPP, TAPS, TVA, TDU
Systems, TranServ, Tacoma, TANC, WECC,
WestConnect, and Xcel.
137 E.g. Allegheny, Entergy, Indianapolis Power,
North Carolina Agencies, and NARUC.
138 E.g. Bonneville, Northwest IOUs, and
NorthWestern.
139 E.g. CAISO.
140 E.g. Ameren and Tacoma.
141 E.g. APPA, Barrick Reply, Duke, EEI, Imperial,
International Transmission, LDWP, NARUC,
Nevada Companies, New York Commission,
NRECA, MidAmerican, Occidental Reply, Pinnacle,
PNM-TNMP, Public Power Council, CREPC, Salt
River, Seattle, South Carolina E&G Reply, SPP
Reply, Utah Municipals, and WPS Companies
Reply.
142 E.g. TDU Systems and East Texas Cooperatives
Reply.
143 E.g., ATC = TTC ¥ (ETC + CBM + TRM).
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industry-wide standard for the
calculation of ATC and emphasizes that
a consistent and transparent approach to
evaluating ATC and ATC/AFC modeling
assumptions is a prerequisite to the
elimination of the broad discretion
afforded transmission providers and,
with it, the subtle discrimination
practiced against customers.
201. Southern suggests that the basic
ATC calculation should be defined for
both firm and non-firm ATC
calculations and also proposes that the
following basic formulas be used: ATC
(firm) = TTC ¥ Firm Commitments or
ETC ¥ TRM ¥ CBM; and ATC (nonfirm) = TTC ¥ Firm and Nonfirm
Commitments + Postbacks of Redirected
and Unscheduled
Service ¥ TRM ¥ CBM. In addition,
TDU Systems requests that the
Commission require standardization of
methods for calculating AFC and
require NERC to create a formal
definition of AFC.
202. PNM–TNMP and Bonneville
express concerns with imposing an
industry-wide standardized ATC
methodology, arguing that there are too
many variables in the way systems are
operated. In its reply comments, PNM–
TNMP adds that NERC’s ATC
calculation method should take into
consideration the need for regional
variation, and focus on consistency in
definitions and data inputs.
WestConnect participants caution that
the replacement of the contract path
ATC approach used in the Western
Electricity Coordinating Council
(WECC) with a flowgate methodology
could seriously disrupt transmission
service in the Western Interconnection.
203. PGP states that, although regional
and sub-regional consistency is a good
idea, there is no need for the
Commission to require ‘‘consistent’’
ATC methodologies; rather, the
emphasis should be on transparency of
the methodologies, inputs, calculations
and outputs. Other commenters agree
that the Commission should not require
overall standardization of ATC
calculations, but instead permit regional
differences with respect to certain
aspects of the calculation of ATC.144 EEI
argues that standardization of ATC
methodologies would require
transmission systems to adopt a ‘‘lowest
common denominator’’ standard in
order to ensure that system reliability is
not compromised, which would result
in a reduction in ATC. EEI suggests that
the Commission should direct NERC to
develop ATC calculation standards that
incorporate regional variations in order
144 E.g., EEI Reply, NARUC Reply, and Powerex
Reply.
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12295
to maximize confidence in standards
and system use, and maintain
reliability. In its reply comments,
Exelon disagrees with EEI and states
that there are no regional differences
within the individual interconnections
that would justify differences in the
application of ATC calculations.
204. Exelon states that ATC
definitions must be consistent so that
the various ATC components such as
TRM have the identical meaning for all
industry participants. In addition,
Exelon argues that each ATC component
(ETC, TRM, and CBM) must be used in
the same manner for all purposes (e.g.,
granting transmission service to third
parties or for the transmission
provider’s own network load).
205. At the October 12 Technical
Conference, NERC recognized that the
goal of achieving consistency may not
mean that a single ATC methodology is
required.145 NERC explained that
consistency can be achieved with a
limited number of methodologies if the
requirements of those methodologies are
properly coordinated and
communicated. NERC stated that the
Standard Drafting Team modifying the
modeling, data, and analysis (MOD)
standards146 relevant to ATC is
developing a standard applicable to
three ATC calculation methodologies:
the rated system path methodology
(contract path), the network response
methodology (network ATC), and the
network response flowgate methodology
(network AFC). NERC and the other
panelists agreed that the two network
methodologies are very similar in
technique. NERC argued that the
ultimate goal of ATC-related reforms
should be to standardize definitions.
The entire panel agreed that definitions
must be consistent and a panelist
representing Constellation asserted that
broad differences in the core definitions
of the ATC calculation are neither
rational nor explainable.147
206. New Mexico Attorney General
recommends that the Commission allow
a utility to waive the requirement to
make certain elements of ATC more
consistent if the utility can show that it
is making adequate progress towards
developing consistent and transparent
ATC calculations at the sub-regional
level.
Commission Determination
207. The Commission adopts the
NOPR proposal to require industry-wide
145 Transcript of October 12 Technical Conference
at 125–150.
146 MOD standards refers to Modeling, Data, and
Analysis Reliability Standards.
147 Transcript of October 12 Technical Conference
at 149–160.
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consistency of all ATC components and
certain definitions, data, and modeling
assumptions. The Commission also will
require each transmission provider to
include in Attachment C to its OATT
detailed descriptions for calculating
both firm and non-firm ATC, consistent
with the requirements of this Final Rule.
The purpose of increasing the
consistency and transparency of ATC
calculations is to reduce the potential
for undue discrimination in the
provision of transmission service,
specifically by reducing the opportunity
for transmission providers to exercise
excessive discretion. We find that the
amount of discretion in the existing
ATC calculation methodologies gives
transmission providers the ability and
opportunity to unduly discriminate
against third parties. In order to
minimize this discretion, the Final Rule
requires that all ATC components (i.e.,
TTC, ETC, CBM, and TRM) and certain
data inputs, data exchange, and
assumptions be consistent and that the
number of industry-wide ATC
calculation formulas be few in number,
transparent and produce equivalent
results. The Commission finds that
these reforms will facilitate
development of a more coherent and
uniform determination of ATC.
208. We reject requests to establish a
single methodology for calculating ATC,
however, for several reasons. It is not
our intent to require transmission
providers to incur the expense of
developing and adopting a new onesize-fits-all software package to
calculate ATC. We also see little benefit
in requiring a ‘‘lowest common
denominator’’ ATC calculator. While a
uniform methodology may result in all
transmission providers calculating ATC
in an identical manner, it would also
likely lead to software implementation
costs in excess of the resulting benefits.
More importantly, we find that the
potential for discrimination does not lie
primarily in the choice of an ATC
calculation methodology, but rather in
the consistent application of its
components.
209. All ATC calculation
methodologies derive ATC by modeling
the system to establish TTC, expressed
in terms of contract paths or flowgates,
and reducing that figure by existing
transmission commitments (i.e., ETC), a
margin that recognizes uncertainties
with transfer capability (i.e., TRM), and
a margin that allows for meeting
generation reliability criteria (i.e., CBM).
These calculation methodologies are
developed based on physical
characteristics of the transmission
provider’s transmission system,
historical modeling practices, and
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processes developed for collection of
input data related to transmission
provider’s own system conditions as
well as relevant data that model
neighboring systems’ conditions. We
therefore find that it is not the
methodologies for calculating ATC
themselves that create the opportunity
for undue discrimination. Instead, we
find that the potential for undue
discrimination stems from two main
sources:
(1) Variability in the calculation of the
components that are used to determine
ATC and (2) the lack of a detailed
description of the ATC calculation
methodology and the underlying
assumptions used by the transmission
provider.148 The combination of a lack
of consistency of the components of the
ATC calculation coupled with the lack
of transparency leaves customers and
regulators unable to verify ATC
calculations and may allow
transmission providers to calculate ATC
in different ways for different
customers.
210. Accordingly, we conclude that
industry-wide consistency of all ATC
components (TTC, ETC, CBM, and
TRM) and certain data inputs and
exchange, modeling assumptions,
calculation frequency, and coordination
of data relevant for the calculation of
ATC will reduce the opportunities for
the exercise of discretion that may lead
to undue discrimination against
unaffiliated transmission customers.
The Commission understands that
NERC currently is developing standards
for three ATC calculation methodologies
(contract or rating path ATC, network
ATC, and network AFC).149 If all of the
ATC components and certain data
inputs and assumptions are consistent,
the three ATC calculation
methodologies being finalized by NERC
through the reliability standards
development process will produce
predictable and sufficiently accurate,
consistent, equivalent, and replicable
148 For example, utilities A and B would agree
that ATC is derived by reducing TTC by the sum
of ETC, CBM and TRM, but utility A may define
ETC to include set-asides for contingencies while
utility B may not.
149 See Transcript of October 12, 2006 Technical
conference at 125. Thee three methodologies are
different computational processes to determine a
transmission system’s ATC. The first, contract path,
examines TTC for every A-to-B path on the system
in concert with all others, reduces ATC by path for
ETC, TRM, and CBM, as appropriate, and produces
ATC for each path. The second method, net work
ATC, uses a simulator to look not at each path, but
each transmission element (line, substation, etc.,),
and rule first contingency simulations to establish
ATC on a network basis. The third method, network
AFC, uses a simulator to examine critical flowgates
over a wider area, then requires a second step to
convert AFC values to particular path ATC values.
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results. It is therefore not necessary to
require a single industry-wide ATC
calculation methodology. The
Commission instead concludes that use
of the ATC calculation methodologies
included in reliability standards
currently being developed by NERC is
acceptable.
211. As TDU Systems note, there is
neither a definition of AFC in NERC’s
Glossary nor an existing reliability
standard that discusses the AFC
method. In order to achieve consistency
in each component of the ATC
calculation (discussed below), we direct
public utilities, working through NERC,
to develop an AFC definition and
requirements used to identify a
particular set of transmission facilities
as a flowgate. However, we remind
transmission providers that our
regulations require the posting of ATC
values associated with a particular path,
not AFC values associated with a
flowgate. Transmission providers using
an AFC methodology must therefore
convert flowgate (AFC) values into path
(ATC) values for OASIS posting. In
order to have consistent posting of the
ATC, TTC, CBM, and TRM values on
OASIS, we direct public utilities,
working through NERC, to develop in
the MOD–001 standard a rule to convert
AFC into ATC values to be used by
transmission providers that currently
use the flowgate methodology.
212. The Commission also believes
that further clarification is necessary
regarding the calculation algorithms for
firm and non-firm ATC.150 Currently,
NERC has no standards for calculating
non-firm ATC. We find that the same
potential for discrimination exists for
non-firm transmission service as for
firm service and that greater uniformity
in both firm and non-firm ATC
calculations will substantially reduce
the remaining potential for undue
discrimination. Therefore, we direct
public utilities, working through NERC,
to modify related ATC standards by
implementing the following principles
for firm and non-firm ATC calculations:
(1) For firm ATC calculations, the
transmission provider shall account
only for firm commitments; and (2) for
non-firm ATC calculations, the
150 The NERC ATC definition does not
differentiate firm and non-firm ATC from a high
level generic ATC definition: ‘‘A measure of the
transfer capability remaining in the physical
transmission network for further commercial
activity over and above already committed uses. It
is defined as Total Transfer Capability less existing
transmission commitments (including retail
customer service), less a Capacity Benefit Margin,
less a Transmission Reliability Margin.’’ See North
American Electric Reliability Corporation, Glossary
of Terms Used in Reliability Standards (February 7,
2006).
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transmission provider shall account for
both firm and non-firm commitments,
postbacks of redirected services,
unscheduled service, and counterflows.
We understand that these principles are
currently followed by most transmission
providers and believe they should be
clearly set forth in the ATC-related
reliability standards. As described
below, each transmission provider’s
Attachment C must include a detailed
formula for both firm and non-firm
ATC, consistent with the modified ATCrelated reliability standards.
213. We deny New Mexico Attorney
General’s request to grant waiver of the
ATC consistency requirements to
utilities that can show that they are
making adequate progress toward
developing consistent and transparent
ATC calculations at the sub-regional
level. While we certainly encourage
regional consistency with respect to the
ATC calculation methodology, we are
not requiring consistency; therefore a
waiver is not necessary. As discussed in
more detail below, any request for
waiver from these ATC calculation
requirements must take place through
the NERC reliability standards
development process as a request for a
regional difference, since the ATC
requirements will be determined
through the NERC reliability standards.
b. Process To Achieve Consistency
NOPR Proposal
214. In the NOPR, the Commission
expressed confidence that the existing
NERC and NAESB processes were wellsuited to achieving greater consistency
in ATC calculations. The Commission
therefore proposed to require public
utilities, working through NERC and
NAESB, to revise the reliability
standards and business practices
relating to ATC, consistent with the
guidance provided in the Final Rule,
within 180 days after the publication of
the Final Rule in the Federal Register.
Comments
sroberts on PROD1PC70 with RULES
215. Many commenters support the
Commission’s proposal directing NERC
and NAESB to develop reliability
standards and business practices
addressing ATC.151 In addition, several
commenters urge the Commission to be
more precise in differentiating between
policy and business standards, and urge
the Commission to provide more
151 E.g., Allegheny, APPA, Arkansas Commission,
Bonneville, CAISO, Constellation, E.ON, EEI,
ELCON, Entergy, Exelon, FirstEnergy, LPPC,
MidAmerican, New York Commission, NERC,
Northeast Utilities, Project for Sustainable FERC
Energy Policy, PNM–TNMP, Santa Clara, Southern,
Tacoma, TransServ, and Utah Municipals.
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guidance to NERC and/or NAESB.152
NRECA suggests that the Commission
require NERC and NAESB to file the
results of their processes with the
Commission, give all interested parties
an opportunity to comment on the
proposals, and exercise its independent
authority to review, and if necessary,
remand the issues or proposals back to
NERC and NAESB.
216. Occidental states on reply that it
does not oppose NERC having a role in
developing the basic requirements and
standards for ATC. However, Occidental
also urges the Commission to adopt a
process similar to that employed in
developing the Standards for Business
Practices and Communication Protocols
for Public Utilities, which were
incorporated by reference into the pro
forma OATT.153 There, the Commission
allowed NAESB’s Wholesale Electric
Quadrant to develop, with widespread
industry input, business practice
standards that the Commission then
reviewed, adopted and required public
utilities to include in their OATTs by
reference.154 Occidental claims that this
process would ensure industry input in
the development of the methodology for
ATC calculations, as well as
Commission review and approval of the
methodology.
217. Several commenters raise
concerns that six months may not be
sufficient time to develop ATC-related
reliability standards and business
practices.155 Exelon, MidAmerican and
NARUC propose that the Commission
grant NERC one year from the date of
the Final Rule to develop the necessary
reliability standards. NARUC agrees
with one year, but requests flexibility to
assure that the NERC and NAESB
processes can be adequately completed.
NERC also states that it expects the
standards development process, already
underway, to be finalized with
standards submitted to the Commission
prior to the summer of 2007. LPPC
recommends that, within six months of
the issuance of the Final Rule, NERC be
required to submit a progress report
addressing the status and a work plan
for conclusion within the ensuing six
months. NRECA proposes that the
Commission closely monitor the NERC
and NAESB process. Some commenters
152 E.g.,
EPSA and Williams.
Standards for Business Practices and
Communication Protocols for Pub. Utils., Order No.
676, 71 FR 26199 (May 4, 2006), FERC Stats. & Regs.
¶ 31,216 (2006), order on reh’g, Order No. 676–A,
116 FERC ¶ 61,255 (2006).
154 Citing id. at P 20.
155 E.g., Constellation, Duke, EEI, Exelon, LPPC,
MidAmerican, NARUC, Northwest IOUs, Public
Power Council, CREPC, Southern, TDU Systems,
and WestConnect.
153 Citing
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12297
strongly oppose a flexible deadline, and
urge the Commission to establish a firm
deadline that must be met.156
218. At the October 12 Technical
Conference, NERC informed
participants that a great deal of progress
has been made since the proposed
standards developed by the NERC
Standard Committee in February 2006
were generated to address the
recommendations made by the LongTerm AFC/ATC Task Force.157
However, NERC indicates that a
significant amount of work remains
before the standard revisions are
considered complete. Since NERC
would like to finalize its revised
standards for submittal to the
Commission for the summer of 2007,
NERC has established an aggressive
schedule of meetings for drafting which
will be coordinated with NAESB.
219. PJM outlines several guidelines it
suggests the Commission should give to
NERC and NAESB regarding the
standards development process and
recommends that Commission staff
participate in the standards
development process. Williams and
EPSA likewise request that the
Commission provide clear guidance to
NAESB to assure efficiency and
timeliness of the process.
220. Some commenters prefer
engagement of a fully independent
organization to develop standards and
practices related to ATC.158 EPSA
strongly urges the Commission to
require all transmission providers
outside of RTO areas to contract with an
independent entity to develop and/or
monitor ATC calculations. Although
TDU Systems agree with EPSA that
vertically-integrated transmission
providers that are not subject to the
independent oversight of an ISO/RTO
retain inherent incentives to
discriminate against competitors, they
contend that the benefit of independent
oversight of ATC calculations must be
weighed against the cost of that
oversight. Alcoa suggests engaging the
Institute of Electrical and Electronics
Engineers (IEEE) instead of the
Commission’s proposal to use NERC
and NAESB. APPA opposes that
position. New York Commission
proposes that regional reliability
organizations, rather than NERC,
complete this task and that the ATC
calculators be closely coordinated by
156 E.g.,
Utah Municipals and Entegra.
Long-Term AFC/ATC Task Force Final
Report (Revised April 14, 2005), available at
https://www.nerc.com/∼filez/ltatf.html.
158 E.g., Alcoa, Fayetteville, and MISO.
157 Citing
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sroberts on PROD1PC70 with RULES
ISOs and RTOs.159 PJM contends on
reply that New York Commission’s
proposal for coordination of ATC
between ISOs and RTOs has been
fulfilled at least between PJM and its
neighbors, arguing that New York
Commission’s proposal is unnecessary
and would add a layer of bureaucracy
and cost. TAPS expresses concern with
the Commission proposal to use NERC
and encourages the Commission to be
precise in its direction to NERC to
accomplish the needed objective.
Commission Determination
221. The Commission directs public
utilities, working through NERC and
NAESB, to modify the ATC-related
reliability standards and business
practices in accordance with specific
direction provided in this Final Rule. As
we explain above, the development of a
more coherent and uniform
determination of ATC across a region
will help limit the potential for undue
discrimination in the calculation of
ATC. The Commission concludes that
the NERC reliability standards
development process and the NAESB
business practices development process
are the appropriate forums for
developing this consistency.
222. NERC has been certified as the
ERO and, as such, has been found to
have the ability to develop reliability
standards through processes with
reasonable notice and opportunity for
public comment. NERC’s processes are
open and provide due process as well as
a balance of interests, while assuring
independence from users and owners
and operators of the bulk-power system.
Moreover, NAESB has a long history of
developing standard business practices
for the electric industry, on which the
Commission has relied in various
contexts. While other entities may bring
certain benefits, commenters have not
demonstrated the superiority of IEEE, a
regional reliability organization, or a
particular RTO over NERC and NAESB.
Once components of ATC are made
consistent and ATC calculation
methodologies are made transparent,
opportunities for discretion that may
lead to undue discrimination in the
calculation of ATC will be sufficiently
eliminated to invalidate the need for the
creation of independent entities to
oversee that calculation. To the extent
that, even following the adoption of
these reforms, customers have
complaints regarding the calculations
performed by individual transmission
159 If
ISOs and RTOs cannot perform the
coordination function, New York Commission
suggests the establishment of a Transmission
Oversight Center to oversee the calculation of ATC
within and between ISOs and RTOs.
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owners, they can be addressed on a
case-by-case basis.
223. With respect to a timeline for
completion, the Commission concurs
with NERC that a significant amount of
work remains to be done on ATC-related
reliability standards development. We
also agree with the many commenters
who state that the NOPR’s proposed sixmonth timeline is too short for such a
complex assignment. Although NERC
projects that it may be able to complete
the process by the summer of 2007
(which is approximately six months
from the date of the Final Rule), we
believe NERC should have additional
flexibility with respect to its timeline.
Accordingly, we direct public utilities,
working through NERC, to modify the
ATC-related reliability standards within
270 days after the publication of the
Final Rule in the Federal Register. We
also direct public utilities to work
through NAESB to develop business
practices that complement NERC’s new
reliability standards within 360 days
after the publication of the Final Rule in
the Federal Register. Finally, we direct
NERC and NAESB to file, within 90
days of publication of the Final Rule in
the Federal Register, a joint status
report on standards and business
practices development and a work plan
for completion of this task within the
timeframe established above.160
c. Applicability to ISOs, RTOs, and
Non-Public Utility Transmission
Providers
NOPR Proposal
224. The Commission did not
specifically address the application of
the ATC-related reforms proposed in the
NOPR to ISOs and RTOs or non-public
utility transmission providers.
Comments
225. ISOs and RTOs believe that the
Commission should not require
wholesale revisions of RTO and ISO
tariffs, even on such issues as ATC
standards.161 They caution that many
regional grid operators’ tariffs contain
nonconforming provisions that were the
product of extensive debate, litigation
and settlements. In addition, some
commenters point out that concern
about ATC calculations is a non-issue in
many ISO/RTO regions because
transmission services in those regions
160 NAESB’s work plan for developing business
practices related to other reforms adopted in this
Final Rule should be filed separately, as requested
in Section IV.C.1.
161 E.g., PJM and MISO Transmission Owners,
SPP Reply.
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are not based on physical transmission
reservations.162
226. MISO argues that AFC
calculation methodologies should be
established via the RTO stakeholder
process, not NERC. In its reply
comments, Exelon expresses
disagreement with MISO and states that
there must be one standard for ATC
calculations, not several methods based
on the desires of different sets of
stakeholders. Several commenters also
believe that ISOs/RTOs should not be
exempt from the requirements for
consistent and transparent ATC
calculations.163
227. EEI asks the Commission to
require all municipal and other nonpublic utility transmission providers to
adhere to any requirement for consistent
and transparent ATC/AFC calculation.
In its view, applying the ATC-related
reforms to these nonjurisdictional
entities would recognize the
interconnected nature of the
transmission grid. EEI argues that
greater transparency and consistency in
the provision of transmission service
would be frustrated if all transmission
providers do not have to comply. Other
commenters reply that EEI’s concerns
are unfounded and describe an example
in the WECC region, where the
methodologies and practices regarding
ATC calculations are developed by
representatives from all affected
transmission providers, utilities, and
market participants, including
nonjurisdictional entities.164
228. LPPC contends that the NERC
reliability standards related to ATC
calculation will already be applicable to
both public and non-public utilities.
LPPC argues that NERC standards, when
final, will be filed with the Commission,
become part of the ERO’s mandatory
reliability standards and will be fully
applicable to otherwise
nonjurisdictional entities. As a result,
the ATC standards will be applicable to
and enforceable upon all transmission
owners, whether or not the transmission
owner has an OATT.
Commission Determination
229. We discuss the applicability of
the Final Rule to ISOs and RTOs in
section IV.C.2 above. With respect to the
application of the ATC requirements of
this Final Rule to municipal and other
non-public utility transmission
providers, we likewise note that the
applicability of the rule generally to
such entities is addressed in section
162 E.g., ISO/RTO Council, ISO New England, and
Pennsylvania Commission.
163 E.g., NRECA and TDU Systems.
164 E.g., Lassen and Public Power Council.
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IV.C.3. We note here, however, that
such entities will be required to comply
with reliability standards developed
under FPA section 215. As LPPC
acknowledges, once these reliability
standards are approved they will
become part of the ERO’s mandatory
reliability standards and, thus, will be
applicable to and enforceable upon all
transmission owners, whether or not the
transmission owner has adopted the
OATT.
d. Alternatives to ATC Consistency
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Comments
230. Some commenters contend that
the NOPR is focused too narrowly on
simply improving the consistency and
transparency of ATC determinations
and suggest that a focus on balancing (or
dispatch) services and how those are
priced would allow the Commission to
avoid the pitfalls inherent in the ATC
approach.165 In their view, such an
approach would eliminate much of the
difference between how third parties are
treated in RTO versus non-RTO systems.
Constellation encourages the
Commission to consider requiring
transmission providers to implement
all-inclusive, security constrained
economic dispatch processes. In reply
comments, Chandley-Hogan argue that
the Commission’s ATC-related
proposals in the NOPR confuse how
transmission service is actually
provided in most of the United States
and, as a result, the Commission’s
analysis of perceived problems in the
calculation of ATC is flawed,
inconsistent with network realities and
the laws of physics, and incompatible
with reliable operations.
231. Contrary to the above claims,
some commenters find that ATC
provides a functionally useful measure
of available capacity and has certain
advantages over alternative models.166
These commenters argue that the factual
record does not support conclusions
that bid-based, marginal cost dispatch
by a third party is inherently more
efficient or inherently more likely to
remedy undue-discrimination than the
OATT model, and cannot overcome the
considerable real world obstacles to
pure economic redispatch, including
overlapping and dynamic constraints,
and the physical realities in the Western
Interconnection that often limit the pool
of resources that can be redispatched to
solve constraints. LPPC contends that
the principal advantage of ATC is the
165 E.g., Chandley-Hogan, EPSA, PJM, San Diego
G&E, and Transparent Dispatch Advocates Reply.
166 E.g., APPA, CMUA, CPA, Duke, EEI, Entergy,
LPPC, Public Power Council, Sacramento, and
WestConnect Reply.
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certainty that it provides for available
capacity, suggesting that the contract
path paradigm facilitates long-term
bilateral contracting.
Commission Determination
232. In this rulemaking, the
Commission is requiring consistency in
the determination of ATC with the
purpose of improving a customer’s
ability to receive transmission service
on a non-discriminatory basis. These
reforms are fully consistent with
operational reality, and we decline to
mandate the security constrained
economic dispatch alternative proposed
by Chandley-Hogan. Chandley-Hogan
argue that it would be unduly
discriminatory to exclude third-party
generators from an efficient dispatch to
serve native load and therefore a
centralized, bid-based market is
required. We agree that a centralized
bid-based market can benefit customers
and, over a large region, can manage
congestion efficiently. We do not
believe, however, that mandating that
result—essentially requiring that Day 2
RTOs be adopted in every region of the
country—is necessary to remedy undue
discrimination in the provision of
transmission service. The concern
raised by Chandley-Hogan is not related
solely to the nondiscriminatory use of
the transmission system. It also
implicates the purchase decisions of
transmission providers on behalf of
their native load customers. These
decisions are regulated primarily by the
states and we decline to take generic
action in this rulemaking to reform the
processes by which those purchases are
made.
e. ATC Components
233. The next several sections address
components of ATC that must be made
consistent to remove the potential for
undue discrimination, namely TTC/
TFC, ETC, CBM, and TRM.
(1) Total Transfer Capability (TTC)/
Total Flowgate Capability (TFC)
NOPR Proposal
234. The Commission proposed to
direct public utilities, working through
NERC, to develop consistent practices
for calculating total transfer/flowgate
capability (TTC/TFC). Although the
NERC reliability regions have
historically calculated transfer
capability using different approaches,
the Commission expressed its view that
guidelines for a common approach to
calculating transfer capability are
achievable. The Commission also stated
that the criteria used for identifying
flowgates and determining TFC could be
more consistent.
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12299
Comments
235. Entergy supports the
development of consistent practices for
determining transfer capability while
maintaining flexibility to recognize
regional and system-specific differences.
APPA agrees that the calculation of
TTC/TFC is, for the most part, a regional
calculation. APPA states that the
Western Interconnection and ERCOT
use their own methods, which are
generally applied system-wide. APPA
believes that more standardization and
coordination of TTC/TFC among
transmission providers in the Eastern
Interconnection, where two primary
methods are used to calculate TTC or
TFC, would be desirable because of
reported loop-flow problems in the
Eastern Interconnection.
236. In order to increase transfer
capability from existing facilities,
AWEA proposes that the Commission
direct NERC, as part of developing
consistent ATC standards, to investigate
the impact of implementing dynamic
line ratings in TTC/TFC calculations
and propose protocols to effectuate such
a program. In response to AWEA’s
proposal, commenters state that if the
Commission decides to provide
guidance to NERC with regard to
dynamic line ratings, the Commission
should encourage NERC to develop
standards with regard to dynamic line
ratings in the operating horizon, but not
in the planning horizon.167
Commission Determination
237. The Commission adopts the
NOPR proposal and directs public
utilities, working through NERC, to
develop consistent practices for
calculating TTC/TFC. We direct public
utilities, working through NERC, to
address, through the reliability
standards process, any differences in
developing TTC/TFC for transmission
provided under the pro forma OATT
and for transfer capability for native
load and reliability assessment studies.
238. We acknowledge that reliability
regions have historically calculated
transfer capability using different
approaches, and we agree that regional
differences should be respected.168
However, as already discussed above
regarding ATC, the TTC requirements
will be determined by the NERC
reliability standards and any request for
a regional difference from the reliability
standards must take place through the
NERC process.
167 E.g.,
MAPP and MidAmerican.
example, WECC has a documented open
process for establishing TTC for the Western
Interconnection.
168 For
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239. With respect to AWEA’s proposal
regarding implementing dynamic line
ratings in TTC/TFC calculations, the
Commission finds that this proposal is
outside the scope of this rulemaking as
it does not appear to relate to undue
discrimination in transmission service
and, in any event, would best be
addressed in the first instance through
the NERC reliability standards
development process, addressing
reliability standards that regulate
facility ratings. If AWEA desires to
pursue this proposal, it should propose
an appropriate dynamic line rating
standard within the ERO’s reliability
standards development process.
(2) Existing Transmission Commitments
(ETC)
NOPR Proposal
240. In the NOPR, the Commission
expressed its view that the lack of
consistency in modeling of existing
transmission commitments (ETC)
resulted in excessive discretion in
determining how much capacity a
transmission provider sets aside for
native load, including its network
customers. The Commission therefore
proposed the development of a
consistent methodology for determining
the capacity needed and set aside for
native load usage. The Commission also
proposed that accounting for
transmission reservations in an ATC/
AFC calculation be more consistent. The
Commission further proposed that
public utilities, working through NERC,
establish and specifically identify the
reservations to be used in determining
ETC.
sroberts on PROD1PC70 with RULES
Comments
241. Entegra and PGP support
increasing consistency in determining
ETC. APPA agrees that it would be
helpful to standardize the method of
accounting for ETC on an
interconnection-wide basis. APPA
states, however, that flexibility might be
required among the interconnections.
TDU Systems requests that the
Commission define with specificity the
types of transmission service requests or
scheduled transmission transactions
that should be included in ETC and
agrees with the Commission that
inclusion of all requests for
transmission service in ETC is likely to
overstate usage of the system, thus
understating ATC. It suggests that the
Commission develop a bright line
method for calculating ETC. NERC notes
that its proposed reliability standards
would define ETC and require
appropriate documentation. NERC adds,
however, that the components included
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in ETC appear to be candidates for
business practices rather than reliability
standards.
242. Williams proposes that ETC be
the subject of an expanded definition
and that native load growth projections
be based on verifiable data provided by
an independent source. It also states
that transmission providers should be
required to update ATC based on each
confirmed transmission service
reservation (point-to-point or network,
firm or non-firm).
Commission Determination
243. To achieve greater consistency in
ETC calculations and further reduce the
potential for undue discrimination, the
Commission adopts the NOPR proposal
and directs public utilities, working
through NERC and NAESB, to develop
a consistent approach for determining
the amount of transfer capability a
transmission provider may set aside for
its native load and other committed
uses. We expect that NERC will address
ETC through the MOD–001 reliability
standard rather than through a separate
reliability standard.169 By using MOD–
001, the ETC calculation can be adjusted
to be applicable to each of the three
ATC methodologies under development
by NERC.
244. In order to provide specific
direction to public utilities and NERC,
we determine that ETC should be
defined to include committed uses of
the transmission system, including (1)
Native load commitments (including
network service), (2) grandfathered
transmission rights, (3) appropriate
point-to-point reservations,170 (4)
rollover rights associated with long-term
firm service, and (5) other uses
identified through the NERC process.
ETC should not be used to set aside
transfer capability for any type of
planning or contingency reserve, which
are to be addressed through CBM and
TRM.171 In addition, in the short-term
ATC calculation, all reserved but
unused transfer capability (nonscheduled) shall be released as non-firm
ATC.
245. We agree with TDU Systems that
inclusion of all requests for
transmission service in ETC would
likely overstate usage of the system and
understate ATC. We therefore find that
169 The purpose of MOD–001 is to promote the
consistent and uniform application of transfer
capability calculations among the transmission
system users.
170 By ‘‘appropriate,’’ we mean that reservations
accounted for under ETC depend on the firmness
and duration of the reservation. The specific
characteristics should be developed in the
reliability standard.
171 TRM also includes such things as loop flow
and parallel path flow.
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reservations that have the same point of
receipt (POR) (generator) but different
point of delivery (POD) (load), for the
same time frame, should not be modeled
in the ETC calculation simultaneously if
their combined reserved transmission
capacity exceeds the generator’s
nameplate capacity at POR. This will
prevent overly unrealistic utilization of
transmission capacity associated with
power output from a generator
identified as a POR. We direct public
utilities, working through NERC, to
develop requirements in MOD–001 that
lay out clear instructions on how these
reservations should be accounted. One
approach that could be used is
examining historical patterns of actual
reservation use during a particular
season, month, or time of day.
246. We agree with NERC that some
elements of ETC are candidates for
business practices rather than reliability
standards. Accordingly, we direct
public utilities, working through
NAESB, to develop business practices
necessary for full implementation of the
developed MOD–001 reliability
standard.
247. We decline to adopt Williams’s
proposal to require that native load
growth be based on the verifiable data
provided by an independent source.
Through increased consistency and
transparency of ATC determinations,
including requirements for posting
additional data, third parties will be
able to verify the accuracy of ETC,
helping to eliminate opportunities for
undue discrimination.
(3) Capacity Benefit Margin (CBM)
NOPR Proposal
248. In the NOPR, the Commission
proposed three options to address the
CBM component of ATC: (1) Have NERC
develop clear standards for how the
CBM value should be determined,
allocated across transmission paths, and
used; (2) charge an entity for which
transfer capability has been set aside to
meet generation reliability criteria a
separate rate for this service; or (3)
eliminate CBM and require an entity
reserving ATC to meet generation
reserve (currently through CBM) to
designate network resources on the
other side of the interface and make an
associated transmission service
reservation.
Comments
249. Numerous commenters support
the Commission’s proposed option one,
requiring NERC to develop clear
standards for how the CBM value
should be determined, allocated across
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transmission paths, and used.172 They
believe that CBM ensures the ability to
import needed power to support system
conditions. TVA argues that option two
would be costly and may cause some
systems to forego CBM, thereby
jeopardizing service to native load
customers. PJM states that option two is
irrelevant in PJM since PJM ‘‘totals’’
reservations and decides when CBM can
be used. Supporters of option one
criticize option three, elimination of
CBM, as costly and a threat to
transmission system reliability.
Southern, Progress Energy, and PJM
emphasize that, without CBM, the LSEs
would need to increase their reserve
margin by contracting for additional
generation capacity, costing millions of
dollars. In addition, Ameren and TVA
believe that CBM elimination will
increase the likelihood of widespread
blackouts in emergency conditions.
250. At the October 12 Technical
Conference, Exelon supported option
two proposing a charge for CBM. Exelon
contended that, in a rate-making
context, there would be an increase in
the divisor of the rate by the amount of
CBM set-aside which would lower the
point-to-point charge. Consequently,
those not benefiting from the CBM setaside effectively would be paying a
lower charge.
251. Constellation and Morgan
Stanley support the elimination of CBM
and argue that CBM and TRM are often
used interchangeably and result in
duplicative transmission set-asides.
They also argue that there is no
compelling need for CBM in the current
liquid market environment. In addition,
Morgan Stanley states that LSEs
affiliated with the transmission provider
should not be allowed to use CBM for
long-term planning purposes as an
excuse to avoid undertaking needed
resource additions or to conceal the true
cost of their load serving functions.
Furthermore, the Commission should
not be distracted by assertions that such
long-term arrangements are necessary
for ‘‘reliability,’’ when in fact they are
simply a way to protect the economic
interests of a particular entity.
252. Duke replies that Constellation
mistakenly believes that CBM is
currently only available to a
transmission provider’s native load
when, in fact, for those transmission
providers that establish CBM, it should
be established for the load of all LSEs
in the control area. Duke contends that
172 E.g., Allegheny, Ameren, EEI, Duke, NRECA,
TVA, APPA, Bonneville, EPSA, FirstEnergy,
Indianapolis Power, MidAmerican, Pinnacle, PJM,
PGP, PNM–TNMP, Public Power Council,
Sacramento, Seattle, South Carolina E&G, TANC,
TDU Systems, and Wisconsin Electric.
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not all transmission providers set aside
capacity through CBM for their native
load; to the extent that a transmission
provider does not set aside CBM, there
should be no obligation to allow other
LSEs to do so. Duke proposes that the
Commission should continue to permit
such flexibility.
253. NERC takes no position on CBM,
expecting that the issue can be settled
through the NERC and NAESB
Procedure for Joint Standards
Development and Coordination and
through other open forums.
254. TAPS suggests that the
Commission ensure that all LSEs have
both access to CBM to meet their
reserve-sharing needs and meaningful
input into how much CBM is reserved.
To do so, TAPS recommends the
creation of a reserve-sharing group made
up of the transmission provider and
LSEs it serves. It argues that this would
remove reservation decisions from the
sole discretion of the verticallyintegrated transmission provider and
instead have them made by the
transmission provider/LSE reservesharing group, subject to dispute
resolution at the Commission. All LSEs
would be invited to participate in the
studies as well as review the results and
assumptions. Moreover, once a regional
planning process is established, as
proposed in the NOPR, TAPS
recommends that the regional planning
group be required to approve the CBM
reservation as well.
255. Williams suggests that a
transmission provider must designate
network resources and reserve firm
transfer capability on both sides of the
control area transmission interface in
order to reserve CBM. Duke replies that,
although some commenters prefer
eliminating CBM and replacing it with
additional designated network
resources, CBM is the preferable option
because it is less costly. Duke further
argues that the choice is between setting
aside both additional transmission and
generation capacity to deal with
emergencies (the additional designated
network resource approach) versus
setting aside only transmission (the
CBM approach). Having to procure
additional designated network resources
to keep in reserve reduces one of the
main benefits of interconnected
operations. Duke argues that eliminating
CBM would drive up costs for network
customers, as they would have to
procure additional generation and
transmission resources. EEI adds that
such a proposal may result in increased
LSE reserve requirements, over-building
of generation supply, and a reduction,
rather than an increase, in ATC.
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12301
Commission Determination
256. The Commission concludes that
it is appropriate to allow LSEs to retain
the option of setting aside transfer
capability in the form of CBM to
maintain their generation reliability
requirement. We agree with commenters
that, without CBM, LSEs would have to
increase their generation reserve
margins by contracting for generation
capacity, which may result in higher
costs without additional reliability
benefits. We require, however, the
development of standards for how CBM
is determined, allocated across
transmission paths, and used in order to
limit misuse of transfer capability set
aside as CBM. Transmission providers
also must reflect the set-aside of transfer
capability as CBM in the development
of the rate for point-to-point
transmission service to ensure
comparable treatment for point-to-point
to customers.
257. The Commission therefore
adopts a combination of the NOPR
options one and two, and declines to
adopt option three. First, we require
public utilities, working through NERC
and NAESB, to develop clear standards
for how the CBM value shall be
determined, allocated across
transmission paths, and used. We
understand that NERC has already
begun the process of modifying several
of the CBM-related reliability standards
and that the drafting process is a joint
project with NAESB. Second, we require
transmission providers to reflect the setaside of transfer capability as CBM in
the development of the rate for point-topoint transmission service.
258. We note that there is broad
concern that eliminating CBM (option
three) would impose extraordinary costs
for meeting generation reliability
criteria, which then may lead utilities to
reduce their generation reliability
requirement to avoid the cost increase.
We believe that the reforms reflected in
combining options one and two are
sufficient to remedy undue
discrimination and that the adverse
effects associated with option three are
neither warranted nor required. We
reject Morgan Stanley’s call for CBM
elimination on the grounds that CBM is
acting as a disincentive to undertake
needed generation resource additions. It
would be inappropriate for the
Commission to restrict the ability of an
LSE to determine how best to meet its
generation reliability criteria.
259. To ensure CBM is used for its
intended purpose, CBM shall only be
used to allow an LSE to meet its
generation reliability criteria. Consistent
with Duke’s statement, we clarify that
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each LSE within a transmission
provider’s control area has the right to
request the transmission provider to set
aside transfer capability as CBM for the
LSE to meet its historical, State, RTO, or
regional generation reliability criteria
requirement such as reserve margin, loss
of load probability (LOLP), the loss of
largest units, etc.
260. We direct public utilities,
working through NERC, to develop clear
requirements for allocating CBM over
transmission paths and flowgates. While
we do not mandate a particular
methodology for allocating CBM to
paths and flowgates, one approach
could be based on the location of the
outside resources or spot market hubs
that an LSE has historically relied on
during emergencies resulting from an
energy deficiency.
261. We concur with TAPS’ proposal
that all LSEs should have access to CBM
and meaningful input into how much
transfer capability is set aside as CBM.
In the transparency section below, we
provide detailed requirements regarding
availability of documentation used to
determine the amount of transfer
capability to be set aside as CBM and
the posting of CBM values and
narratives. Access to this documentation
will enable LSEs to validate how much
transfer capability is set aside as CBM
on each system and provide them with
information to question whether the setaside is consistent with the reliability
standards and this Final Rule.
262. Concerning TAPS’ proposal to
remove the reservation decision from
the sole discretion of transmission
providers, we determine that LSEs
should be permitted to call for use of
CBM, if they do so pursuant to
conditions established in the reliability
standards development process. We
direct public utilities working through
NERC to modify the CBM-related
standards to specify the generation
deficiency conditions during which an
LSE will be allowed to use the transfer
capability reserved as CBM. In addition,
we direct that transmission set aside as
CBM shall be zero in non-firm ATC
calculations. Finally, we order public
utilities to work with NAESB to develop
an OASIS mechanism that will allow for
auditing of CBM usage.
263. We also require transmission
providers to design their transmission
charges to ensure that the class of
customers not benefiting from the CBM
set-aside, i.e., point-to-point customers,
do not pay a transmission charge that
includes the cost of the CBM set-aside.
To do this, transmission providers are
required to submit redesigned
transmission charges that reflect the
CBM set-aside through a limited issue
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FPA section 205 rate filing as part of its
initial ATC-related compliance filing.
These filings, which may be submitted
within 120 days after the publication of
the Final Rule in the Federal Register,
may be limited to the rate design change
only, i.e., they will not require the
submission of cost of service data or a
revision to the transmission provider’s
revenue requirement.
264. With respect to TAPS’ proposal
that all LSEs should be allowed to use
CBM to meet their reserve-sharing
needs, we believe that TRM is the
appropriate category for that purpose,
not CBM. We reject TAPS’ proposal to
use CBM for the LSE’s reserve-sharing
needs, but instead make TRM available
for the incremental power flows
resulting from reserve sharing, as
explained next.
265. As we are rejecting option three,
which would have required the
reservation of transfer capability rather
than using CBM, we also reject
Williams’ proposal to require the
reservation of transfer capability on both
sides of an interface for CBM.
(4) Transmission Reserve Margin (TRM)
NOPR Proposal
266. Finally, the Commission
proposed the development of reliability
standards MOD–008 and MOD–
009 173that specify the uncertainties that
TRM could be used to accommodate,
which could include (1) Load forecast
and load distribution error, (2)
variations in facility loadings, (3)
uncertainty in transmission system
topology, (4) loop flow impact, (5)
variations in generation dispatch,
including intermittent resources, (6)
automatic sharing of reserves, and (7)
other uncertainties identified through
the NERC reliability standards
development process.
Comments
267. Most commenters agree that the
existing definitions for TRM require
clarification.174 Commenters also agree
that NERC should be required to
develop clear standards for the
determination of TRM, including
specifying the criteria used in the
determination of TRM.175 PNM–TNMP
173 The MOD–008 and MOD–009 reliability
standards document regional TRM methodologies
and procedures for verifying TRM values.
174 E.g., Allegheny, APPA, EEI, EPSA, Exelon,
LPPC, MidAmerican, NRECA, Northwest IOUs,
NorthWestern, Occidental, Pinnacle, Powerex,
PNM–TNMP, PPL, PJM, PPM, and WestConnect.
175 Exelon recommends that the following factors
should be the same for the planning process and
ATC/AFC process to achieve consistency: base case
flows, reservation impacts, TRM and CBM
forecasted to occur simultaneously; counterflows;
positive impacts resulting from reservations and
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supports the Commission’s proposal,
pointing out that the implementation of
the current NERC standards definition
for TRM and CBM could result in its
double-counting, which must be
eliminated. APPA members in the
Western Interconnection suggest that
regional variations be permitted. They
also note that the modeling methods
used by WECC and its sub-regions may
differ from those used in the Eastern
Interconnection. For example, they
contend that uncertainties associated
with transmission maintenance
schedules that are driven by hydroproduction curves will seasonally affect
TRM set-asides on certain transfer
paths. PJM believes that the TRM
methodology should be consistent at the
regional reliability organization level.
PJM also contends that TRM should be
coordinated, exchanged and respected
on external flowgates and that the
concept of a maximum TRM, by
percentage, should be adopted in the
NERC standards.
268. Consistent with its position on
CBM, TAPS proposes that TRM setasides should be conditioned on
inclusive reserve-sharing arrangements,
with the reservations determined by the
reserve-sharing group, subject to dispute
resolution before the Commission (and,
eventually, approval by joint planning
groups).
269. PNM–TNMP suggests that the
Commission consider definitions to
include the following clarification taken
from WECC procedures on ATC: ‘‘If the
limitation on the use of TRM to 59
minutes would force a Transmission
Provider to set aside unnecessary CBM
on the same path as the TRM, that
Transmission Provider may utilize the
TRM beyond the 59 minutes.’’ 176 PNM–
TNMP states that this would allow the
transmission provider to maximize the
ATC by not needlessly setting aside
twice the amount of transmission (TRM
and CBM) than is necessary for
reliability.
270. Nevada Companies argue that no
new standards are required for TRM and
that any further action would be
burdensome. They explain that NERC
has a well-established definition that
does not require further clarification. In
their view, all that is required is a
complete statement, to be posted on
OASIS, regarding the transmission
provider’s application of TRM. NERC
generation dispatch; TRM for the same scenarios;
and CBM.
176 Citing WECC Rocky Mountain Operating and
Planning Group, Determination of Available
Transfer Capability within the Western
Interconnection, June 2001, page 9, https://
www.wecc.biz/modules.php?op=modload&name=
Downloads&file=index&req=getit&lid=1035.
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comments that the existing reliability
standards for TRM will be revised to
require clear documentation of the
calculation of TRM. It also adds that the
revised standard will make various TRM
components mandatory to achieve more
consistency across methodologies.
271. Santee Cooper urges the
Commission to ensure that service to
native load and transmission system
reliability will not be compromised as
the Commission seeks greater levels of
consistency in the calculation of ATC. It
states that the Commission also must be
cognizant of the importance of TRM in
the provision of service to native load.
Commission Determination
272. The Commission adopts the
NOPR proposal and requires public
utilities, working through NERC, to
complete the ongoing process of
modifying TRM standards MOD–008
and MOD–009. We understand that the
standard drafting process is underway
as a joint project with NAESB.
273. The Commission also adopts the
NOPR proposal to establish standards
specifying the appropriate uses of TRM
to guide NERC and NAESB in the
drafting process. Transmission
providers may set aside TRM for (1)
Load forecast and load distribution
error, (2) variations in facility loadings,
(3) uncertainty in transmission system
topology, (4) loop flow impact, (5)
variations in generation dispatch, (6)
automatic sharing of reserves, and (7)
other uncertainties as identified through
the NERC reliability standards
development process. Because load,
facility loading and other uncertainties
constantly deviate, we will not require
that TRM set aside capacity be set at
zero in the non-firm ATC calculation. In
other words, we will not require transfer
capability that is set aside as TRM to be
sold on a non-firm basis. We find that
clear specification in this Final Rule of
the permitted purposes for which
entities may reserve CBM and TRM will
virtually eliminate double-counting of
TRM and CBM.
274. We will not adopt PNM-TNMP’s
proposal regarding use of set aside
transfer capability as TRM beyond 59
minutes, rather than converting it to
CBM. Our proposal is to separate
transfer capability set asides as either
CBM or TRM without regard to duration
of use of the set aside. Therefore, such
a clarification is not necessary.
275. In addition, we direct public
utilities, working through NERC, to
establish an appropriate maximum
TRM. One acceptable method may be to
use a percentage of ratings reduction,
i.e., model the system assuming all
facility ratings are reduced by a specific
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percentage. This is a relatively simple
method and, if adopted as the reliability
standard’s method, should not restrict a
transmission provider from using a
more sophisticated method that may
allow for greater ATC without reducing
overall reliability.
276. Because of the operational
characteristics of the uncertainties that
are to be accommodated using TRM,
and their aggregate impact on reliable
operation, we require each transmission
provider to calculate, and allocate on
the paths and flowgates, the aggregate
TRM value for all LSEs within its area.
We support NERC’s plan to revise
existing reliability standards for TRM to
require clear documentation of the TRM
calculation, as we expect the TRM value
to be supported and fully transparent. In
addition, we require each transmission
provider to make available all
underlying documentation, including
work papers and load flow base cases,
used to determine TRM, to any
transmission customer and LSE within
its control area, subject to a
confidentiality agreement,177 if
necessary. We agree with Santee
Cooper’s comments that the
Commission must ensure that service to
native load and system reliability are
not compromised. We believe that our
requirement for public utilities to work
through NERC satisfies such concerns.
277. With respect to the proposal to
permit regional variations in the TRM
calculation methodology, we reiterate
our position stated above that any
request for regional difference from the
applicable reliability standards must
take place through the NERC reliability
standards development process. With
respect to TAPS’ proposal regarding
reserve sharing groups, we clarify that,
to the extent transfer capability is
needed for transmission of shared
reserves, this is included under TRM.
However, as noted previously in the
CBM discussion, we are not mandating
the use of reserve sharing groups.
f. Modeling, Assumptions and Input
Data
NOPR Proposal
278. The Commission’s proposal with
regard to modeling, assumptions and
data inputs was based on a principle
that there should be consistency among
transmission providers and between
what the transmission provider does for
its operation and expansion planning
for native load and what it does in
determining short and long-term ATC
177 The agreement may appropriately restrict the
sharing of sensitive information with customer
personnel that are involved only in transmission
functions, as opposed to merchant functions.
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for all uses. The Commission stated its
view that consistency is necessary to
ensure non-discriminatory treatment by
eliminating a transmission provider’s
ability to use discretion to the
disadvantage of competitors. The
Commission proposed three specific
areas for reform.
279. First, the Commission proposed
to require public utilities, working
through NERC, to modify the ATCrelated standards to incorporate a
requirement for periodic validation and
modification of models to ensure that
they are up to date.178 The Commission
stated that the models should be
updated and benchmarked to actual
events.
280. Second, the Commission
proposed that, to the maximum extent
practicable, the same data must be used
by the transmission provider to
determine short- and long-term ATC as
those used in system operation and
planning studies, respectively.
281. Third, the Commission proposed
that public utilities, working through
NERC, develop assumptions for use in
ATC determinations and that the
assumptions remain consistent among
transmission providers to the maximum
extent practicable. The Commission
indicated that short- and long-term ATC
calculations should be developed using
consistent assumptions regarding
representative load levels, generation
dispatch, transmission reservations and
counterflows, in addition to any other
modeling assumptions identified by
NERC. The Commission further
proposed that there should be a
consistent approach to the modeling of
load levels, a method established for
determining which generators should be
modeled in service (including guidance
on how independent generators should
be considered), consistency in the
simulation of power flows from points
of receipt to delivery when sources are
unknown, and consistency in the
manner in which ATC/AFC reservations
are accounted for. The Commission
stated that the model for long-term ATC
should include, to the maximum extent
practicable, the same assumptions
regarding new transmission and
generation facilities additions and
retirements as those used in planning
for expansion.
282. The Commission noted that the
proposal is not intended to change the
manner in which native load is served
178 The Commission noted that this would
include review of load flow base cases, short circuit
data, transient and dynamic stability simulation
data, contingency (files should contain information
on special protection schemes and remedial action
plans) subsystem and monitoring files, and
production cost models.
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and sought comment on whether (and,
if so, how) this proposal would affect
service to native load customers.
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Comments
283. Commenters generally discuss
consistency of data, assumptions and
modeling together so we in turn do the
same. Many commenters support the
proposals for consistency in data,
assumptions and/or modeling.179 Others
support flexibility or regional
variation.180 A few commenters oppose
specific aspects of the overall
proposal.181
284. TDU Systems and Sacramento
express support for the Commission’s
proposal to require public utilities,
working through NERC, to develop
modeling assumptions for use in
calculating ATC that are consistent with
those used to plan the operation and
expansion of the transmission system.
Xcel, however, would have the
Commission go further. Xcel
recommends that the Commission
enhance its proposal by establishing a
date certain for transmission providers
in the Western Interconnection to be
required to account for impacts of loop
flows when processing transmission
service requests and calculating ATC.
Xcel suggests that NERC be directed to
develop standards for evaluation of
counterflows on ATC. EPSA offers
examples of specific data inputs that, in
its view, should also be standardized
among all transmission providers,
which include: Load levels and
distribution studies; transmission
outages; generation outages; and
generation dispatch. Ameren submits
that any modeling of base generation
dispatch must model generators,
including merchant generators, as they
are expected to run.
285. Williams asks the Commission to
require consistency between
transmission planning horizon and
procurement terms, and transparency
around the long-term transmission
planning assumptions. Williams states
that third-party bids to a request for
proposals are evaluated with
transmission costs that may already be
included in long-term transmission
plans. Thus, argues Williams,
procurement and long-term planning
assumptions are intertwined. In reply,
Entergy acknowledges and agrees that
the models used for planning,
179 E.g., APPA, Arkansas Commission,
Constellation, Entegra, Exelon, EPSA, ISO/RTO
Council, LDWP, MidAmerican, Municipals,
NRECA, CREPC, Sacramento, Santee Cooper, Suez
Energy NA, TAPS, TDU Systems, WestConnect, and
Williams.
180 E.g., Bonneville. Santee Cooper, and Entergy.
181 E.g., PJM, EPSA, and Ameren.
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operations and service request
evaluations should generally be based
on similar data and procedures, but
argues that due to changes in system
configuration, facilities included in
transmission plans are often not needed
at all and thus are not constructed.
Therefore, Entergy proposes that the
Commission allow NERC to determine
the circumstances under which
differences between models would be
appropriate.
286. Southern asks for clarification on
what the Commission intends by
proposing that modeling assumptions be
consistent in the context of TTC
assessments. Southern explains that, as
the Commission has recognized, the
inevitable changes in system conditions
between different time horizons (e.g.,
real-time and planning and operations)
would render this approach unreliable
because load levels, dispatch
arrangements, reservations, and outages
cannot be the same over significantly
different time horizons.
287. Supporting regional differences,
Bonneville contends that calculating
ATC for a hydroelectric system requires
different inputs and modeling
assumptions than are appropriate for
thermal-based systems. Bonneville
explains that non-power constraints
placed on hydroelectric projects that
were built for multiple uses are a major
concern on the Bonneville system.
Consequently, hydro operators are more
limited in their ability to use generation
redispatch as a tool to meet long-term
firm load obligations. Similarly, Santee
Cooper cautions that overstandardization may result in certain
parameters being misstated or
inappropriately constrained, resulting in
inaccurate reservations of capacity for
native load purposes and a potentially
detrimental effect on the reliability of
service. It recommends that the
Commission direct NERC to allow
deviations from the standard modeling
assumptions where the need can be
supported, with the caveat that a
utility’s modeling assumptions must be
transparent and available for scrutiny.
Seattle contends that modeling
assumptions should be developed at the
sub-regional level, consistent among
adjacent transmission providers. TVA
suggests that the transmission providers
be allowed to retain flexibility to
conduct risk analyses and reflect those
in their modeling assumptions.
288. Other commenters argue that
modeling assumption standardization
should not be performed by NERC and,
instead, should be delegated to the
regional reliability organizations or
RTOs, as they possess a superior
knowledge of the physical grid within
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their boundaries.182 PJM states that such
issues are best left to the joint
stakeholder processes and the resulting
joint and common market initiatives.
289. In response to the Commission’s
inquiry as to how standardizing the
modeling assumptions and data would
affect native load, commenters generally
state that standardization of ATC
modeling assumptions would increase
comparability of service to LSEs and
enhance the ATC methodology and its
nondiscriminatory application to grid
utilization.183
Commission Determination
290. The Commission directs public
utilities, working through NERC, to
modify the reliability standards MOD–
010 through MOD–025 184 to incorporate
a requirement for the periodic review
and modification of models for (1) Load
flow base cases with contingency,
subsystem, and monitoring files, (2)
short circuit data, and (3) transient and
dynamic stability simulation data, in
order to ensure that they are up to date.
This means that the models should be
updated and benchmarked to actual
events. We find that this requirement is
essential in order to have an accurate
simulation of the performance of the
grid and from which to comparably
calculate ATC, therefore increasing
transparency and decreasing the
potential for undue discrimination by
transmission providers.
291. We note that commenters
generally were very supportive of the
Commission’s proposals for review and
update of models and for consistency of
assumptions and data inputs. We
received no adverse comments
concerning our general proposal to
require public utilities, working through
NERC, to modify the ATC-related
standards to incorporate a requirement
for the periodic review and modification
of models to ensure that they are up to
date. Moreover, the need to improve the
quality of system modeling was one of
the U.S.-Canada Power System Task
Force recommendations.185
292. The Commission also adopts the
NOPR proposal to require transmission
providers to use data and modeling
assumptions for the short- and longterm ATC calculations that are
consistent with that used for the
182 E.g., Sacramento, Manitoba Hydro, Nevada
Companies, and TANC.
183 E.g., Sacramento.
184 The MOD–010 through MOD–025 reliability
standards establish data requirements, reporting
procedures, and system model development and
validation for use in the reliability analysis of the
interconnected transmission systems.
185 Final Report on the August 14, 2003 Blackout
in the United States and Canada: Causes and
Recommendations.
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planning of operations and system
expansion, respectively, to the
maximum extent practicable. This
includes, for example: (1) Load levels,
(2) generation dispatch, (3) transmission
and generation facilities maintenance
schedules, (4) contingency outages, (5)
topology, (6) transmission reservations,
(7) assumptions regarding transmission
and generation facilities additions and
retirements, and (8) counterflows. We
find that requiring consistency in the
data and modeling assumptions used for
ATC calculations will remedy the
potential for undue discrimination by
eliminating discretion and ensuring
comparability in the manner in which a
transmission provider operates and
plans its system to serve native load and
the manner in which it calculates ATC
for service to third parties. The
Commission directs public utilities,
working through NERC, to modify ATC
standards to achieve this consistency.
293. With regard to EPSA’s request for
the standardization of additional data
inputs, we believe they are already
captured in the Commission’s proposal
as adopted in this Final Rule. Xcel asks
the Commission to require consistency
in the determination of counterflows in
the calculation of ATC. Counterflows
are included in the list of assumptions
that public utilities, working through
NERC, are required to make consistent.
We believe that counterflows, if treated
inconsistently, can adversely affect
reliability and competition, depending
on how they are accounted for.
Accordingly, we reiterate that public
utilities, working through NERC and
NAESB, are directed to develop an
approach for accounting for
counterflows, in the relevant ATC
standards and business practices. We
find unnecessary Xcel’s request that we
require a date certain for specific issues
in the Western Interconnection to be
addressed. Above we require public
utilities, working through NERC, to
modify the ATC standards within 270
days after the publication of the Final
Rule in the Federal Register.
294. With regard to Williams’ request
that the Commission require
consistency between transmission
planning horizons and procurement
terms, we believe that such an express
requirement is neither appropriate nor
necessary. The manner in which
transmission providers procure power
for native load customers is generally
outside the scope of this rulemaking.
This notwithstanding, we note that by
this Final Rule, Williams and other
affected market participants will have
an opportunity to participate in a
transmission provider’s coordinated,
regional planning process. This will
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provide a vehicle for interested parties
to gain access to planning-related
information and to have their own plans
for transmission evaluated at the same
time the transmission provider plans for
its needs. Coupled with the
modifications to the ATC-related
reliability standards that require the
same data and assumptions to be used
for calculating long-term ATC as in
system planning, these reforms are
adequate to address Williams’ concern.
To the extent there are changes on the
system, these should be captured in the
regional transmission planning process
and in the determination of ATC. We
therefore reject Entergy’s proposal to
allow NERC to determine the
circumstances under which differences
between models would be appropriate
in order to ensure comparable service
for all transmission customers.
295. We offer the following
clarifications. In response to Southern,
we clarify that we require consistent use
of assumptions underlying operational
planning for short-term ATC and
expansion planning for long-term ATC
calculation. We also clarify that there
must be a consistent basis or approach
to determining load levels. For example,
one approach may be for transmission
providers to calculate load levels using
an on- and off-peak model for each
month when evaluating yearly service
requests and calculating yearly ATC.
The same (peak- and off-peak) or
alternative approaches may be used for
monthly, weekly, daily and hourly ATC
calculations. Regardless of the ultimate
choice of approach, it is imperative that
all transmission providers use the same
approach to modeling load levels to
enable the meaningful exchange of data
among transmission providers.
Accordingly, we direct public utilities,
working through NERC, to develop
consistent requirements for modeling
load levels in MOD–001 for the services
offered under the pro forma OATT.
296. With respect to modeling of
generation dispatch, we direct public
utilities, working through NERC, to
develop requirements in NERC’s MOD–
001 reliability standard specifying how
transmission providers shall determine
which generators should be modeled in
service, including guidance on how
independent generation should be
considered. We agree with Ameren that
any modeling of base generation
dispatch must model generators,
including merchant generators, as they
are expected to run. Accordingly, we
direct public utilities, working through
NERC, to revise reliability standard
MOD–001 by specifying that base
generation dispatch will model (1) All
designated network resources and other
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12305
resources that are committed or have the
legal obligation to run, as they are
expected to run and (2) uncommitted
resources that are deliverable within the
control area, economically dispatched
as necessary to meet balancing
requirements.
297. Regarding transmission
reservations modeling, we direct public
utilities, working through NERC, to
develop requirements in reliability
standard MOD–001 that specify (1) A
consistent approach on how to simulate
reservations from points of receipt to
points of delivery when sources and
sinks are unknown and (2) how to
model existing reservations.
298. In response to commenter
requests in favor of flexibility and
regional differences, we again require
that any waivers from the approved
NERC reliability standards must take
place through the NERC reliability
standards process as a request for
regional difference. Also, we disagree
with commenters who argue that
modeling assumptions should be
delegated to regional reliability
organizations. The goal of this
rulemaking is to increase consistency in
ATC calculations and that is best
accomplished through NERC, which has
established processes to address
requests for regional differences from
the reliability standard requirements.
We conclude that the NERC process is
appropriate as it is open to all industry
participants and, therefore, is a suitable
arena for establishment of common
standards for modeling assumptions.
g. ATC Calculation Frequency
NOPR Proposal
299. The Commission proposed the
development of standards requiring that
the ATC calculation be performed with
consistent frequency among
transmission providers. Specifically, the
Commission proposed that transmitting
public utilities, working through NERC
and NAESB, develop standards
requiring that the calculation be
performed by all transmission providers
on a consistent time interval and in a
manner that closely reflects the actual
topology of the system, e.g., generation
and transmission outages, load forecast,
interchange schedules, transmission
reservations, facility ratings, and other
necessary data. The Commission also
supported uniform updating of ATC
values and its components (e.g., TTC,
ETC, CBM, and TRM).
Comments
300. Alcoa and Powerex emphasize
the critical need for ATC to be
calculated more frequently for
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constrained facilities. On constrained
paths, where transmission equipment is
stressed to its limits, Alcoa recommends
that ATC be calculated on an hourly or
real-time basis and be adjusted for
temperature extremes. Seattle comments
that ATC should be updated on a ‘‘by
exception’’ basis, i.e., when significant
model changes or confirmations of
service requests occur. While
supporting the Commission proposal,
TAPS cautions against updating ATC/
AFC too frequently, as this may play
into the hands of those who use
reservation computer programs.
Commission Determination
301. The Commission adopts the
NOPR proposal and requires the
development of reliability standards
that ensure ATC is calculated at
consistent intervals among transmission
providers. The Commission thus directs
public utilities, working through NERC
and NAESB, to revise reliability
standard MOD–001 to require ATC to be
recalculated by all transmission
providers on a consistent time interval
and in a manner that closely reflects the
actual topology of the system, e.g.,
generation and transmission outages,
load forecast, interchange schedules,
transmission reservations, facility
ratings, and other necessary data. This
process must also consider whether
ATC should be calculated more
frequently for constrained facilities.
ATC-related requirements for OASIS
posting are discussed below.
h. Data Exchange
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NOPR Proposal
302. The Commission proposed the
development through NERC of standard
protocols that would enable and require
the exchange of data and coordination
among transmission providers. The
Commission proposed that the
following data, at a minimum, be
exchanged among transmission
providers for the purposes of ATC
modeling: (1) Load levels; (2)
transmission planned and contingency
outages; (3) generation planned and
contingency outages; (4) base generation
dispatch; (5) existing transmission
reservations, including counterflows; (6)
ATC recalculation frequency and times;
and (7) source/sink modeling
identification. The Commission
expressed its view that significant
improvements in the communication,
coordination, and exchange of data
across all transmission providers in an
interconnection are needed to produce
accurate determinations of ATC. The
Commission sought comment as to how
much data sharing is workable, whether
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there are additional data that should be
provided, whether access to such data
should be limited to transmission
providers, and if there are existing
forums by which these or similar data
are already shared.
Comments
303. Most commenters support the
Commission’s proposal to establish
rules for data exchange, but express a
preference for confidential data
exchange.186 NERC states that proposed
changes to its existing modeling
standards would require transmission
providers to coordinate the calculation
of TTC/ATC/AFC with others. TVA
emphasizes that it has already
incorporated these principles into its
operating processes by executing
agreements that provide for data
exchange and coordination with
neighboring transmission systems.
304. PJM suggests that the data
exchange protocols be developed as
minimum requirements and not
interfere with existing protocols that
PJM has with neighboring control areas
under agreements such as the MISO/
PJM JOA.187 Similarly, SPP states that it
also has developed seams coordination
agreements with adjoining transmission
providers 188 that fully meet and, in
some cases exceed, the Commission’s
objective of fostering greater data
exchanges between transmission
providers.
305. MISO is concerned that the
NOPR does not address transparency
and regional coordination issues arising
at the seams between RTO and non-RTO
regions, particularly with respect to
ATC calculations. In MISO’s view, the
Commission-approved joint operating
agreements between various ISOs and
RTOs contain cutting edge ATC
calculation methodologies, while no
comparable common protocols have
evolved with non-RTO utilities. In its
186 E.g., Allegheny, Ameren, Arkansas Municipal,
Bonneville, Constellation, CAISO, Entergy, Exelon,
FirstEnergy, LPPC, MidAmerican, Santee Cooper,
Seattle, and TAPS.
187 Under the PJM/MISO Joint Operating
Agreement (JOA) and other operating agreements
modeled on that agreement, parties have developed
comprehensive data exchange protocols to facilitate
coordination and consistent AFC calculations.
Much of this data is supplied through industry
standard sources such as NERC SDX and NERC
eTags.
188 SPP has developed seams agreements to
exchange ATC data and coordinate congestion with
non-RTO neighbors such as the Southwest Power
Administration. Further, SPP exchanges ATC/AFC
data and coordinates planning, reserve sharing,
outage coordination, and transmission service
administration under a transmission coordination
agreement with Associated Electric Cooperative,
Inc. (AECI), an individual transmission provider
situated on SPP’s border that is not a member of
SPP or any other RTO.
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reply comments, Exelon agrees with
MISO that the various joint operating
agreements are not consistent. Exelon
proposes that the NERC standards
specify requirements for coordination
and the type of data that must be
exchanged and used for accurate ATC
calculations. Exelon contends that
having uniform standards for
coordination developed by NERC will
enhance efficiency throughout the
industry, particularly between and
among RTO and non-RTO areas.
MidAmerican reiterates that ATC
coordination remains an issue for RTOs
and that any improvements in ATC
coordination resulting from this
proceeding must apply to the OATTs of
RTOs and non-RTOs alike.
306. NAESB states that coordination
and data exchange may require business
practices for existing transmission
reservations, including counterflows,
ATC calculation frequency, and source/
sink modeling identification. Some
commenters request that the
Commission clarify that only
information necessary for purposes of
ATC modeling needs to be
exchanged.189 In particular, they
propose that proprietary generation or
market information data that might
harm their competitive position should
not be publicly disseminated since that
would not enhance the ability of
transmission providers to accurately
calculate ATC.
307. While acknowledging these
confidentiality and commercial
sensitivity concerns, other commenters
recommend that the availability of
shared data not be limited to
transmission providers.190 For example,
TAPS explains that transmission
dependent utilities need an opportunity
to access the data periodically as a
check on the process. To address
confidentiality or standards of conduct
concerns, TAPS proposes that
transmission dependent utilities’ access
to data could be achieved through an
employee barred from disclosing
information to marketing staff or a third
party independent consultant retained
by the transmission dependent utility.
However, APPA and Seattle urge the
Commission to eliminate artificial and
institutional barriers to the exchange of
data and information.
308. APPA and Seattle also contend
that, even if data were openly available,
the vast quantities of hourly data points
are difficult to manage, process and
analyze using existing methods. To
address this issue, APPA recommends
189 E.g., Allegheny, Constellation, and
Indianapolis Power.
190 E.g., APPA, Bonneville, TAPS, and Seattle.
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that the Commission encourage ongoing
efforts to obtain greater resolution of
system-model State variables,
contractual uses and probabilistic
ranges and to refine data management
and analytical methods.
309. New York Commission suggests
having an overarching entity, such as a
Transmission Oversight Center, that is
responsible for calculating and
coordinating ATC between various
ISOs/RTOs could overcome this lack of
data.
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Commission Determination
310. The Commission adopts the
NOPR proposal and directs public
utilities, working through NERC, to
revise the related MOD reliability
standards to require the exchange of
data and coordination among
transmission providers and, working
through NAESB, to develop
complementary business practices. The
following data shall, at a minimum, be
exchanged among transmission
providers for the purposes of ATC
modeling: (1) Load levels; (2)
transmission planned and contingency
outages; (3) generation planned and
contingency outages; (4) base generation
dispatch; (5) existing transmission
reservations, including counterflows; (6)
ATC recalculation frequency and times;
and (7) source/sink modeling
identification. The Commission
concludes that the exchange of such
data is necessary to support the reforms
requiring consistency in the
determination of ATC adopted in this
Final Rule. As explained above,
transmission providers are required to
coordinate the calculation of TTC/TFC
and ATC/AFC with others and this
requires a standard means of exchanging
data.
311. While there is a near consensus
among commenters that significant
improvements in the communication,
coordination, and exchange of data
across all transmission providers are
needed to produce accurate
determinations of ATC, we acknowledge
the concerns of ISO/RTOs that new data
exchange protocols may interfere with
the existing protocols and seams
coordination agreements. Although we
will not provide a blanket exemption for
ISOs and RTOs from meeting or
exceeding the data exchange
requirements of this Final Rule, they
may, as explained in section IV.C.2,
demonstrate in relevant filings that their
existing data exchange protocols are
consistent with or superior to those that
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are developed in the NERC and NAESB
processes.191
312. With respect to concerns
regarding the exchange of data that may
be a subject of confidentiality and
commercially sensitive, we only require
information necessary for purposes of
ATC modeling to be exchanged. As
suggested by some commenters,
proprietary generation or market
information data that might harm a
competitive position should not be
publicly disseminated, since that would
not enhance the ability of transmission
providers to accurately calculate ATC. If
any of the data are subject to
confidentiality and are commercially
sensitive, they must be disclosed in
accordance with a confidentiality
agreement.
2. Transparency
a. OATT Transparency
(1) Attachment C
NOPR Proposal
313. In the NOPR, the Commission
proposed to require each transmission
provider to include in Attachment C of
its OATT more descriptive information
concerning its ATC/AFC calculation
methodology. Specifically, the
Commission proposed to require the
transmission provider to state its
specific mathematical algorithm used to
calculate firm and non-firm ATC/AFC
for its scheduling horizon, operating
horizon, and planning horizon. The
Commission also proposed to require
transmission providers to provide a
process flow diagram that illustrates the
various steps through which ATC/AFC
is calculated. In addition, the
Commission proposed to require
transmission providers to provide
definitions and explain in detail how
TTC, ETC, AFC, TRM, and CBM are
calculated for both operating and
planning horizons.
Comments
314. Most commenters support the
Commission’s overall proposal on
transparency in ATC calculations.192
Numerous commenters support the
191 We are not requiring that every transmission
provider follow identical protocols. Rather, all
transmission providers must meet the relevant
NERC reliability standards and NAESB business
practices, and each entity will be subject to
reliability standards compliance audits through
which they will have to demonstrate that they meet
or exceed the reliability standards.
192 E.g., Alberta Intervenors, AWEA, Bonneville,
CAISO, Constellation, Duke, East Texas
Cooperatives, ELCON, Entergy, Entegra, EPSA,
E.ON, Exelon, MidAmerican, Morgan Stanley,
Municipals, Nevada Companies, NPPD, PGP, PJM,
Powerex, CREPC, Santee Cooper, TVA, TAPS, and
TDU Systems.
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12307
Commission’s proposal to require
detailed information in Attachment C
regarding the transmission provider’s
ATC/AFC calculation methodology.193
Barrick agrees in its reply comments
that a thorough explanation of how ATC
is calculated should be made readily
available either in the transmission
provider’s OATT or on its OASIS,
thereby improving transparency and
making it less difficult for customers to
determine whether the calculations are
unduly discriminatory. Old Dominion
calls for greater transparency in the
details of calculating ATC, even as
applied to RTOs such as PJM because of
the relevance of ATC at the borders of
an RTO/ISO and the market impact of
inconsistencies in definitions, data,
modeling assumptions and frequency of
ATC calculations. NERC states that the
revised NERC reliability standards will
address transparency.
315. NARUC contends that
understanding ATC calculation
methodologies and having access to the
underlying data is essential to a range of
critical State commission functions and,
therefore, greater transparency of ATC
information will significantly enhance
State commissions’ abilities to fulfill
their statutory obligations. On reply,
North Carolina Agencies agree with
NARUC and state that efforts aimed at
increased transparency of ATC
calculations should help uncover any
actual discriminatory behavior by
transmission providers, provide a
clearer standard against which to
evaluate claims of unduly
discriminatory activities, and facilitate
regional planning efforts. Entegra states
on reply that transmission providers
should be required to post narratives
explaining changes in models and
factors underlying ATC and AFC values,
which would be invaluable to the
Commission and customers in
identifying problems that may warrant
enforcement actions.
316. While APPA generally supports
the Commission’s proposal, some of
APPA’s members along with other
commenters express concern that
including all the information might be
too burdensome and result in numerous
tariff changes.194 Some APPA members
in the West also express concerns about
the competitive implications of
193 E.g., Arkansas Municipal, Arkansas
Commission, CAISO, Constellation, ELCON,
Entergy, ISO New England, Morgan Stanley,
NARUC, Nevada Companies, Occidental, PJM,
Powerex, Project for Sustainable FERC Energy
Policy, Santee Cooper, and Suez Energy NA.
194 E.g., EEI, PNM–TNMP, Sacramento, Seattle,
and Southern.
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providing such confidential and
sensitive information.
317. EEI also notes that providing
additional detailed information in
Attachment C would be duplicative and
may result in confusion due to
inconsistencies between the wording of
the NERC and NAESB ATC documents
and each transmission provider’s
Attachment C. To avoid uncertainty, EEI
recommends that the Commission
require transmission providers to
comply with the requirements of
Attachment C by referencing NERC
reliability standards or business
practices that provide the information
that is called for in the Attachment.
MidAmerican believes that additional
information concerning calculating ATC
and its components would best be
retained in the transmission provider’s
business practices rather than
Attachment C. In its reply comments,
Powerex suggests an alternative of
permitting transmission providers to
provide a general reference to NERC,
WECC, or NAESB standards and fully
outline core definitions, processes, data
and assumptions when deviating from
such standards.
318. Southern contends that the
transparency concerns expressed in the
NOPR are driven more by the
complexity and volume of the data
involved rather than a lack of
information. Southern suggests that
sufficient information is readily
available and the best course of action
by the Commission would be to focus
on documenting transfer capability
methodologies available to transmission
customers. NRECA replies that many
commenters provided input into why
more transparency is needed and
repeats the example provided in its NOI
comments of a cooperative that spent
many months in discussions with a
public utility transmission provider in
an effort to understand ATC-related
information posted on OASIS.
319. Pinnacle contends that the
Commission’s proposal for detailed
information in Attachment C is only
relevant in flow-based systems, pointing
out that in the Western Interconnection,
the scheduling horizon, and the
operating horizon are the same and thus
reporting such information is not
necessary. APPA and Bonneville believe
that adding such detail in Attachment C
may only result in incremental changes
and suggest that better regional
coordination would provide greater
transparency.
320. Though ISO New England
believes this proposal would not create
an undue burden, it urges the
Commission to allow for variety in the
illustration of the process flow diagram.
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Regarding the proposal to require a
‘‘detailed explanation’’ of the
calculation of ATC, TTC, ETC, and TRM
components, ISO New England argues
that the relevant inputs can change on
a daily basis because ATC for Pooled
Transmission Facilities (PTF) in New
England is a function of market
conditions, as opposed to an
administratively-derived calculation. In
ISO New England’s view, the level of
detail required should reflect the
operation of competitive markets. MISO
is concerned that the NOPR does not
address transparency and regional
coordination issues arising at the seams
between market and non-market areas,
particularly with respect to ATC
calculations.
321. MidAmerican strongly urges the
Commission to ensure that non-public
utility transmission providers adhere to
the transparency requirements, since in
the Pacific Northwest many of the
‘‘backbone’’ transmission lines are coowned by jurisdictional and
nonjurisdictional entities. A
jurisdictional co-owner may be limited
in its ability to determine such
parameters as TRM and CBM because it
may not be the line operator. LPPC, in
its reply comments, believes it is
unnecessary and redundant to require
non-public utility transmission
providers to adopt the ATC
requirements of the pro forma OATT,
because the Commission recognizes in
the NOPR that NERC and NAESB are
currently drafting standards for ATC,
which when final will be filed with the
Commission and become part of the
ERO’s mandatory reliability standards
and fully applicable to otherwise
nonjurisdictional entities.
322. Suez Energy NA contends that it
is essential that the Commission include
an explanation of each component of
the ATC calculation in Attachment C to
ensure that the transmission provider
incorporates NERC standards
appropriately and to ensure proper
enforcement in the event that an audit
shows that the transmission provider
has employed other methods of
calculating ATC. Suez Energy NA also
notes that the mathematical algorithms
and process flow diagrams should be
provided to users of the transmission
system, independent monitors,
transmission coordinators and
regulators, even if a confidentiality
agreement is required. APPA suggests
that the Commission and regional
reliability organizations conduct
additional audits to ensure that these
posted practices and procedures are in
fact being followed, and that the data
used are verifiable.
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Commission Determination
323. The Commission adopts the
NOPR proposal to increase transparency
regarding ATC calculations by requiring
each transmission provider to set forth
its ATC calculation methodology in its
OATT. Each transmission provider
must, at a minimum, include the
following information in Attachment C
to its OATT. It must clearly identify
which of the NERC-approved
methodologies it employs (e.g., contract
path, network ATC, or network AFC). It
also must provide a detailed description
of the specific mathematical algorithm
the transmission provider uses to
calculate firm and non-firm ATC for the
scheduling horizon (same day and realtime), operating horizon (day ahead and
pre-schedule), and planning horizon
(beyond the operating horizon). In
addition, transmission providers must
include a process flow diagram that
describes the various steps that it takes
in performing the ATC calculation.
Furthermore, transmission providers
must set forth a definition of each ATC
component (i.e., TTC, ETC, TRM, and
CBM) and a detailed explanation of how
each one is derived in both the
operating and planning horizons.
Requiring transmission providers to file
a statement of their ATC calculation
methodology along with a process flow
diagram and more detailed definitions
of ATC components in Attachment C of
the OATT will provide greater
transparency to transmission customers
and assist in identifying any
discrepancies that may arise in ATC
determinations. These new
requirements will assist in alleviating
any appearance of discrimination in the
determination of ATC.
324. The Commission acknowledges
NARUC’s comments that understanding
ATC methodologies and the underlying
data also will enhance State regulators’
ability to meet their regulatory
obligations. More transparent ATC
calculations are critical to coordinated
regional transmission planning that
ultimately will improve transmission
access for customers and enhance grid
reliability. Transparent ATC
calculations facilitate the ability of
market participants and regulators to
detect discrimination.
325. We do not believe our
requirement to include additional
information in Attachment C will be
overly burdensome or lead to an
excessive level of future tariff revisions.
Attachment C must provide an accurate
documentation of processes and
procedures related to the calculation of
ATC, not the actual mathematical
algorithms themselves, which should be
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posted on the transmission provider’s
Web site. These processes define service
availability and, as such, must be part
of the transmission provider’s OATT. It
is entirely appropriate that, because
revisions to such processes impact
transmission availability, they should be
filed for Commission approval and
included in a transmission provider’s
OATT. We also require transmission
providers to file a revised Attachment C
to incorporate any changes in NERC’s
and NAESB’s revised reliability
standards and business practices related
to ATC calculations, as requested by the
Commission in this Final Rule. This
filing should be made within 60 days of
completion of the NERC and NAESB
processes. As we expect transmission
providers to rarely change their ATC
calculation methodologies, we do not
believe this requirement will trigger an
unacceptable level of tariff filings
modifying the Attachment C description
of the ATC components and processes.
326. We agree with ISO New England
that the process flow diagram
requirement may be met with a variety
of illustrations, so long as it is of
sufficient detail to provide the
transmission customer with a
reasonable understanding of the
transmission provider’s ATC calculation
processes. The process flow diagram
should support the other Attachment C
requirements. As noted above, we agree
with Suez Energy NA that mathematical
algorithms and process flow diagrams
should be made available. We do not
find that a confidentiality agreement is
generically warranted; however, we note
that, a transmission provider may
require a confidentiality agreement for
CEII materials, consistent with our CEII
requirements, or may otherwise protect
the confidentiality of proprietary
customer information.
327. We also require transmission
providers to document their processes
for coordinating ATC calculations with
their neighboring systems. This
requirement is particularly important
with respect to seams between market
and non-market areas, as identified by
MISO, and with respect to the request
of other commenters to increase regional
coordination regarding ATC calculation.
While this Final Rule does not address
all seams issues between market and
non-market areas, it does take important
steps towards that end by improving
data exchange between transmission
providers and providing increased
transparency with respect to ATC
calculation.
328. We reject proposals to address
the transparency of ATC methodology
by merely referencing business practices
and reliability standards developed by
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NERC, NAESB, and WECC.195 ATC
calculations have a direct and tangible
effect on the granting of open access
transmission service.196 As such, an
accurate and detailed statement of the
methodology and its components that
defines how the transmission provider
determines ATC belongs in the
transmission provider’s OATT as the
means of holding the transmission
provider accountable for following nondiscriminatory procedures for granting
service, not in business practices kept
by the transmission provider.197
However, as noted above, the actual
mathematical algorithms should be
posted on the transmission provider’s
web site, with the link noted in the
transmission provider’s Attachment C.
329. We also reject Pinnacle’s
assertion that more detailed information
in Attachment C would only apply to
flow-based systems. Regardless of what
type of ATC calculation methodology is
employed, transparency in ATC
calculations is critical to avoid undue
discrimination when allocating
transmission capacity under the pro
forma OATT.
330. In response to MidAmerican’s
comments regarding the applicability of
the ATC-related reforms to non-public
utilities, we again refer to section IV.C.3
where we discuss this issue generally.
We note here, however, that the ERO’s
reliability standards currently in
development before the Commission
will be applicable to all users, owners
and operators of the bulk electric grid,
which includes non-public utilities.
331. We do not believe ATC-specific
tariff audits are necessary to order at
this time. The Commission will
continue to provide oversight of all
tariff-related activities through its
enforcement program. Moreover, ATC
requirements will be part of the
mandatory and enforceable reliability
standards and, as such, will be subject
to compliance audits through that
process.
195 WECC has on file a Reliability Management
System agreement under which transmission
providers agreed, through contracts, to follow
WSCC reliability criteria. Western Systems
Coordinating Council, 87 FERC ¶ 61,060 (1999).
196 The Commission recognized in Order No. 889
that the methodology for calculating ATC and TTC
belongs in the tariff. Order No. 889 at 31,607. At
the time, the industry represented that it was
engaged in efforts to develop uniform methods of
determining ATC. The Commission encouraged
such industry efforts and required that the tariff
include the methodology, which was to be based on
current industry practices, standards and criteria.
197 For the same reason, the Commission
disagrees with the assertions of Southern and EEI
that more information in Attachment C would be
duplicative because some ATC-related information
is already available elsewhere.
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12309
(2) CBM Practices
NOPR Proposal
332. In the CBM Order, the
Commission required transmission
providers to post a specific narrative
explanation of their CBM practices.198
In addition, the Commission directed
transmission providers to post their
procedures for allowing access to CBM
during emergencies. The Commission
further stated in the CBM Order that, if
a utility’s practice was not to set aside
transfer capability as CBM, it should
reflect that in Attachment C.
333. In the NOPR, the Commission
proposed to require transmission
providers to include this CBM narrative
in Attachment C of their OATTs. In
addition, the Commission proposed that
transmission providers explain their
definition of CBM, list the databases
used in their CBM calculations, and
prove that there is no double-counting
of contingency outages when
performing CBM calculations.
Comments
334. Seattle and Suez Energy NA
support this proposal. Seattle states that
CBM information should be specified in
Attachment C in order to provide clear
guidance for the specific information
that is posted on OASIS. Seattle and
APPA suggest that CBM should be
verifiable and subject to audit by
independent parties such as regional
reliability organizations.
335. EEI suggests that the Commission
revise Attachment C, section 3(f) to
replace the word ‘‘prove’’ with the word
‘‘demonstrate’’ in the requirement that
the transmission provider ‘‘prove’’ that
it does not double count contingency
outages when calculating CBM, TTC
and TRM. EEI notes that the term
‘‘prove’’ implies a determination on the
merits after evaluation of competing
arguments and evidence. A transmission
provider should be able to satisfy its
obligations by ‘‘demonstrating’’ the
absence of a double count. Any
customer that wishes to challenge the
demonstration can do so, at which time
the issue of ‘‘proof’’ would arise.
336. With regards to ‘‘double
counting,’’ TVA references TRM and
agrees that additional explanations
regarding the calculation of TRM,
including methods used to avoid double
counting contingency events, should
improve transparency in providing open
access transmission service. TVA points
out that this is being addressed by a
NERC standards drafting team.
198 Capacity Benefit Margin in Computing
Available Transmission Capacity, 88 FERC ¶ 61,099
(1999) (CBM Order).
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Commission Determination
337. The Commission adopts the
NOPR proposal requiring additional
information in the transmission
provider’s OATT Attachment C
regarding its determination of CBM.
Transmission providers must provide in
Attachment C a narrative description
detailing their CBM practices. In
addition, a transmission provider must
explain its definition of CBM and list
the databases used to derive its value.
These new requirements will provide
transmission customers transparency
into the CBM component of ATC and
help discourage the potential for undue
discrimination in the calculation and
use of CBM.
338. We adopt EEI’s proposal that the
Commission revise Attachment C,
section 3(f) to replace the word ‘‘prove’’
with the word ‘‘demonstrate.’’ The word
‘‘demonstrate’’ more accurately
describes the showing we expect the
transmission provider to make. We
agree that the word ‘‘prove’’ implies a
standard of proof that we did not intend
to impose. We also acknowledge TVA’s
comments that the NERC standards
drafting team is developing standards
that should address ‘‘double counting’’
in ATC calculations in general.
However, we require that the
information in Attachment C be
sufficient to demonstrate that a
transmission provider is not double
counting CBM in its ATC calculation.
339. Finally, the Commission rejects
the proposal by Suez Energy NA, APPA,
and Seattle to establish formal audits of
CBM set asides. Requirements for CBM
will be part of the mandatory and
enforceable reliability standards and, as
such, will be subject to compliance
audits through that process. Moreover,
the Commission provides oversight of
all tariff-related activities through its
enforcement program.
b. OASIS
sroberts on PROD1PC70 with RULES
(1) ATC/TTC Posting Requirements
NOPR Proposal
340. The Commission’s existing
regulations require certain ATC-related
information to be posted on each
transmission provider’s OASIS and
other information to be provided on
request. To ensure that relevant
information is available on a timely
basis to all market participants, the
Commission proposed in the NOPR to
amend its regulations to allow potential
customers greater access to information
that will enable them to obtain service
on a non-discriminatory basis from any
transmission provider.
341. The Commission noted in the
NOPR that existing regulations require
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ATC and TTC calculations to be
performed according to consistently
applied methodologies referenced in the
transmission provider’s OATT and
current industry practices, standards
and criteria. The Commission proposed
that these calculations be based on the
ERO reliability standards.
342. The Commission further
proposed to maintain the requirement
that transmission providers provide, on
request, all data used to calculate ATC
and TTC for any constrained paths.
Transmission providers also would
remain required, on request, to make
publicly available any system planning
studies or specific network impact
studies performed for customers and to
post a list of such studies on OASIS.
Comments
343. Several commenters support the
proposal to post ATC-related
information on OASIS.199 TDU Systems
supports each of the Commission’s
proposals with respect to providing
easier access to data underlying ATC
calculations and greater transparency to
the process. Sacramento states that
posting on OASIS will ensure proper
public access, but will avoid the need
for Commission approval of an OATT
change.
344. Constellation strongly supports
the need for additional transparency,
stating that providing transmission
customers with meaningful insight into
the current ‘‘black box’’ determination
of ATC will help minimize the mystery
underlying many transmission provider
responses to service requests. According
to Constellation, further transparency
will assist customers in predicting the
outcome of transmission service
requests and facilitate increased
commercial activity. Constellation
suggests that the Commission require
transmission providers to provide
transmission customers, on request,
with specific details related to modeling
data, modeling support information,
modeling benchmarking and forecasting
data, and transmission service request
audit data. It requests that the
information be in a form and format
usable by the transmission customers
and that the Commission take steps to
ensure that transmission customers
understand how ATC is calculated and
the data inputs are used to affect those
calculations.
345. Great Northern likewise requests
that the Commission enhance the
requirement to provide all data on
request, specifically on constrained
199 E.g., APPA, Constellation, FirstEnergy,
Indianapolis Power, Sacramento, Suez Energy NA,
TAPS, and TDU Systems.
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paths, by requiring a posted tabulation
of annual and monthly ATC calculation
details. Great Northern suggests
including TTC, network load for each
transmission customer, capacity
reserved for each network resource,
each point-to-point transmission service
reservation, CBM and other deductions
from TTC.
346. APPA members support the
posting of ATC information, as it will
assist in using ATC more efficiently,
and they support the posting of system
planning studies and specific network
impact studies that the transmission
provider performs for its own merchant
function, as well as studies performed
for customers. In addition, APPA
suggests the posting of facilities studies
at the time they become available,
assuming that this can be done
consistent with CEII concerns. TAPS
goes further by urging the Commission
to close gaps in the current OASIS
requirements by requiring posting of all
studies performed for transmission
owners’ own transmission network
resource designations and other uses of
the system, including facilities studies
as well as system impact studies,
ensuring posted study lists are updated
contemporaneously with the availability
of new studies, and requiring retention
of studies for a minimum of five years.
347. Nevada Companies and TVA
support cost effective measures that
increase transparency in transmission
operations and, unless the requirement
becomes unduly time consuming or
burdensome, in general support more
disclosure rather than less.
Commission Determination
348. The Commission adopts the
proposal in the NOPR to continue to
require transmission providers to
comply with existing ATC-related
posting obligations as supplemented by
this Final Rule. The Commission will
continue to require transmission
providers, on request, to make available
all data used to calculate ATC and TTC
for any constrained paths and any
system planning studies or specific
network impact studies performed for
customers. Transmission providers must
also continue to post a list of such
studies on OASIS.
349. In addition, we agree with the
requests of APPA and TAPS to require
the additional posting of, at a minimum,
a listing of all system impact studies,
facilities studies, and studies performed
for the transmission provider’s own
network resources and affiliated
transmission customers, to be made
available upon request. We note that
appropriate procedures to accommodate
CEII concerns should be developed to
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ensure eligible entities with a legitimate
interest in transmission study data can
receive access to it. Also, we adopt
TAPS’ suggestion that the studies be
made available for five years to make
the requirement consistent with data
retention requirements pertaining to
denial of service requests.
350. The Commission rejects
Constellation’s and Great Northern’s
proposals to require transmission
providers to provide upon request or
regularly post additional information
beyond that required in the regulations
and this Final Rule. The transmission
provider is already required to make
available, upon request and in
electronic format, all information
related to the calculation of ATC and
TTC for any constrained path.
Accordingly, we see little benefit to
require transmission providers to
provide upon request or regularly post
additional information suggested by
these commenters.
information. Bonneville indicates that it
currently posts TRM values in its
Business Practices Forum, which is
useful for examining curtailment events,
supporting transmission planning
objectives, and validating posted ATC
values.
353. EPSA also recommends that the
Commission provide guidance on
standards that should be developed to
require each transmission provider to
notify the Commission in writing and
post a notice on its OASIS within 24
hours of a transmission provider’s use of
CBM to import emergency power. EPSA
also requests that the amount of CBM
reserved for each interface be posted on
OASIS.
Commission Determination
NOPR Proposal
351. The Commission’s OASIS
regulations currently require
transmission providers to calculate and
post ATC and TTC for each posted path,
but make no requirement for CBM and
TRM postings. In the CBM Order,
however, the Commission required
transmission providers, with respect to
each path for which the utility already
posts ATC, to post (and update) the
CBM figure for that path. The
Commission also required transmission
providers to make any transfer
capability set aside for CBM available
on a non-firm basis and to post this
availability on OASIS. In the NOPR, the
Commission proposed to incorporate
these CBM posting requirements into its
regulations. The Commission also
proposed that transmission providers
post (and update) the TRM values for
the paths on which the transmission
provider already posts ATC, TTC, and
CBM.
Comments
352. Several commenters strongly
support the Commission’s proposal to
require transmission providers to post
TRM and CBM.200 APPA and EPSA
agree that the posting of TRM for near
term transmission services would
provide greater assurance that ATC
calculations are being performed
according to established procedures.
Since transmission providers already
have this information, FirstEnergy states
that it does not appear to be unduly
burdensome for them to post such
354. The Commission adopts the CBM
posting requirements proposed in the
NOPR. In doing so, we amend our
OASIS regulations to incorporate the
directives established in the CBM Order.
Accordingly, we require transmission
providers to post (and update) the CBM
amount for each path. In addition, the
Commission requires transmission
providers to make any transfer
capability set aside for CBM but unused
for such purpose available on a non-firm
basis and to post this availability on
OASIS. Furthermore, the Commission
requires transmission providers to post
(and update) the TRM values for the
paths on which the transmission
provider already posts ATC, TTC, and
CBM.
355. We reject EPSA’s request to
require transmission providers to notify
the Commission in writing and post a
notice on OASIS within 24 hours of a
transmission provider’s use of CBM to
import emergency power and transfer
capability set aside as CBM at each of
the transmission provider’s interfaces.
The additional transparency of CBMrelated information provided in this
Final Rule, along with the reforms
related to consistency of CBM, will
cause sufficient information to be made
available to customers concerning the
use of CBM. The use and allocation of
CBM and TRM will be more transparent
to transmission customers, thus
reducing the potential for undue
discrimination.
(3) Periodic Reevaluation of the CBM
Set-Aside
sroberts on PROD1PC70 with RULES
(2) CBM/TRM Posting Requirements
200 E.g.,
Powerex, PJM, PPL, Seattle, and Pinnacle.
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NOPR Proposal
356. In the CBM Order, the
Commission stated that the level of ATC
set aside for CBM can and should be
reevaluated periodically to take into
account more certain information (such
as assumptions that may not have, in
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12311
fact, materialized).201 The Commission
therefore directed transmission
providers to periodically reevaluate
their generation reliability needs so as to
make known the availability of CBM
and to post on OASIS their practices in
this regard.202 In the NOPR, the
Commission proposed to incorporate
these requirements in the Commission’s
regulations and to obligate transmission
providers to reevaluate the CBM setaside at least quarterly.
Comments
357. Some commenters support
quarterly reevaluation of CBM setasides.203 TAPS agrees with the need for
full transparency of CBM reservations
and practices and states that, because
CBM values may differ from season to
season, CBM values should be
separately calculated for at least each
quarter. However, TAPS does not find
that it is necessary or appropriate for the
CBM values to be reevaluated quarterly,
given the effort involved in collecting
the data and performing the modeling
analysis. Rather, CBM studies should be
performed at least every other year,
supplemented with ‘‘off-year studies’’
when appropriate.
Commission Determination
358. The Commission incorporates
into its regulations the requirement in
the CBM Order for a transmission
provider to periodically reevaluate its
transfer capability set-aside for CBM.
With respect to TAPS’ concerns over the
effort involved in the re-evaluation
process, we will require CBM studies to
be performed at least every year. This
requirement is consistent with the CBM
Order, in which the Commission stated
that the level of ATC set aside for CBM
should be reevaluated periodically to
take into account more certain
information (such as assumptions that
may not have, in fact, materialized).204
While changes requiring a reevaluation
of CBM are longer-term in nature (e.g.,
installation of a new generator or a longterm outage), quarterly may be too
frequent, though two years may be too
long and may prevent a portion of the
CBM set-aside from being released as
ATC. Moreover, annual reevaluation is
consistent with the current NERC
standard being developed in MOD–
005.205 The requirement to evaluate
CBM at least every year also is
consistent with the CBM Order in that
201 CBM
Order at 61,237.
202 Id.
203 E.g., EPSA, Sacremento, Santa Clara, Suez
Energy NA, and TDU Systems.
204 CBM Order at 61,237.
205 The MOD–005 reliability standard establishes
the procedure for verifying CBM values.
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the Commission directed transmission
providers to periodically reevaluate
their generation reliability needs so as to
make known the need for CBM and to
post on OASIS their practices in this
regard.
(4) ATC/TTC Narrative Explanation
NOPR Proposal
359. In the NOPR, the Commission
proposed to largely retain existing
posting requirements for unconstrained
posted paths, but to amend the
regulations relating to data posted for
constrained posted paths. Existing
regulations require ATC and TTC on
constrained paths to be updated when
(1) Transactions are reserved, (2) service
ends, or (3) whenever the TTC estimate
for the path changes by more than 10
percent.206 In the NOPR, the
Commission proposed to supplement
the existing regulations by requiring the
transmission provider to post a brief,
but specific, narrative explanation of the
reason for the change at the time a
change in monthly and yearly ATC
values on a constrained path is posted.
The Commission sought comment on
whether the posting of this new
information would provide adequate
transparency to the customer on a
frequent enough basis without imposing
an undue burden on the transmission
provider. The Commission also sought
comment on whether a similar narrative
should be required when ATC remains
unchanged at a value of zero for some
specified period of time.
Comments
sroberts on PROD1PC70 with RULES
360. Some commenters support the
Commission’s proposal to require
transmission providers to post more
detailed explanations about changes in
ATC values on their OASIS sites.207
NAESB, TranServ, and Williams request
that the Commission clarify the
regulatory requirements for posting of
updated ATC values such as the level of
standardization, frequency and time of
postings, and other requirements.
CAISO believes that ATC should be
updated on a daily basis.
361. Powerex and Nevada Companies
propose that additional disclosures be
posted, such as data on grandfathered
contracts, time-specific data relevant to
transmission constraints and ATC rights
on posted paths, and remaining
customer rights under a reservationbased network service system.
206 See
18 CFR 37.6(b)(3)(i)(C).
Arkansas Commission, CAISO,
Constellation, East Texas Cooperatives, Exelon,
FirstEnergy, LPPC, Morgan Stanley, NRECA,
Pinnacle, Powerex, Santa Clara, and Suez Energy
NA.
362. A few commenters caution that
some of the data that the Commission is
requiring to be posted by transmission
providers is market-sensitive and, if
posted on a real-time basis, could be
used by third parties to obtain an unfair
competitive advantage.208 These
commenters propose that the
transmission providers should be
allowed a brief period of delay (e.g., one
week) before posting data. Indianapolis
Power also advocates a delay due to the
burden on transmission providers of the
new posting.
363. Several commenters oppose the
Commission’s proposal to require that
transmission providers post narratives
on OASIS outlining reasons why
monthly and yearly ATC values on
constrained paths change.209 These
commenters contend that this will cause
undue burden on transmission
providers without providing customers
with any significant or new information.
They also argue that the proposal is
impractical and will not result in
providing transmission customers with
meaningful information regarding
transmission service options.
364. If such a requirement is adopted,
MISO recommends that a threshold
higher than a 10 percent change in ATC
be established and that the Commission
clarify what the term ‘‘specific
explanation’’ means in this context. PJM
states that it already exceeds the
Commission’s proposed requirement.
However, if strictly applied, this
proposal would be unduly burdensome
on PJM because it would require PJM to
post a narrative each hour. PJM asks that
the Commission not apply unnecessary
and costly posting requirements on
independent RTOs and ISOs.
365. EEI and Southern are concerned
that monthly ATC may change in
response to every reservation of hourly
transmission service because a
reservation of hourly firm service on a
constrained path may reduce the
availability of monthly firm service. EEI
contends that, if transmission providers
are required to post changes in TTC
instead of ATC, they would not be
required to post a new narrative every
time a reservation is made, thus
reducing the overall burden on
transmission providers. EEI additionally
states that the reasons for changes in
TTC and ATC values often are complex
and involve the interaction of multiple
variables in the model that produces the
TTC and ATC values and a specific
change in TTC or ATC cannot easily be
207 E.g.,
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208 E.g., Ameren, ISO New England, Southern,
and NRECA.
209 E.g., Ameren, EEI, Entergy, MISO, Pinnacle,
PJM, PNM–TNMP, Southern, TranServ, and TVA.
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traced to a specific change in the inputs.
Alternatively, EEI suggests that
transmission providers could post the
major changes in the inputs to the TTC
modeling software that are made in
connection with each updated TTC
posting without ascribing specific
inputs to specific changes in TTC and
ATC values on specific lines.
366. Several commenters are
supportive of the proposed requirement
that transmission providers provide a
narrative explanation when ATC values
remain at zero.210 APPA suggests that if
a particular interface shows an ATC of
zero for a specified period, the
transmission provider should provide a
narrative explanation of why this is the
case and how its plans to address this
problem. It also suggests that this
information should be employed in the
transmission planning process. East
Texas Cooperatives, in reply comments,
state that the narrative can provide
useful information to the transmission
customers and State and Federal
regulators regarding specific conditions
regarding ATC coordination.
367. In supplemental comments,
NAESB states that the Commission
should specify whether it is sufficient
for the explanation of changes in ATC
or TTC values to be limited to broad
generalized statements or whether the
posted information should include such
information as the specific events which
gave rise to the change, the new values
for ATC at all points on the network, the
impact of the change on transmission
customers, and a detailed snapshot of
the conditions on the system at all
flowgates or constrained elements when
the change occurred.211
368. Southern states that posting a
narrative when ATC remains at zero is
unwarranted and unnecessary, as it
simply indicates that the market has
responded to market signals of ATC
availability and purchased all available
capacity.
Commission Determination
369. The Commission adopts the
NOPR proposal, with the modifications
discussed below, to require that the
transmission provider post a brief, but
specific, narrative explanation of the
reason for a change in monthly and
yearly ATC values on a constrained
path. Rather than requiring a narrative
210 E.g., APPA, East Texas Cooperatives, Suez
Energy NA, and TAPS.
211 November 2, 2006, Addendum to the
Testimony of Ronald M. Mucci on behalf of the
North American Energy Standards Board,
Preventing Undue Discrimination and Preference in
Transmission Service, Docket Nos. RM05–25–000
and RM05–17–000, October 12 Technical
Conference, pp. 2–3.
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when a monthly or yearly ATC value
changes as a result of transactions being
reserved, service ending, or the TTC
estimate for the path changing by more
than 10 percent, we will require a
narrative when a monthly or yearly ATC
value changes only as a result of a 10
percent change in TTC. This will reduce
the number of ATC changes for which
a narrative will be required and address
concerns that the new requirement
unduly burdens transmission providers.
Any remaining burden is justified by the
benefit to transmission customers of
receiving timely information regarding
changes in TTC that result in changes to
ATC. In addition, we adopt NAESB’s
suggestion that posted information
include the (1) Specific events which
gave rise to the change and (2) new
values for ATC on that path (as opposed
to all points on the network).
370. We reject calls for delays prior to
posting data. While commenters allege
the possibility of granting others a
competitive advantage through the
release of ‘‘market-sensitive’’ data, they
have proffered no evidence to support
the allegation of potential harm.
371. We do require, as suggested in
the NOPR, a narrative with regard to
monthly or yearly ATC values when
ATC remains unchanged at a value of
zero for a significant period, and will set
that period at six months or longer. This
information will be valuable to
customers and regulators in assessing
the ability of a transmission provider’s
facilities to meet existing service
requests. The information also will
provide assurance to customers that the
transmission provider is diligent in
regularly evaluating ATC on all paths,
monitoring persistent constraints and
addressing them in its planning
processes.
372. Finally, we reject CAISO’s
suggestion that ATC be updated daily
on a transmission provider’s OASIS site,
because CAISO offered no justification
for the proposal.
(5) Denial of Service/Records Retention
sroberts on PROD1PC70 with RULES
NOPR Proposal
373. In the NOPR, the Commission
proposed to maintain the requirement
that a transmission provider post the
reason for a denial of a request for
service. The Commission also proposed
to amend this provision to require a
transmission provider to maintain and
make available information supporting
the reason for the denial. The
Commission further proposed to extend
the time period for which transmission
providers must maintain transmission
service information for audit. Currently,
regulations require that audit data be
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retained and made available upon
request for download for three years
from the date when they are first posted.
The Commission proposed to change
the period from three to five years.
Comments
374. Many commenters support
posting of the reasons for denying
service and the 5-year retention
proposal.212 TAPS supports the
proposal but suggests several
modifications. First, it suggests that the
Commission clarify the requirement to
post the reasons for denying service is
triggered not only by denial of the
entirety of a transmission request, but to
any disposition that falls short of a full
unconditional grant of the service (with
rollover rights if applicable). Second,
TAPS recommends that the regulatory
text of proposed section 37.6(e)(2)(ii) be
modified to make the supporting data
available, upon request, to any eligible
customer rather than just to the
customers who were denied service.
Third, it asks that the Commission
expand its OASIS regulations to require
the transmission provider to maintain
and make available on request the
information supporting the disposition
(positive, negative, or in between) of its
own network resource designations and
other usage needs. East Texas
Cooperatives suggest that the
Commission also require that
transmission providers distinguish
between denials of requests for firm and
non-firm transmission service.
375. Some commenters urge the
Commission to clearly define the scope
of any transmission service request
information subject to the proposed
five-year record retention requirement
to ensure that no undue administrative
burden is placed on transmission
providers.213 TVA questions the need to
extend the time period for an additional
two years. TVA states that the benefits
of extension are not commensurate with
the increased costs, since it is unaware
of any problems that have arisen with
the current three-year timeline. Seattle
argues on reply that the Commission
should retain the NOPR posting
requirements in the Final Rule because
information on actual transmission
congestion can be helpful instead of sole
reliance on simulation models.
212 E.g., APPA, Arkansas Commission, Arkansas
Municipal, Duke, East Texas Cooperatives, MISO,
ISO New England, Williams, Nevada Companies,
PPL, Sacremento, Sant Clara, Suez Energy NA, and
TDU Systems.
213 E.g., MidAmerican, PacifiCorp, PNM–TNMP,
and PJM.
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12313
Commission Determination
376. As proposed in the NOPR, the
Commission maintains the requirement
that a transmission provider post the
reason for a denial of service and
extends from three years to five years
the period for which transmission
providers must maintain data providing
reasons for denial of service. In general,
commenters support the requirement for
posting denial of service information
and the increase in retention time to five
years, indicating that such information
can be helpful to customers in their
awareness of actual transmission
congestion, rather than relying on
simulation models.
377. We also adopt TAPS’ suggestion
to expand the regulations to include
availability of information supporting
the disposition of a transmission
provider’s own network resource
designations and to make such
information available to any eligible
customer rather than just to that
customer denied service. In addition,
we clarify that a partial denial of service
triggers the requirements as well. Such
information is consistent with the new
regulations established by this Final
Rule and will help ensure that
customers receive transmission service
that is not unduly discriminatory. The
development of a log of service denials,
full or partial, will establish an ongoing
record of service requests and
transmission provider responses
demonstrating the transmission
provider’s provision of
nondiscriminatory open access service.
Furthermore, repeated denials of service
over a particular path or flowgate will
provide an indication of congestion that
can be used in the transmission
planning process. In addition, we agree
with East Texas Cooperatives that
postings of denials of service should
indicate whether the requested service
was firm or non-firm.
(6) Designation and Termination of
Network Resources
NOPR Proposal
378. In the NOPR, the Commission
proposed to require the transmission
provider and network customers to use
the transmission provider’s OASIS to
request designation of a new network
resource and to terminate the
designation of a network resource. This
information would be posted on OASIS
for 90 days and be available for audit for
a five-year period. Transmission
customers therefore would be able to
query such requests to designate and
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terminate a network resource.214 The
Commission also proposed to require
the transmission provider to post on its
OASIS a list of its current designated
network resources and all network
customers’ current designated network
resources. The list would include the
resource name, geographic and
electrical location and amount of
capacity of the designated network
resource.
sroberts on PROD1PC70 with RULES
Comments
379. Several commenters support the
Commission’s proposal to require
transmission providers and network
customers to use the transmission
provider’s OASIS to request or
terminate designation of resources,
though some indicated that the required
network resource information is
currently available via OASIS.215 PJM
supports the proposal, provided that the
electrical location is based on an
industry standard format and any
standard adopted by NERC takes into
consideration possible confidentiality
issues when posting the geographic
location of designated network
resources.
380. APPA suggests that reservations
related to future load growth also
should be posted so that it is clear to all
industry participants what transmission
capacity transmission providers are
reserving for load growth purposes.
Williams submits that the list of current
designated resources needs to indicate
whether they are for native load or
network customers, or whether they are
for meeting forecasted loads and system
emergencies.
381. TranServ supports the
Commission’s proposal and indicates
that NAESB is the appropriate forum for
development of standards necessary to
support posting the designation and
termination of network resources.
TranServ cautions that implementation
will require a sufficient period of time
after the practices and standards are
developed and suggests that changes to
OASIS should be timed to avoid peak
summer and winter seasons.
382. Exelon requests that the
Commission clarify that transmission
providers and network customers
making firm off-system sales may
terminate designation of network
resources solely for the term of such sale
and not for other periods of time. During
this period of termination, the firm
capacity is posted and made available to
other customers.
214 See
18 CFR 37.6(a)(6).
APPA, Exelon, PJM, TAPS, TranServ, and
TDU Systems.
215 E.g.,
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383. Great Northern supports the
proposal and requests clarification that,
when a network resource is
‘‘undesignated,’’ ATC will not be set
aside in anticipation that it might be
designated again as a network resource
in the future. Great Northern requests
that the Commission confirm that new
requests to designate network resources,
regardless of the prior designation of
those resources, are placed at the end of
the transmission service queue.
384. Sacramento states that the
posting requirements for network
resources are an unnecessary burden
and instead recommends that the
transmission provider should be
required to identify resources it is
transmitting to native load when it
denies a request for transmission service
from a third party.
posting of unused transfer capability.
TDU Systems state that the requirement
to post on OASIS all transfer capability
associated with transmission
reservations not scheduled in real time
furthers not only the Commission’s
goals with respect to comparability and
transparency of ATC calculations, but
also the Commission’s goals in freeing
up access to transmission capacity for
transmission customers.
Commission Determination
385. The Commission adopts the
NOPR proposal and requires
transmission providers and network
customers to use OASIS to request
designation of new network resources
and to terminate designation of network
resources.216 This information shall be
posted on OASIS for 90 days and
available for audit for a five-year period.
Transmission customers thus shall be
able to query requests to designate and
terminate a network resource. This
requirement adds valuable transparency
without undue burden, since it is
nothing more than maintaining a
database of designation requests made
and responded to electronically. The
Commission orders public utilities,
working through NAESB, to develop
appropriate templates for OASIS.
386. The requests for clarifications by
Exelon and Great Northern will not be
addressed in this section. These
requests are not related to OASIS
postings, but involve changes in tariff
language. They are addressed in section
V.D.6 of this Final Rule.
Comments
(7) Posting of Unused Transfer
Capability
NOPR Proposal
387. In the NOPR, the Commission
reminded transmission providers that
transfer capability associated with
transmission reservations that is not
scheduled in real time should be
included in non-firm ATC and posted
on OASIS.
Comments
388. Entegra, TANC, and TDU
Systems emphasize the need for the
216 See paragraph 1477, where further detail on
using OASIS to request designation of network
resources is provided.
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Commission Determination
389. We affirm our statement in the
NOPR proposal acknowledging that
transfer capability associated with
transmission reservations that are not
scheduled in real time is required to be
made available as non-firm, and posted
on OASIS.
(8) Other OASIS Issues
390. MidAmerican, PacifiCorp and
Pinnacle contend that the development
of the OASIS posting requirements is
technical in nature and should be
addressed by the NERC and NAESB
processes.
391. NRECA recommends that the
Commission require public utility
transmission providers to make OASIS
data available in a useable, machinereadable and manipulable format to
transmission customers (so they can be
better prepared to make decisions about
their transmission needs) and to the
Commission (so that it can monitor the
provision of transmission service).
Similarly, Powerex states that posted
data must be in sufficient detail to
permit third parties to independently
review and verify ATC postings and
treatment of transmission service
requests.
392. Utah Municipals suggest that
OASIS sites be as uniform and
compatible as possible and reasonably
user-friendly, and that certificate fees
for access to non-public sites be
evaluated for legitimacy. Arkansas
Commission and Seattle also express
concern over the OASIS access
requirements established by most
transmission providers, which require
viewers to purchase certificates or
licenses for the particular computers
from which OASIS access is sought.
393. Williams suggests that all
transmission service-related business
practices and local procedures,
including the exercise of discretion or
waiver or granting of exception, be
posted on the transmission provider’s
OASIS. It also suggests that real-time
data and import/export limits by
constrained area should be posted on
OASIS, along with line outages
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(planned and unplanned), estimated
return to service dates and de-rates of a
line.
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Commission Determination
394. In response to NRECA and other
commenters regarding the availability
and format of data available on OASIS,
we note that current regulations already
require that OASIS data be made
available in a useable, machine-readable
user friendly format to transmission
customers. The improvements required
in the Final Rule will enhance the level
of detail posted on OASIS and, in turn,
transmission customers’ ability to verify
the transmission provider’s treatment of
transmission requests. Thus, to the
extent NRECA or others desire greater
consistency in data formats, they should
propose such revisions through the
NERC and NAESB processes.
395. Regarding comments received
expressing concern about the use of
certificates for OASIS access, we believe
that the use of such certificates can be
appropriate. However, the Commission
reminds transmission providers that the
cost of OASIS access, whether by
registration, certificate or other form of
license, should be limited to a nominal
charge, e.g., no more than $100. This
nominal fee provides funding for OASIS
maintenance while assuring that all
transmission customers and potential
customers will not be denied access
because of excessive fees.
396. With respect to Williams’ request
for additional OASIS postings, we agree
that such additional data would be
useful to transmission customers and is
already posted on some ISO and RTO
Web sites and, to a lesser extent, on the
NERC web site (TLR data). Therefore,
we require that all transmission servicerelated business practices and local
procedures, including waivers, should
be posted on or made available through
OASIS. With respect to real-time data
and import/export limits by constrained
area, estimated return-to-service dates
and line de-ratings, we are confident
that most of this data is already required
by this Final Rule and shall be provided
whenever TTC and ATC changes in
value trigger the posting of a narrative
explanation of the causes of those
changes. Moreover, the Final Rule
requires a broad data exchange among
transmission providers, including
information on line outages and other
data relating to ATC calculations.
Accordingly, we will not require
additional OASIS postings for this data.
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(9) CEII
NOPR Proposal
397. Critical Energy Infrastructure
Information (CEII) is information
concerning proposed or existing critical
infrastructure (physical and virtual) that
(1) Relates to the production,
generation, transportation, transmission
or distribution of energy, (2) could be
useful to a person in planning an attack
on critical infrastructure, (3) is exempt
from mandatory disclosure under the
Freedom of Information Act, 5 U.S.C.
552, and (4) does not simply give the
location of the critical infrastructure.217
Access to such transmission related
information has been restricted by the
Commission’s CEII regulations.218
398. In the NOPR, the Commission
recognized that the use of the existing
CEII processes could undermine their
goal of providing increased
transparency to information necessary
to evaluate the use of the transmission
system. As a result, the Commission
requested comment on procedures that
could be adopted by transmission
providers to streamline the resolution of
CEII concerns and allow timely
disclosure of information from the
transmission providers to interested
parties.
Comments
399. APPA and other commenters
argue that the additional information
disclosure requirements proposed in the
NOPR raise substantial CEII concerns,
and request the Commission to refine its
CEII procedures to allow those with
legitimate need for the information to
obtain it on a timely basis.219 Bonneville
would like to permit public access for
stakeholders to review principles and
methods used in ATC calculations, but
only permit limited access, subject to
background checks and non-disclosure
agreements, to modeling data that may
compromise infrastructure security.
APPA suggests establishing a process for
advance qualification for receipt of such
information by those industry
participants with rights to review
information on the customer side of
OASIS, without giving blanket public
access. TDU Systems urge the
Commission to adopt a streamlined
217 See Critical Energy Infrastructure Information,
Order No. 683, 71 FR 58273 (Oct. 3, 2006), FERC
Stats. & Regs. ¶ 31,228 at P 66 (2006), reh’g pending.
We note that the Commission is proposing to
change the definition of CEII in a proceeding in
Docket No. RM06–23–000. See Critical Energy
Infrastructure Information, Notice of Proposed
Rulemaking, 71 FR 58325 (Oct. 3, 2006), FERC
Stats. & Regs. ¶ 32,607 (2006).
218 See 18 CFR 388.112–113.
219 E.g., MidAmerican, Sacramento, Southern,
and TVA.
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process to ensure timely resolution of
ATC calculation disputes and to adopt
measures that ensure that CEII claims do
not unduly restrict information.
400. EEI and Southern caution that
the release of a transmission provider’s
explanation of methodologies, practices,
and procedures in Attachment C may
not give rise to CEII concerns, but that
other information such as energy
infrastructure data, models and
assessments do raise security and
confidentiality concerns. They propose
that a transmission provider have the
ability to seek confidential treatment of
such information. Allegheny proposes
that an independent third party or
Commission staff review and explain
ATC calculations to interested parties
without disclosing CEII.
401. Several commenters believe that
much of the information the
Commission proposes to require
transmission providers to provide will
not pose CEII concerns.220 However,
Entergy states that some of the
information requires protection as
proprietary information because its
public availability over OASIS would
reveal commercially sensitive
information. ISO New England also
points out that information relevant to
the ATC calculation may be marketsensitive
402. Pinnacle believes the current
CEII process is not unduly burdensome
and urges the Commission to continue
to apply the existing CEII procedures,
which allow transmission customers
with digital certificates or passwords to
access publicly restricted transmission
information.
Commission Determination
403. The Commission acknowledges
that certain data and studies required to
be made public under this Final Rule
may contain CEII. The Commission has
a responsibility to protect this
information. However, the Commission
agrees with APPA, Bonneville, and TDU
Systems that those with a legitimate
need for CEII information must be able
to obtain it on a timely basis. The
Commission also shares EEI and
Southern’s concerns that the data,
models and assessments used to
calculate ATC may contain information
that raises security and confidentiality
concerns, and ISO New England and
Entergy’s concerns about commercial
and market-sensitive information.
404. In order to provide transparency
and avoid undue delays in providing
information to those with a legitimate
need for it, the Commission requires
220 E.g., Nevada Companies, East Texas
Cooperatives, PJM, and TDU Systems.
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(10) Additional Data Posting
NOPR Proposal
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405. To further reduce discretion in
calculating ATC/AFC, the Commission
proposed that transmission providers
post on OASIS metrics related to the
provision of transmission service under
their OATT. In the NOPR, the
Commission proposed to require the
monthly posting of (1) The number of
affiliate versus non-affiliate requests for
transmission service that have been
rejected and (2) the number of affiliate
versus non-affiliate requests for
transmission service that have been
made. This posting would also detail
the length of service request (e.g., shortterm or long-term) and the type of
service requested (e.g., firm point-topoint, non-firm point-to-point or
network service). The Commission
sought comments regarding whether it
should require transmission providers
to post their underlying load forecast
assumptions for all ATC calculations
and, on a daily basis their actual daily
peak load for the prior day. Finally, the
Commission asked for comment on the
overall benefit of posting the proposed
metrics, on potential alternative metrics,
and on working through NAESB to
develop standards for consistent
methods of posting the new
requirements on OASIS.
Comments
406. PJM and other commenters
support the proposal to post data
221 18
CFR 388.113.
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showing acceptances and denials of
transmission service requests of nonaffiliates and affiliates.222 However, PJM
and Ameren argue that the affiliate
posting requirement should not apply to
RTOs and ISOs, because they are
independent, have no affiliates, and lack
incentive to favor one transmission
customer over another. MDEA requests
clarification on how the additional
posting requirements would be applied
under Entergy’s weekly procurement
process. Entergy notes on reply that the
Commission has already established
metrics to measure the performance of
its weekly procurement process, and the
creation of further metrics are beyond
the scope in a generic rulemaking.
Entergy further points out that nonaffiliated generating facilities that are
designated as network resources to serve
native load also benefit from
transmission service obtained in this
manner. It suggests that NAESB is the
best forum for considering such issues
and developing specific procedures for
calculating these metrics. TranServ
suggests that there are other useful
metrics that NAESB should be directed
to define, such as average time to
evaluate requests and confirm requests,
and percentage of requests denied,
approved and withdrawn.
407. PJM notes its support of
proposed OASIS posting reforms, but
cautions that all industry groups must
have an equitable and proportionate
voice in NAESB if it is requested to
develop standards. It also expresses
concern that PJM and other RTOs have
established a practice of posting a
significant amount of data for
participants’ use in formats and
applications which respective members
have requested and approved through
stakeholder processes.
408. APPA points out that the data on
transmission denials would be useful to
the Department of Energy (DOE) in
reporting on congestion in its triennial
congestion studies to be prepared under
FPA section 216(a), and that NAESB
may be able to provide standard formats
for disclosure of such data. Some APPA
members express a preference for NERC
to develop these standards, while others
stress the need for regional variation in
posting requirements.
409. Ameren questions whether the
posting requirement would serve the
Commission’s objective of identifying
undue discrimination even in cases
where the transmission provider is not
an RTO or other independent
transmission provider, because the
metrics can lead to incorrect
impressions. MidAmerican also states
that the proposed posting would require
sophisticated analysis to yield useful
benefits.
410. EEI is not opposed to the
proposal to post metrics on acceptance
and denial of requests for transmission
service, but suggests such information is
already available on OASIS and that any
customer or the Commission staff can
develop its own metrics. Southern also
states that this data is currently
available.
411. Several commenters support the
posting of forecast and actual daily peak
loads.223 Ameren states that the
proposed requirement would produce a
useful comparison, increase
transparency, and provide the ability to
verify that an appropriate amount of
capacity is being set aside for native
load. E.ON states that RTO and ISO
forecasts and actual data need to be
posted with sufficient granularity to
allow for meaningful comparison of
control area and LSE load levels. EEI
requests that the Commission clarify
that its proposal to require the posting
of peak loads applies to system-wide
loads and not only to the native load of
the transmission provider. It also seeks
clarification that the differences
between forecast and actual system peak
loads not result in any repercussions.
412. APPA members in the East
generally favor the proposal to post the
load information, but its members in the
West expressed concerns about the
competitive implications of providing
such data. Additional commenters
express concern about data
confidentiality.224 TAPS contends that
providing for data disclosure on a oneday lag basis would alleviate these
commercial concerns, but it also
suggests that the Commission should
require the disclosure of projected load
forecast information on request to a
customer’s non-market employees or
agents.
222 E.g., Arkansas Commission, Constellation,
MidAmerican, MDEA, Morgan Stanley, Nevada
Companies, NRECA, Suez Energy NA, and
TranServ.
transmission providers to establish a
standard disclosure procedure for CEII
required to be disclosed by this Final
Rule. We note that transmission
customers already have digital
certificates or passwords to access
publicly restricted transmission
information on OASIS. Transmission
providers may set up an additional login
requirement for users to view CEII
sections of the OASIS, requiring users to
acknowledge that they will be viewing
CEII information. Transmission
providers may require customers to sign
a nondisclosure agreement at the time
that the customer obtains access to this
portion of the OASIS. Only information
that meets the criteria for CEII, as
defined in section 388.113 of the
Commission’s regulations,221 should be
posted in this section of the OASIS.
Transmission providers will be
responsible for identifying CEII and
facilitating access to it by appropriate
entities, and the Commission will be
available to resolve disputes if they
arise.
223 E.g., Ameren, Constellation, E.ON, Nevada
Companies, NRECA, Powerex, Suez Energy NA,
TAPS, TDU Systems, and TranServ.
224 E.g., E.ON, Entergy, LDWP, and TranServ.
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Commission Determination
413. The Commission adopts the
proposed requirement to post on OASIS
metrics related to the provision of
transmission service under the OATT.
Specifically, transmission providers
must post (1) The number of affiliate
versus non-affiliate requests for
transmission service that have been
rejected and (2) the number of affiliate
versus non-affiliate requests for
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transmission service that have been
made. This posting must detail the
length of service request (e.g., short-term
or long-term) and the type of service
requested (e.g., firm point-to-point, nonfirm point-to-point or network service).
The Commission also will require
transmission providers to post their
underlying load forecast assumptions
for all ATC calculations and, to post on
a daily basis, their actual daily peak
load for the prior day. The Commission
directs transmission providers to work
through NAESB to develop standards
for consistent methods of posting the
new requirements on OASIS.
414. The Commission agrees with PJM
and Ameren that affiliate posting
requirements do not apply to RTOs and
ISOs, since they do not have affiliates to
transact with. The Commission also
agrees with Entergy that the metrics
established for its weekly procurement
process are outside the scope of this
proceeding.
415. In response to Southern’s point
that the information necessary to
compute the metrics is already available
on OASIS, while it is true that service
denial information is available on
OASIS for long periods, request
information is not. As such, a customer
would need to continuously download
information from OASIS to record the
data sufficient to calculate the metrics
on its own. The Commission concludes
that it is not unduly burdensome for
transmission providers to calculate the
metrics required by this Final Rule.
416. With regard to posting of load
forecasts and actual daily peak load, we
conclude that such postings are
necessary to provide transparency for
transmission customers. We agree with
E.ON that RTO and ISO load data needs
to be posted at a sufficient granularity
to allow for meaningful comparison of
control area and LSE load levels. Most
RTOs and ISOs post load data for the
entire footprint, but few post it on an
LSE or control area basis. We therefore
direct ISOs and RTOs to post load data
for the entire ISO/RTO footprint and for
each LSE or control area footprint
within the ISO/RTO. This will not
create an undue burden on ISOs and
RTOs, since the load data for the entire
footprint is an aggregation of load data
across the LSEs or control areas in the
footprint. We also agree with EEI that
the peak load applies to system-wide
load, including native load. We direct
transmission providers to post load
forecasts and actual daily peak load for
both system-wide load (including native
load) and native load, as this data will
be useful to customers and regulators.
We deny EEI’s request for a guarantee
that transmission providers will not be
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held accountable for producing a
reasonable load forecast. While we do
not intend to penalize transmission
providers for failing to account for
unforeseen circumstances, we retain our
ability to investigate any allegations of
manipulation of load forecasts, as this
could be used as a means of
inappropriately denying requested
transmission service.
417. The Commission is not
convinced by the views of some
commenters that load data has
competitive implications. The
Commission notes, as PJM pointed out
in its comments, that many RTOs have
an established practice of posting
significant amounts of load data for
participants’ use, and this data posting
has not raised competitive concerns.
B. Coordinated, Open and Transparent
Planning
1. The Need for Reform
418. Order No. 888 set forth certain
minimum requirements for transmission
system planning. For example, Order
No. 888 and the pro forma OATT
require that transmission providers plan
and upgrade their transmission systems
to provide comparable open access
transmission service for their
transmission customers. With regard to
network service, section 28.2 of the pro
forma OATT provides that the
transmission provider ‘‘will plan,
construct, operate and maintain its
Transmission System in accordance
with Good Utility Practice in order to
provide the Network Customer with
Network Integration Transmission
Service over the Transmission
Provider’s Transmission System.’’
Section 28.2 also provides that the
Transmission Provider shall, consistent
with Good Utility Practice, ‘‘endeavor to
construct and place into service
sufficient transfer capability to deliver
the Network Customer’s Network
Resources to serve its Network Load on
a basis comparable to the Transmission
Provider’s delivery of its own generating
and purchased resources to its Native
Load Customers.’’
419. The pro forma OATT also
requires that new facilities be
constructed to meet the service requests
of long-term firm point-to-point
customers. Section 13.5 of the pro forma
OATT requires the transmission
provider to consider redispatch of the
system to relieve any constraints that
are inhibiting a transmission customer’s
point-to-point service if it is economical
to do so; but if redispatch is not
economical, the transmission provider
is obligated to expand or upgrade its
system. This expansion obligation on
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12317
the part of the transmission provider for
point-to-point service is found in
section 15.4 of the pro forma OATT,
which provides that, when a
transmission provider cannot
accommodate a request for point-topoint transmission because of
insufficient capability on its system, it
will ‘‘use due diligence to expand or
modify its Transmission System to
provide the requested Firm
Transmission Service.’’ Section 15.4
goes on to provide that ‘‘the
Transmission Provider will conform to
Good Utility Practice in determining the
need for new facilities and in the design
and construction of such facilities.’’ The
transmission provider’s obligation to
upgrade or expand its system to provide
point-to-point service as detailed in
section 15.4 is contingent on the
transmission customer agreeing to
compensate the transmission provider
for such costs pursuant to the terms of
section 27 (providing for cost
responsibility for upgrades and/or
redispatch ‘‘to the extent consistent
with Commission policy’’).
420. In Order No. 888–A, the
Commission encouraged utilities to
engage in joint planning with other
utilities and customers and to allow
affected customers to participate in
facilities studies to the extent
practicable. The Commission also
encouraged regional planning so that
the needs of all participants are
represented in the planning process.225
Order No. 888–A did not, however,
require that transmission providers
coordinate with either their network or
point-to-point customers in
transmission planning or otherwise
publish the criteria, assumptions, or
data underlying their transmission
plans. The Commission also did not
require joint planning between
transmission providers and their
customers or between transmission
providers in a given region.226 The only
section of the existing pro forma OATT
that directly speaks to joint planning is
section 30.9, which provides that a
network customer must receive credit
when facilities constructed by the
customer are jointly planned and
installed in coordination with the
transmission provider.227
225 See
Order No. 888–A at 30,311.
id.
227 Pro forma OATT section 21.2, ‘‘Coordination
of Third-Party System Additions,’’ provides for
certain rights for transmission providers to
coordinate construction of facilities on their
systems associated with point-to-point customer
requests and related construction on a third-party
transmission system, but imposes no obligation on
transmission providers.
226 See
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421. As the Commission stated in the
NOPR, the Nation has witnessed a
decline in transmission investment
relative to load growth in the ten years
since Order No. 888 was issued.
Transmission capacity per MW of peak
demand has declined in every NERC
region. Transmission constraints plague
most regions of the country, as reflected
in the limited amounts of ATC posted
in many regions, increased frequency of
denied transmission requests,
increasingly common transmission
service interruptions or curtailments
and rising congestion costs in organized
markets.228
422. We do not believe that the
existing pro forma OATT is sufficient in
an era of increasing transmission
congestion and the need for significant
new transmission investment. We
cannot rely on the self-interest of
transmission providers to expand the
grid in a nondiscriminatory manner.
Although many transmission providers
have an incentive to expand the grid to
meet their State-imposed obligations to
serve, they can have a disincentive to
remedy transmission congestion when
doing so reduces the value of their
generation or otherwise stimulates new
entry or greater competition in their
area. For example, a transmission
provider does not have an incentive to
relieve local congestion that restricts the
output of a competing merchant
generator if doing so will make the
transmission provider’s own generation
less competitive. A transmission
provider also does not have an incentive
to increase the import or export capacity
of its transmission system if doing so
would allow cheaper power to displace
its higher cost generation or otherwise
make new entry more profitable by
facilitating exports.
423. As the Commission explained in
Order No. 888, ‘‘[i]t is in the economic
self-interest of transmission
monopolists, particularly those with
high-cost generation assets, to deny
228 The number of TLRs has increased
significantly since NERC started reporting annual
statistics. The total number of TLRs each year has
grown from under 500 in 1998 and 1999 to around
2000 over the last four years from 2002 to 2006. The
number of TLR actions at the highest levels,
requiring curtailment of firm transmission flows,
has also grown, from under 10 before 2001 to 70
in 2006, averaging 55 per year from 2003 to 2006.
Source: NERC Web site, ftp://www.nerc.com/pub/
sys/all_updl/oc/scs/logs/trends.htm. In addition,
congestion costs continue to be a major issue in
RTO markets. For example, congestion costs in PJM
were $2.09 billion in calendar year 2005, which was
a 179 percent increase over 2004. Although this
increase resulted primarily from increases in PJM
annual billings, the congestion costs in both years
were approximately 9 percent of total PJM billings
in both years and have ranged from 6 percent to 10
percent of total billings since 2000. Source: 2005
PJM State of the Markets Report, April 2006.
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transmission or to offer transmission on
a basis that is inferior to that which they
provide themselves.’’ 229 The court
agreed on review of Order No. 888,
noting in TAPS v. FERC that ‘‘[u]tilities
that own or control transmission
facilities naturally wish to maximize
profit. The transmission-owning utilities
thus can be expected to act in their own
interest to maintain their monopoly and
to use that position to retain or expand
the market share for their own generated
electricity, even if they do so at the
expense of lower-cost generation
companies and consumers.’’ 230 The
Supreme Court in New York v. FERC
similarly explained that ‘‘public utilities
retain ownership of the transmission
lines that must be used by their
competitors to deliver electric energy to
wholesale and retail customers. The
utilities’ control of transmission
facilities gives them the power either to
refuse to deliver energy produced by
competitors or to deliver competitors’
power on terms and conditions less
favorable than those they apply to their
own transmissions.’’ 231
424. The existing pro forma OATT
does not counteract these incentives in
the planning area because there are no
clear criteria regarding the transmission
provider’s planning obligation.
Although the pro forma OATT contains
a general obligation to plan for the
needs of their network customers and to
expand their systems to provide service
to point-to-point customers, there is no
requirement that the overall
transmission planning process be open
to customers, competitors, and State
commissions.232 Rather, transmission
providers may develop transmission
plans with limited or no input from
customers or other stakeholders. There
229 Order
No. 888 at 31,682.
F.3d at 684.
231 535 U.S. at 8–9 (citation and footnotes
omitted).
232 As discussed in more detail in the NOPR, the
need for reform was recognized by the Consumer
Energy Council of America (CECA), a public
interest energy policy organization with a 30-year
history of bringing stakeholders together to find
solutions to contentious energy policy issues. CECA
launched its Transmission Infrastructure Forum in
early 2004, which published its conclusions in
January 2005 in a final report titled ‘‘Keeping the
Power Flowing: Ensuring a Strong Transmission
System to Support Consumer Needs for CostEffectiveness, Security and Reliability’’ (CECA
Report). Among other things, the CECA Report
concludes that regional transmission planning with
consumer input early in the process is needed to
ensure the development of a robust transmission
system capable of meeting consumer needs reliably
and at reasonable cost over time. The CECA Report
stresses that regional transmission planning must
address inter-regional coordination, the need for
both reliability and economic upgrades to the
system, and critical infrastructure to support
national security and environmental concerns. See
NOPR at P 207.
230 225
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also is no requirement that the key
assumptions and data that underlie
transmission plans be made available to
customers.
425. Taken together, this lack of
coordination, openness, and
transparency results in opportunities for
undue discrimination in transmission
planning. Without adequate
coordination and open participation,
market participants have no means to
determine whether the plan developed
by the transmission provider in
isolation is unduly discriminatory. This
means that disputes over access and
discrimination occur primarily after-thefact because there is insufficient
coordination and transparency between
transmission providers and their
customers for purposes of planning.233
The Commission has a duty to prevent
undue discrimination in the rates,
terms, and conditions of public utility
transmission service and, therefore, an
obligation to remedy these transmission
planning deficiencies. As we explain
above, our authority to remedy undue
discrimination is broad.234 In addition,
new section 217 of the FPA requires the
Commission to exercise its jurisdiction
in a manner that facilitates the planning
and expansion of transmission facilities
to meet the reasonable needs of LSEs. A
more transparent and coordinated
regional planning process will further
these priorities, as well as support the
DOE’s responsibilities under EPAct
2005 section 1221 to study transmission
congestion and issue reports designating
National Interest Electric Transmission
Corridors and the Commission’s
responsibilities under EPAct 2005
section 1223.
NOPR Proposal
426. In order to provide for more
comparable open access transmission
service, limit the potential for undue
discrimination and anticompetitive
conduct, and satisfy its statutory
responsibilities under section 217 of the
FPA, the Commission proposed to
amend the pro forma OATT to require
coordinated, open, and transparent
transmission planning on both a local
and regional level. Each public utility
233 In our discussion of enforcement issues at
section V.E of this Final Rule, we note specific
situations in which transmission providers have
agreed to resolve staff allegations that they engaged
in OATT violations involving transactions with
affiliates. While these specific situations may not
directly relate to discrimination in planning, they
nevertheless document the continuing incentive of
transmission providers to favor themselves and
their affiliates in the provision of transmission
service.
234 See Order No. 888 at 31,669 (noting that the
FPA ‘‘fairly bristles’’ with concern for undue
discrimination (citing AGD, 824 F.2d at 998).
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transmission provider would be
required to submit, as part of its
compliance filing in this proceeding, a
proposal for a coordinated and regional
planning process that complies with the
following eight planning principles:
Coordination, openness, transparency,
information exchange, comparability,
dispute resolution, regional
participation, and congestion studies. In
the alternative, transmission providers
could make a compliance filing in this
proceeding describing their existing
coordinated and regional planning
processes and showing that they are
consistent with or superior to that
required in the Final Rule.
427. The Commission stated that it
expected non-public utility
transmission providers to participate in
the proposed planning processes, given
that effective regional planning cannot
occur without the participation of all
transmission providers, owners, and
customers. Although the Commission
encouraged the use of an independent
third party to oversee or coordinate the
planning process, the NOPR did not
propose to require it. The Commission
also strongly encouraged the
participation of State commissions and
other State agencies in planning
activities.
428. The Commission sought
comment on several aspects of the
NOPR proposal. First, the Commission
inquired as to the level of flexibility
each transmission provider should be
given in implementing any principles
adopted. Second, the Commission
sought comment, by way of example, on
transmission planning processes that
comply with the NOPR reforms in
principle. Third, the Commission
sought comment on whether there are
other principles or requirements that
should be adopted to support the
construction of needed new
infrastructure and otherwise ensure that
all market participants are treated on a
comparable basis. Specifically, the
Commission inquired: (a) Whether there
should be a principle or guideline to
govern the recovery and allocation of
costs associated with funding the
regional planning requirement; (b)
whether there should be a requirement
that, at least for large new transmission
projects, there be an open season to
allow market participants to participate
in joint ownership of these projects; (c)
whether there should be a specific study
process to identify opportunities to
enhance the grid for purposes beyond
maintaining reliability or reducing
current congestion; and, (d) whether
public utilities should be required to
develop cost allocation principles to
address the sharing of the costs of new
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transmission projects and, given that
such projects can take years to
construct, whether the planning process
should be required to look out at least
as far as the longest time it would take
to build such an upgrade in the region
in question. Finally, the Commission
sought comment on the level of detail to
be required in transmission providers’
OATTs.
Comments
429. Most commenters support the
development of coordinated, open, and
transparent planning. While differing on
how they should be implemented,
commenters express broad support for
the eight planning principles,235 though
all RTOs and ISOs and many investorowned utilities believe that their
planning processes already comply with
the proposals in the NOPR. ISO/RTO
Council, as well as individual RTOs and
ISOs, advance the position that RTOs
and ISOs already meet the planning
requirements in the NOPR, that there
has been no credible case made for
reopening their already approved
planning processes, and that RTOs and
ISOs should be exempt from complying
with the NOPR’s planning principles.
430. Some transmission providers
agree that RTOs already meet the
principles, and others argue against
commenters who maintain that RTOs
‘‘rubber stamp’’ transmission provider
plans.236 For example, MISO asserts that
it conducts an open planning process
and does not ‘‘rubber stamp’’ projects.
Duke concurs with MISO, stating that
there are abundant opportunities for
participation in the MISO planning
process. Xcel also replies in support of
the MISO process.
431. Several transmission customers,
however, argue that current RTO
processes are insufficient because,
among other things, they merely accept
the transmission owners’ plans and only
provide for after-the-fact input, thus
failing to satisfy the planning principles
proposed in the NOPR.237 Old
Dominion also asserts that RTOs
generally approve transmission owner
identified upgrades, which give them
the advantage of having their own
parochial plans incorporated into the
regional plan without any separate
evaluation or complete stakeholder
input. TAPS asserts that open planning
should apply both to the RTO and the
underlying transmission owners’
235 The one exception is the congestion studies
requirement, which is generally opposed by
transmission providers and supported by
customers.
236 E.g., Duke, Exelon, and Xcel.
237 E.g., Indicated Parties Reply, Old Dominion,
NRECA, and TAPS.
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12319
planning efforts. In its reply, WPS
opposes MISO’s proposal to be exempt
from the NOPR’s planning
requirements, arguing that the MISO
process is not open and only aggregates
the plans of the transmission providers.
432. EEI takes issue with broad
statements in the NOPR that assert that
transmission providers have a
disincentive to remedy transmission
congestion and to plan their
transmission systems on a comparable
basis. Other individual investor-owned
utilities also assert that the record does
not support the NOPR’s claims that a
mandatory coordinated, open, and
transparent planning process is
necessary to remedy undue
discrimination.238 Many others,
however, believe the NOPR correctly
diagnoses the problem of
discrimination.239
433. Most commenters do not
question the Commission’s jurisdiction
to address the transmission planning
process generally. Southern, however,
argues that the Commission has no
general authority in this area and that
section 217 of the FPA does not grant
the Commission any additional
jurisdiction to impose a regional
planning requirement.240 FMPA
counters that the Commission has FPA
authority to cure undue discrimination
and to ensure ‘‘just and reasonable’’
transmission rates and terms by
adopting transmission planning
criteria.241 In their replies, APPA and
TAPS agree with the Commission that
FPA section 217(b)(4) can be cited as
legal support for transmission planning.
In its reply, NRECA stresses that the
transmission planning process must
focus, consistent with FPA section
217(b)(4), on the reasonable long-term
needs of LSEs, not all users of the
system as argued by EPSA and NRG.
Santee Cooper urges the Commission to
be mindful of the limits of its
jurisdiction in establishing study
requirements that may delve into
generation resource adequacy or issues
related to the mix of generation. Other
commenters urge the Commission not to
impinge on State jurisdiction.242 In its
reply, LPPC emphasizes that the
Commission’s expectation that public
power entities will participate is
238 See,
e.g., Duke and Southern.
e.g., APPA and EPSA. However, NRG and
Reliant believe that the planning process outside of
RTOs is fundamentally flawed and cannot be
remedied by the NOPR’s planning proposal.
240 Progress Energy also claims that the
Commission does not have any jurisdiction to
mandate regional planning.
241 See also TAPS Reply.
242 See, e.g., Nevada Companies, New Mexico
Attorney General, North Carolina Commission
Reply, and Southern.
239 See,
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sufficient and asserts that there is no
reason to take further action that might
test the limits of jurisdiction under FPA
section 211A.243
434. WIRES endorses several planning
objectives it believes to be critical to
successful planning. These objectives
include open and transparent planning
procedures, a long-term planning
horizon, broad-based inclusion of
reliability, economic, efficiency and
environmental considerations in
planning, clear conditions under which
a transmission owner will commit to
build planned facilities, and provision
for fair and efficient allocation of the
costs of planned facilities. WIRES also
emphasizes the importance of
considering non-transmission
alternatives, arguing that an appropriate
grid plan must be based on an integrated
view of all alternatives, including
demand response and distributed
generation.
Commission Determination
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435. In order to limit the
opportunities for undue discrimination
described above and in the NOPR, and
to ensure that comparable transmission
service is provided by all public utility
transmission providers, including RTOs
and ISOs, the Commission concludes
that it is necessary to amend the existing
pro forma OATT to require coordinated,
open, and transparent transmission
planning on both a local and regional
level. We disagree with commenters
arguing either that we lack jurisdiction
to require coordinated transmission
planning or that we have not established
a basis for such a requirement. The
Commission has broad authority to
remedy undue discrimination by
ensuring that transmission providers
plan for the needs of their customers on
a comparable basis.244 That
fundamental requirement was adopted
in Order No. 888 and the reforms
adopted herein should ensure that it
will be implemented properly. Further,
we explained in detail above why
undue discrimination remains a concern
in the planning area and why the
243 Other jurisdictional arguments primarily relate
to the question of joint ownership, in which some
commenters argue that the Commission lacks
jurisdiction to mandate joint ownership
arrangements. See, e.g., Duke, EEI, National Grid,
Northeast Utilities, PSEG, and Southern. FMPA and
others, however, argue that the Commission does
have the authority to order joint ownership. Joint
ownership will be discussed more fully below.
244 See AGD, 824 F.2d at 1008 (Commission has
broad discretion to promulgate generic rules to
eliminate undue discrimination without
‘‘conduct[ing] experiments in order to rely on the
prediction that an unsupported stone will fall’’).
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existing OATT is insufficient to address
that concern.
436. New section 217 of the FPA
further supports reform in this area, as
it reflects Congress’ intent that the
Commission utilize its powers to
facilitate the planning and expansion of
the transmission system.245 Through
EPAct 2005 sec. 1223, Congress also
directed the Commission to encourage
the deployment of advanced
transmission technologies in
infrastructure improvements, including
among others optimized transmission
line configurations (including multiple
phased transmission lines), controllable
load, distributed generation (including
PV, fuel cells, and microturbines), and
enhanced power device monitoring.
437. Accordingly, each public utility
transmission provider is required to
submit, as part of a compliance filing in
this proceeding, a proposal for a
coordinated and regional planning
process that complies with the planning
principles and other requirements in
this Final Rule.246 In the alternative, a
transmission provider (including an
RTO or an ISO, as discussed below),
may make a compliance filing in this
proceeding describing its existing
coordinated and regional planning
process, including the appropriate
language in its tariff, and show that this
existing process is consistent with or
superior to the requirements in this
Final Rule. Under either of these
approaches, the process must be
documented as an attachment to the
transmission provider’s OATT.
438. At the outset, we note that the
planning obligations imposed in this
Final Rule do not address or dictate
which investments identified in a
transmission plan should be undertaken
by transmission providers. Furthermore,
except for the discussion below of cost
allocation for transmission investments
under Principle 9, the planning
245 FPA section 217(b)(4) provides that ‘‘[t]he
Commission shall exercise the authority of the
Commission under [the FPA] in a manner that
facilitates the planning and expansion of
transmission facilities to meet the reasonable needs
of load-serving entities to satisfy the service
obligations of the load-serving entities, and enables
load-serving entities to secure firm transmission
rights (or equivalent tradable or financial rights) on
a long term basis for long term power supply
arrangements made, or planned, to meet such
needs.’’
246 The pro forma OATT, as modified by this
Final Rule, reflects the proposed planning
requirement in sections 15.4, 16.1, 17.2(x), 28.2,
29.2, 31.6. The planning process itself will be
included as Attachment K to the pro forma OATT.
We understand that some transmission providers
may already have attachments to their OATTs
labeled with the letter ‘‘K,’’ in which case
transmission providers are free to label their
planning process OATT attachment with the next
available letter.
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obligations included in this Final Rule
do not address whether or how
investments identified in a transmission
plan should be compensated. Through
the principles described below, we
establish a process through which
transmission providers must coordinate
with customers, neighboring
transmission providers, affected State
authorities, and other stakeholders in
order to ensure that transmission plans
are not developed in an unduly
discriminatory manner.
439. As for the application of the
Final Rule’s coordinated planning
requirement to RTOs and ISOs, which
already have a Commission-approved
transmission planning process on file
with us, we note that the intent of our
reform in this Final Rule is not to
reopen prior approvals, but rather to
ensure that the transmission planning
process utilized by each RTO and ISO
is consistent with or superior to the
planning process adopted here. When
the Commission approved the existing
RTO and ISO transmission planning
processes, they were found to be
consistent with or superior to the
existing pro forma OATT. Because the
pro forma OATT is being reformed by
this Final Rule, it is necessary for each
RTO and ISO to now either reform its
process or show that its planning
process is consistent with or superior to
the pro forma OATT, as modified by the
Final Rule.
440. We also make clear that
transmission owning members of ISOs
and RTOs must participate in the
planning processes adopted in this Final
Rule. In order for an RTO’s or ISO’s
planning process to be open and
transparent, transmission customers and
stakeholders must be able to participate
in each underlying transmission
owner’s planning process. This is
important because, in many cases, RTO
planning processes may focus
principally on regional problems and
solutions, not local planning issues that
may be addressed by individual
transmission owners. These local
planning issues, however, may be
critically important to transmission
customers, such as those embedded
within the service areas of individual
transmission owners. Consequently, the
intent of the Final Rule will not be
realized if only the regional planning
process conducted by the RTOs and
ISOs is shown to be consistent with or
superior to the Final Rule. To ensure
full compliance, individual
transmission owners must, to the extent
that they perform transmission planning
within an RTO or ISO, comply with the
Final Rule as well. Without such a
requirement, the more regional RTO or
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ISO planning process will not comply
with the requirements of the Final Rule
to the extent they incorporate and rely
on information prepared by underlying
transmission owners that, in turn, have
not complied with the Final Rule.
Accordingly, as part of their compliance
filings in this proceeding, RTOs and
ISOs must indicate how all participating
transmission owners within their
footprint will comply with the planning
requirements of this Final Rule. While
we leave the mechanics of such
compliance to each RTO and ISO, we
emphasize that the RTO’s or ISO’s
planning processes will be insufficient
if its underlying transmission owners
are not also obligated to engage in
transmission planning that complies
with Final Rule.247
441. The Commission also expects all
non-public utility transmission
providers to participate in the planning
processes required by this Final Rule. A
coordinated, open, and transparent
regional planning process cannot
succeed unless all transmission owners
participate. We are encouraged, based
on the representations of LPPC and
others, that non-public utility
transmission providers will fully
participate in such processes. We
therefore do not believe it is necessary
at this time to invoke our authority
under FPA section 211A, which gives us
authority to require non-public utility
transmission providers to provide
transmission services on a comparable
and not unduly discriminatory or
preferential basis.248 If we find on the
appropriate record, however, that nonpublic utility transmission providers are
not participating in the planning
247 We understand that there are some
transmission owners in RTOs or ISOs that continue
to have OATTs on file under which they provide
service over certain transmission facilities that they
did not turn over to the operational control of the
RTO or ISO. Like any other transmission provider,
those entities must submit a compliance filing to
their OATTs that satisfies all requirements of this
Final Rule, including the inclusion of an
attachment governing their own planning
procedures. As we explain elsewhere, the
compliance filing deadline for transmission owning
participants in RTOs and ISOs shall be the same as
the RTO and ISO deadline, i.e., 210 days after
publication of the Final Rule in the Federal
Register.
248 FPA section 211A(b) provides, in pertinent
part, that ‘‘the Commission may, by rule or order,
require an unregulated transmitting utility to
provide transmission services—(1) At rates that are
comparable to those that the unregulated
transmitting utility charges itself; and (2) on terms
and conditions (not relating to rates) that are
comparable to those under which the unregulated
transmitting utility provides transmission services
to itself and that are not unduly discriminatory or
preferential.’’ The non-public utility transmission
providers referred to in this Final Rule include
unregulated transmitting utilities that are subject to
FPA section 211A.
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processes required by this Final Rule,
the Commission may exercise its
authority under section 211A on a caseby-case basis. Further, we note that
reciprocity dictates that non-public
utility transmission providers that take
advantage of open access due to
improved planning should be subject to
the same requirements as jurisdictional
transmission providers.
442. In sum, each OATT planning
process attachment must incorporate the
transmission planning principles and
concepts in this Final Rule and must be
filed with the Commission within 210
days after the publication of the Final
Rule in the Federal Register.
Alternatively, RTOs, ISOs, and other
transmission providers that currently
have planning processes they believe
comply with the Final Rule may make
a filing with the Commission
documenting those processes in an
OATT attachment and explaining how
their planning processes are consistent
with or superior to the planning process
adopted here. Such filings must also be
submitted within 210 days after the
publication of the Final Rule in the
Federal Register.
443. In order to assist transmission
providers in complying with the Final
Rule, and ensure that the planning
procedures are developed with
customer and stakeholder participation,
the Commission will convene staff
technical conferences in several broad
regions around the country to discuss
regional implementation and other
compliance issues in advance of the
compliance date. We extend an
invitation to State regulatory
commissions to participate in these
technical conferences with our staff in
order to ensure that State concerns are
fully addressed. The Commission will
endeavor to hold the technical
conferences 90 to 120 days after the
publication of the Final Rule in the
Federal Register. To facilitate these
conferences, each transmission provider
should, within 75 days after the
publication of the Final Rule in the
Federal Register, post a ‘‘strawman’’
proposal for compliance with each of
the planning principles adopted in the
Final Rule, including a specification of
the broader region in which it will
conduct coordinated regional planning.
This strawman may be posted on the
transmission provider’s OASIS, or its
Web site if it does not have its own
OASIS (e.g., in the case of a
transmission owning member of an RTO
or ISO that does not have its own
OATT). We strongly urge transmission
providers to consult with their
stakeholders in the development of this
strawman.
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12321
2. Planning Principles
444. We set forth below the planning
principles that must be satisfied for a
transmission provider’s planning
process to be considered compliant with
the Final Rule. The NOPR identified
eight such principles, but based on the
comments received the Commission
will require compliance with nine—the
original eight plus a cost allocation
principle, as described further below.
a. Coordination
445. In the NOPR, the Commission
proposed that transmission providers
must meet with all of their transmission
customers and interconnected neighbors
to develop a transmission plan on a
nondiscriminatory basis. We sought
comment on specific requirements for
this coordination, such as the minimum
number of meetings to be required each
year, the scope of the meetings, the
notice requirements, the format, and any
other features deemed important by
commenters.
Comments
446. Commenters express universal
support for the general concept of
coordination, but differ on how specific
the requirement should be. Several
commenters argue that the requirement
that transmission providers ‘‘must
meet’’ with customers and utilities is
unrealistic.249 EEI requests that the
Commission clarify that transmission
providers will be responsible for
coordinating with customers and
holding meetings, but that the
requirement to meet should be limited
to making reasonable efforts to meet
with all customers. NRECA asks on
reply that the Commission make clear
that the lack of full participation by
some nonjurisdictional utilities that take
network service under the OATT should
not excuse the transmission provider’s
obligation to engage in transmission
planning. NRECA states that inclusion
in the planning process must be an
opportunity for LSEs, not an obligation.
447. Other commenters express a
more general concern that the
Commission not be prescriptive with
respect to meeting requirements.250 For
example, most commenters generally
believe the Commission should not
prescribe rigid rules regarding the
number of meetings that must be held
249 E.g., Allegheny, Duke, EEI, International
Transmission, MidAmerican, NorthWestern, and
SCE.
250 E.g., Allegheny, APPA, Bonneville, California
Commission, Duke, Entergy, Imperial, International
Transmission, MidAmerican, NCEMC, NC
Transmission Planning Participants Reply,
NorthWestern, NRECA, Pinnacle, Progress Energy,
CREPC, Santee Cooper, SCE, TVA, and WAPA.
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each year. Xcel, however, suggests that
a minimum of three meetings a year
would be appropriate. Progress notes
that coordination in North Carolina
already occurs as a result of regular
meetings throughout the year. Nevada
Companies believe that meetings should
be dependent on need and should not
be programmatically established. TDU
Systems recommend at least monthly
meetings, but stress that meetings
should be as frequent as is required to
specify and perform the studies forming
the basis for the plan. NCPA believes
that the minimum requirements are not
as important as how they can be
monitored or enforced to ensure that
true participation indeed occurs.
448. Seattle suggests 30 days notice
for meetings and that information
regarding meetings be posted at least
one week in advance. Entergy finds a
notice requirement reasonable, and
other utilities suggest a 30-day
requirement would be appropriate.251
Seattle also suggests e-mail notification
and Salt River supports internet posting.
With respect to details beyond
frequency and notice, Entergy cautions
the Commission against being too
prescriptive.
449. On meeting scope, several
commenters request that the
Commission make clear that the
purpose of the meeting is to focus on
transmission issues and not provide a
broad forum for other issues.252
Sacramento believes that meetings
should be limited to sub-regional or
regional transmission planning and not
include planning to meet local
transmission needs.
450. Other commenters stress that
joint planning requires more than just
meeting with customers and that all
LSEs need to be integrated into the
planning process so that they are
actively developing transmission plans
alongside transmission providers from
the inception.253 This concept of
collaborative planning is a running
theme in the comments provided by
several public power entities, such as
NRECA, TAPS, and TDU Systems. TDU
Systems argue that comparability
requires that LSEs have equal weight in
decision-making rather than provide de
facto veto authority to transmission
providers. NRECA argues in its reply
that collaborative planning is required
by FPA section 217(b)(4). These
commenters assert that LSEs must be
able to participate in the development of
251 E.g.,
252 E.g.,
Nevada Companies and NorthWestern.
Entergy, Progress Energy, SCE, and
Southern.
253 E.g., NRECA, Seminole Reply, TAPS, and TDU
Systems.
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planning models, including the
assumptions and criteria that go into
these models, and in the development of
the base case and change case for study
purposes, particularly as to the
identification and projection of loads
and resources.254 Progress and
Southern, however, argue in replies that
giving customers equal weight in
decision-making crosses the line from
planning to control by third parties, and
Southern believes this would be
opposed by State regulators.
Commission Determination
451. The Commission adopts the
coordination principle proposed in the
NOPR. Commenters overwhelmingly
desire flexibility as to the coordination
principle, and as such, we will not
prescribe the requirements for
coordination, such as the minimum
number of meetings to be required each
year, the scope of the meetings, the
notice requirements, the format, and any
other features. We will allow
transmission providers, with the input
of their customers and other
stakeholders, to craft coordination
requirements that work for those
transmission providers and their
customers and other stakeholders.
452. We emphasize that the purpose
of the coordination requirement is to
eliminate the potential for undue
discrimination in planning by opening
appropriate lines of communication
between transmission providers, their
transmission-providing neighbors,
affected State authorities, customers,
and other stakeholders. Rigid and
formal meeting procedures may be one
way to accomplish this goal, but there
may be other ways as well. For example,
a transmission provider could meet this
requirement by facilitating the
formation of a permanent planning
committee made up of itself, its
neighboring transmission providers,
affected State authorities, customers,
and other stakeholders. Such a planning
committee could develop its own means
of communication, which may or may
not emphasize formal meeting
procedures. We are more concerned
with the substance of coordination than
its form.
453. In response to the concerns of
some commenters, we clarify that
transmission providers are not required
254 This collaborative approach is also generally
supported by East Texas Cooperatives, FMPA,
NCEMC, NCPA, and Old Dominion. NCEMC
believes that the key to ensuring true collaboration
is a voting structure, like that adopted in the North
Carolina Transmission Planning Collaborative,
which gives all load-serving entities an equal say
in planning decisions. APPA also believes that
giving customers a say in the outcome (e.g., through
voting) is critical.
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to meet with customers and other
stakeholders that choose not to meet.
Transmission providers cannot force
others to meet with them. Transmission
providers are, however, required to craft
a process that allows for a reasonable
and meaningful opportunity to meet or
otherwise interact meaningfully. We
also clarify that the coordination
requirements imposed in this Final Rule
are intended to address transmission
planning issues, and are not intended to
provide a forum for ancillary issues,
such as specific siting concerns, which
are better addressed elsewhere. As for
NRECA’s concern that transmission
providers must plan for their
nonjurisdictional network customers
even if they decline to fully participate
in the planning process, a transmission
provider cannot be expected to
effectively plan for a customer if that
customer declines to engage in the
planning process. Therefore, we
encourage NRECA and non-public
utilities to participate fully in the
planning process.
454. In response to the suggestion by
some commenters that we require
transmission providers to allow
customers to collaboratively develop
transmission plans with transmission
providers on a co-equal basis, we clarify
that transmission planning is the tariff
obligation of each transmission
provider, and the pro forma OATT
planning process adopted in this Final
Rule is the means to see that it is carried
out in a coordinated, open, and
transparent manner, in order to ensure
that customers are treated comparably.
Therefore, the ultimate responsibility
for planning remains with transmission
providers. With this said, we fully
intend that the planning process
adopted herein provide for the timely
and meaningful input and participation
of customers into the development of
transmission plans. This means that
customers must be included at the early
stages of the development of the
transmission plan and not merely given
an opportunity to comment on
transmission plans that were developed
in the first instance without their input.
b. Openness
455. In the NOPR, the Commission
proposed that transmission planning
meetings must be open to all affected
parties (including all transmission and
interconnection customers and State
authorities). The Commission also
sought comment on whether there are
any circumstances under which
participation should be limited, for
example, to address confidentiality
concerns.
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Comments
456. Commenters generally agree on
the need to meet with all affected
parties, as well as the need to limit some
meetings for security or confidentiality
reasons. Certain commenters urge the
Commission to make clear that
openness does not extend to a
requirement to meet with the general
public and that the meetings are for
‘‘industry and governmental
representatives’’ only.255 For example,
Southern agrees that eligible
transmission customers and State
commissions should be allowed to
participate in the meetings, but states
that these meetings should not be open
to the general public to help ensure that
the focus is on core transmission
planning and not be diverted to other
issues.
457. Transmission providers generally
note that some meetings will need to be
limited for CEII concerns or for
discussion of commercially-sensitive
information.256 Progress Energy states
the Commission should be flexible
regarding the composition of meetings
and openness, noting that in North
Carolina meetings involving CEII are
limited to transmission personnel and
non-marketing personnel of
participating LSEs, while other meetings
in the North Carolina process are open
to the public. In their reply, NC
Transmission Planning Participants note
that they have been able to negotiate
confidentiality protocols agreeable to
each of them. Duke believes that
restrictions on open meetings need to be
in place when sensitive commercial
information is being discussed, so that
personnel engaged in the merchant
function do not gain access to sensitive
information about their competitors.
Indianapolis Power recommends the
Commission keep existing restrictions
on access to planning meetings in place
to preserve current protections on
security and competitive information.
TVA states that it is particularly
concerned with maintaining
confidentially and asks the Commission
to defer to NERC and its Regional
Entities, which TVA says are developing
procedures for planning.
458. Commenters also raise issues
regarding the application of the
Commission’s Standards of Conduct to
those that participate in planning
meetings.257 EEI, for example, believes
Commission Determination
460. The Commission adopts the
NOPR’s proposal and will require that
transmission planning meetings be open
to all affected parties including, but not
limited to, all transmission and
interconnection customers, State
commissions and other stakeholders.
We recognize that it may be appropriate
in certain circumstances, such as a
particular meeting of a subregional
group, to limit participation to a
relevant subset of these entities. We
emphasize, however, that the overall
development of the transmission plan
and the planning process must remain
open. We agree with the concerns of
some commenters that safeguards must
be put in place to ensure that
confidentiality and CEII concerns are
adequately addressed in transmission
planning activities. Accordingly, we
will require that transmission providers,
in consultation with affected parties,
develop mechanisms, such as
confidentiality agreements and
password-protected access to
information, in order to manage
confidentiality and CEII concerns.
Lastly, concerns surrounding the
256 Other
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application of the Commission’s
Standards of Conduct to planning
participants, and whether and how
these standards should affect access to
and use of information obtained in the
planning process, will be discussed
below.
c. Transparency
461. In the NOPR, the Commission
proposed that transmission providers be
required to disclose to all customers and
other stakeholders the basic criteria,
assumptions, and data that underlie
their transmission system plans. The
Commission also sought comment on
whether the information provided in
FERC Form 715 (Form 715) is adequate
and, if not, what additional detail
should be provided. In addition, the
Commission sought comment on the
format for disclosure, including
protections to address confidentiality
concerns.
Comments
462. Transmission providers generally
agree that they should provide the basic
criteria, assumptions, and data for
planning, but argue that non-public
utility transmission providers should
also be required to provide comparable
information.259 In general, EEI believes
that information provided during the
planning process should be treated as
confidential and not disclosed to the
general public.
463. Public power entities and other
commenters support transparency and
also are sensitive to confidentiality
concerns.260 NCPA believes that the
failure of CAISO to release planning
data is one of the biggest failings of
CAISO planning process. Without
access to criteria, assumptions, and data
inputs, NCPA argues that customers
cannot duplicate planning results, nor
can they independently determine
whether the assumptions are correct,
whether the model is producing the
right results, whether those results are
being fairly applied in the choice of
projects to be undertaken, or assess the
impacts on their own customers. APPA
suggests that transmission providers be
required to reduce to writing the
methodology, criteria, and processes
they use to develop their transmission
plans, including how they treat retail
native loads, in order to ensure that
standards are consistently applied.
259 E.g.,
255 E.g.,
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APPA, EEI, Salt River, and Southern.
commenters also recognize the need to
maintain confidentiality for CEII and commerciallysensitive information. E.g., Arkansas Commission,
AWEA, California Commission, NCPA, NRECA,
CREPC, Seattle, TDU Systems, and WAPA.
257 Commenters raise issues with regard to the
application of the Commission’s Standards of
that if information is disclosed during a
planning meeting and is not
simultaneously made public, then all
planning participants—including
nonjurisdictional entities—should be
subject to the Commission’s Standards
of Conduct. APPA understands the need
to ensure that non-public information
obtained during planning meetings is
not utilized to gain an unfair advantage
in the power market; however, it
believes that other means short of the
application of the Standards of Conduct
would suffice, such as requiring
simultaneous disclosure of information
as a ‘‘safe harbor’’ or the use of
confidentiality agreements.258
459. NRECA and TDU Systems argue
that meetings should be open and,
joined by APPA, suggest that
confidentiality issues can be managed
with confidentiality agreements and
other arrangements (such as password
protected access to information). TAPS
suggests that access to data be limited to
transmission dependent utility
employees not involved in marketing or
to an outside consultant. California
Commission stresses that any advisory
subcommittees must also be open to all
stakeholders.
Conduct to planning participants in their comments
addressing some of the other principles as well,
which will be discussed below, as well as
addressed in the pending rulemaking in Docket No.
RM07–1–000. See Standards of Conduct NOPR.
258 See also East Texas Cooperatives Reply and
NRECA Reply.
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CAISO, EEI, and SCE.
APPA, California Commission, NCPA,
CREPC, Salt River, and WAPA. Old Dominion,
however, does not believe that any of the data
required to be disclosed is commercially-sensitive;
however, it does recognize that it may be CEII, in
which case it claims security can be maintained via
a secure OASIS site.
260 E.g.,
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CREPC points out that transparency is
necessary if State regulatory processes
are to give deference to planning results.
Sacramento asserts that it may be
reasonable to allow customers and
stakeholders access to the planning
model or at least allow access to a
comprehensive description of the model
and methodology, in order to allow
others to closely replicate the planning
analysis. Sacramento is joined by
Imperial in referencing WECC’s ongoing effort to increase planning
transparency.
464. NRECA and TDU Systems,
however, do not believe that a specific
disclosure principle would be necessary
if LSEs were truly integrated into the
planning process. In other words, they
argue that if the process is truly open,
then LSEs, as participants in the
development of the joint plan, should
already have access to the inputs and
assumptions underlying the plans and,
in fact, should have helped develop
them.
465. EEI believes that Standards of
Conduct requirements should be placed
on all participants in the planning
process whenever disclosure of
commercially-sensitive information is
needed for planning. East Texas
Cooperatives argues that the Standards
of Conduct should not be generically
applied to public power and that such
issues should be managed with
confidentiality agreements and case-bycase protective orders. In its reply,
NRECA also asserts that, while it is
necessary to protect competitivelysensitive information, there is no basis
for requiring nonjurisdictional entities
to comply with the formal separation of
functions requirements simply because
they have received information in the
planning process, as this is inconsistent
with the cooperative utility business
model. Rather, NRECA believes
commercially-sensitive information can
be handled in other established ways.
APPA also suggests that Standards of
Conduct issues can be managed by
providing for certain ‘‘safe harbors’’ for
participation, such as simultaneous
disclosure of information or the use of
an independent facilitator.261
466. Commenters express a range of
views on the information found in Form
715. MidAmerican believes Form 715 to
be more than adequate and recommends
shortening or eliminating it. Other
investor-owned utilities find Form 715
261 NARUC asks the Commission to re-examine
the need for its Standards of Conduct rules
concerning communications between resource and
transmission planners in light of the mitigation
provided by the open planning processes proposed
in the NOPR.
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to be generally sufficient.262 Others
believe the information in Form 715, as
currently supplemented by other
information in the planning process, is
adequate.263 Duke and WAPA contend
that Form 715 does not contain
sufficient information for transmission
planning, but believe that disclosure of
further details should be left to
stakeholders. According to
NorthWestern, Form 715 contains the
basic data, but may not always provide
the needed information.
467. ISO/RTO Council believes that
Form 715 data are generally inadequate
for planning studies, but urges the
Commission not to attempt to develop
‘‘standardized forms’’ for these and
other types of data. CAISO also cautions
against adopting a standardized form for
the collection of necessary information,
because standardized forms do not
necessarily provide the information
needed by individual providers.
468. A number of other commenters
believe that Form 715 information is
insufficient.264 APPA and TAPS point
out that Form 715 does not include all
the information needed to perform a
load flow study, including information
on economic dispatch and interchange,
and also that Form 715 information is
out of date when filed. Seattle notes that
typical sub-regional planning processes
go into significantly greater detail than
Form 715 and argues that Form 715 is
primarily a reliability-focused report
that seldom delves into economic
analysis of congestion and transmission
options that mitigate congestion.
469. Several commenters contend that
transparency in the planning process is
of particular interest to demand
resources. New Jersey Board suggests
that each transmission provider’s
planning process analyze whether
demand resources or other solutions
could be considered as an alternative or
a component of new transmission lines
or upgrades. New Jersey Board states
that this analysis should include both
supply-side and demand-side measures
such as load management, new building
codes and energy efficiency standards,
the use of distributive renewable energy
systems, and renewable portfolio
standards. Ohio Power Siting Board
argues that an open, transparent, and
inclusive regional planning process
should include distributed generation,
262 E.g.,
Indianapolis Power, Southern, and Xcel.
Allegheny (with data from PJM) and
Nevada Companies (with data from WECC).
264 E.g., APPA, California Commission, NCPA,
CREPC, Seattle, TAPS, and TDU Systems. California
Commission and CREPC also point out that the load
forecast information presently used in planning in
the Western Interconnection is likewise
insufficient.
263 E.g.,
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demand response, and new technology
as part of the mix of available options
for incremental or interim congestion
relief until longer term solutions can be
developed and constructed. Fayetteville
notes its general support for a SEARUC
joint planning proposal, which includes
a principle that would require the
integration of demand response in
planning. WIRES likewise argues that an
appropriate grid plan should be based
on an integrated view of all alternatives,
including demand response and
distributed generation. PJM, Midwest
ISO, and ISO New England emphasize
that their planning processes already
provide for the evaluation and
integration of demand response
resources.265 Other commenters, such as
Alcoa and Steel Manufacturer’s
Association, suggest that demand
response resources be considered as
substitutes for certain ancillary services.
470. In response to its notice
convening the October 12 Technical
Conference, the Commission received
several comments addressing the role of
demand response in planning.
Participants in the technical conference
generally responded that demand
response programs are considered in
planning, particularly in the load
forecasts. Some observed that demand
response has often been difficult to
incorporate in long-term plans when it
is not dispatchable and only available in
one-year increments. Participants
stressed that transmission providers
must have control over a resource
throughout the planning horizon if they
are to rely on that resource in lieu of
constructing upgrades. Some
participants reported that this capability
is available from several forms of
demand response resources.
Commission Determination
471. The Commission adopts the
NOPR’s proposal and will require
transmission providers to disclose to all
customers and other stakeholders the
basic criteria, assumptions, and data
that underlie their transmission system
plans.266 In addition, transmission
265 See
also ISO/RTO Council.
of the information should be available
to those engaged in transmission planning already
under reliability Standards TPL–001–0 through
TPL–004–0 proposed in Docket RM06–16–000. See
the Reliability Standards NOPR. These standards
set out detailed requirements for annual studies to
assess the performance of the transmission system
and require conducting simulation studies over a
five-year time horizon, with additional studies as
needed for the six to ten-year horizon. The
Commission proposed that planning entities
conduct ‘‘studies to bracket the range of probable
outcomes,’’ examining system operation under
variations in demand levels, existing and planned
facilities, reactive power resources, generation
dispatch and transaction patterns, controllable
266 Much
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providers will be required to reduce to
writing and make available the basic
methodology, criteria, and processes
they use to develop their transmission
plans, including how they treat retail
native loads, in order to ensure that
standards are consistently applied. This
information should enable customers,
other stakeholders, or an independent
third party to replicate the results of
planning studies and thereby reduce the
incidence of after-the-fact disputes
regarding whether planning has been
conducted in an unduly discriminatory
fashion. We note, however, that
transmission providers cannot be
expected to fulfill these planning
obligations unless non-public utility
transmission providers that participate
in the planning process make similar
information available and, for the
reasons set forth above, we fully expect
that they will do so. We believe that the
same safeguards developed as discussed
above regarding the openness principle,
such as confidentiality agreements and
password protected access to
information, will adequately protect
against inappropriate disclosure of
confidential information or CEII.
472. The Commission also requires
that transmission providers make
available information regarding the
status of upgrades identified in their
transmission plans in addition to the
underlying plans and related studies. It
is important that the Commission,
stakeholders, neighboring transmission
providers, and affected State authorities
have ready access to this information in
order to facilitate coordination and
oversight. To the extent any such
information is confidential or consists of
CEII, the transmission provider can
implement the safeguards suggested
above.
473. In response to the concerns of
some commenters regarding the
disclosure of information to non-public
utility transmission providers, we
believe that simultaneous disclosure of
transmission planning information
where appropriate alleviates many of
those concerns. In those instances
where there is non-simultaneous
disclosure of information, we find that
existing reciprocity requirements ensure
that information is not inappropriately
shared with the non-public utility
transmission provider’s marketing
affiliate.
loads and demand-side management, and other
factors. Id. at P 1047. While we recognize that
OATT planning is distinct from these proposed
reliability planning standards, we expect that the
key data underlying transmission planning will be
provided in conjunction with reliability standards
and thus should be available for transmission
planning when those standards are finalized.
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474. In Order No. 888–A, the
Commission clarified that, under the
reciprocity condition, a non-public
utility transmission provider must also
comply with the OASIS and Standards
of Conduct requirements or obtain
waiver of them.267 We reiterate that
non-public utility transmission
providers should abide by the Standards
of Conduct with regard to managing
non-public transmission planning
information obtained through the
planning process, consistent with their
reciprocity obligations. We also note
that, given the planning process
required by this Final Rule, it may be
necessary to revisit the waivers of the
Standards of Conduct granted to certain
non-public utility transmission
providers in the past. We will not do so,
however, on a generic basis in this
proceeding. All such existing waivers
thus shall remain in place. Whether an
existing waiver of the Standards of
Conduct should be revoked will be
considered on a case-by-case basis in
light of the circumstances surrounding
the particular transmission provider.268
475. In order for the Final Rule’s
transmission planning process to be as
effective as possible, we emphasize that
all transmission providers, both
jurisdictional and nonjurisdictional,
must be assured that the information
they provide in that process will not be
used inappropriately in the wholesale
power market. While we decline to
require a third party independent
facilitator as discussed below, we do
believe that utilizing an independent
entity may help parties manage
Standards of Conduct concerns.269
Finally, we wish to emphasize that the
Commission recognizes that compliance
with the Standards of Conduct can
impose costs on small entities, but we
believe that this concern must be
balanced against the fact that a
coordinated and open transmission
planning process is critical to
remedying undue discrimination and
meeting our Nation’s future energy
needs and that an open planning
process cannot be fully successful if
certain entities (whether jurisdictional
or nonjurisdictional) can use the
information to obtain an undue
267 See
Order No. 888–A at 30,286.
believe this same approach should also
apply to public utilities that have obtained waivers
of the Standards of Conduct.
269 The Commission will consider whether
further changes to the Standards of Conduct would
facilitate the transmission planning requirement in
the Standards of Conduct NOPR initiated in Docket
No. RM07–1–000. See supra note 257. We also
intend to address the concerns of NARUC with
regard to waiving the Standards of Conduct
concerning communications between resource and
transmission planners in that proceeding.
268 We
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12325
advantage in power markets. We
therefore intend to balance the costs of
confidentiality restrictions with the
importance of not allowing any entity
an undue competitive advantage in
addressing this issue on a case-by-case
basis.
476. Although we adopt the foregoing
protections to ensure that particular
entities do not gain an inappropriate
competitive advantage over others, we
believe that transmission providers
should make as much transmission
planning information publicly available
as possible, consistent with protecting
the confidentiality of customer
information. Given that one of the
primary objectives of the planning
reforms adopted herein is to allow
customers to consider future resource
options, it will be necessary for market
participants, including the merchant
function of transmission providers, to
have access to basic transmission
planning information in order to
consider those options. The
simultaneous disclosure of transmission
planning information can alleviate the
Standards of Conduct concerns
discussed above.270
477. In response to commenter
concerns regarding the sufficiency of
planning information currently
available in the Form 715, we find that
Form 715, as well as Form 714, have not
provided customers and others with the
timely data needed to perform load flow
studies and other analyses to ensure that
planning is being conducted on a
comparable basis. For example, while
we understand that certain planning
information is already provided in FERC
Form No. 714 (Annual Electric Control
and Planning Area Report) and FERC
Form 715 (Annual Transmission
Planning and Evaluation Report), we
believe that with regard to transparency
of data and assumptions, Forms 714 and
715 are limited in a number of ways. An
important limitation is that information
is not necessarily available on a
consistent geographic basis. Form 715
requires selected powerflow studies by
270 Transmission providers could ensure
simultaneous disclosure of information through
such actions as providing all current and potential
customers and other stakeholders equal access,
notice, and opportunity to attend planning
meetings, providing for the contemporaneous
availability of meeting handouts and minutes on the
transmission providers’ OASIS or Internet Web
sites, and requiring that an energy affiliate or
marketing affiliate employee of the transmission
provider may not attend a meeting unless a
representative of at least one additional customer or
potential customer is present. We believe such
actions would typically constitute compliance with
sections 358.5(a) and (b) of the Standards of
Conduct, 18 CFR 358.5(a)–(b), dealing with
information access and prohibited disclosure,
respectively.
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control area, while Form 714 requires
information on control area generation
and load, including hourly load on a
planning area. Since these two areas do
not necessarily coincide, it can be
difficult to apply the data except for the
single annual or seasonal system peak.
Consequently, Form 715 is an
insufficient basis for broad transmission
planning purposes and must be
supplemented by additional
assumptions and data.
478. Information may also be difficult
to compare or apply if a region is larger
than a single control area. Where the
peak periods represented in the Form
715 correspond to different time periods
in different control areas, separate
assumptions and information may be
needed for a study encompassing
multiple control areas. In addition, each
control area may include different
criteria for including facilities in the
data and additional assumptions will be
needed to resolve these issues as well.
Moreover, information on the basis for
key assumptions is limited. The Form
715 instructions require a description of
transmission planning reliability criteria
and assessment practices, but allow the
transmitting utility discretion on what is
reported. As a result, assumptions
regarding key inputs, such as the load
forecasts, are not available. Similarly,
information regarding customer demand
response is not available. Lastly, Form
715 requires no information explaining
the basis for generator dispatch in the
powerflow cases, nor is any economic
information provided. For studies of
system peak reliability, when all
generators are expected to be running,
this may not be a significant limitation.
However, without some basis for
dispatching the system at other times, it
becomes difficult or impossible to
conduct meaningful load flow studies
for other planning purposes. Therefore,
we will require the disclosure of
criteria, assumptions, data, and other
information that underlie transmission
plans as described above.
479. Finally, several commenters
assert that demand response resources
should be considered in transmission
planning.271 Some commenters note
that certain regions currently are in the
process of incorporating demand
response into their transmission
planning processes.272 Demand
resources currently provide ancillary
services in some regions, and this
capability is in under development in
271 E.g., Ohio Power Siting Board, New Jersey
Board, and WIRES.
272 E.g., PJM and ISO–New England.
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some others.273 We therefore find that,
where demand resources are capable of
providing the functions assessed in a
transmission planning process, and can
be relied upon on a long-term basis,
they should be permitted to participate
in that process on a comparable basis.274
This is consistent with EPAct 2005
section 1223.
d. Information Exchange
480. In the NOPR, the Commission
proposed that network transmission
customers be required to submit
information on their projected loads and
resources on a comparable basis (e.g.,
planning horizon and format) as used by
transmission providers in planning for
their native load. The Commission
further proposed that point-to-point
customers be required to submit any
projections they have of a need for
service over that planning horizon and
at what receipt and delivery points. The
Commission sought comment on
whether specific requirements should
be adopted for this information
exchange.275 The Commission also
stated that transmission providers must
allow market participants the
opportunity to review and comment on
draft transmission plans.
Comments
481. Transmission providers suggest
that they should be responsible for
developing a schedule and format for
submission of information and the
development of a draft plan that
provides sufficient time for participants
to review and comment before
completion of a final plan.276 EEI
emphasizes the importance of requiring
comparable information from all
participants in planning, including non273 See Staff Report: Assessment of Demand
Response & Advanced Metering at 97–100 (Docket
Number AD–06–2–000) (Demand Response Report),
available at https://www.ferc.gov/legal/staff-reports/
demand-response.pdf#xml=https://
search.atomz.com/search/
pdfhelper.tk?sp_o=1,100000,0.
274 The transmission planning processes we
require in this Final Rule are not intended in any
way to infringe upon State authority with regard to
integrated resource planning. Rather, we believe
that the transparency provided under an open
regional transmission planning process can provide
useful information which will help states to
coordinate transmission and generation siting
decisions, allow consideration of regional resource
adequacy requirements, facilitate consideration of
demand response and load management programs
at the State level, and address other factors states
wish to consider.
275 The Commission noted in the NOPR that for
network service, some of this information is already
required by sections 29, 30, and 31 of the pro forma
OATT, but to the extent it is not, the Commission
proposed to require customers to provide additional
information as necessary for the transmission
provider to develop a system plan.
276 E.g., EEI, Pinnacle, Salt River, and Xcel.
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public utilities. EEI maintains that
similarly-situated participants should
have comparable information, with
commercially-sensitive information
available only to transmission function
personnel. Duke supports the
information exchange principle in
general, but believes the NOPR
envisions a wider exchange of
information on loads and resources than
is appropriate.277 Instead, Duke believes
that planning participants should agree
on how much detail will be available.
WAPA similarly suggests that any
criteria for information exchange should
be developed by stakeholders, not the
Commission.
482. Although commenters do not
generally disagree with a requirement
for point-to-point customers to submit
projections of their needs for service,
they question the value of these
projections if the customers have not
actually requested service for these
projected needs.278 Nevada Companies
state that point-to-point customers
should provide future use forecasts and
that the forecast data transferred by all
entities should be provided for the
planning horizon in a uniform manner.
483. Southern is concerned that the
opportunity for review and comment
could be construed to apply to draft
interconnection, system impact, or
facilities studies under the transmission
provider’s OATT. Southern argues that
such a requirement would cause great
delay and asks the Commission to
clarify that the transparency
requirement for review and comment on
transmission plans is limited to only the
transmission provider’s draft of its base
case transmission plan.
484. Other commenters advance a
view that joint planning should consist
of more than providing the transmission
provider with information and then
reviewing and commenting on the plans
it develops; rather, customers need to be
able to actively participate in the
development of the planning studies
and transmission plans.279 APPA
likewise believes that earlier
involvement is needed so that projected
needs are fully understood and
accounted for in the initial development
of the plan.280 NCPA stresses that
reviewing plans is meaningless if there
is no access to data on how the plan was
created, how economic evaluation was
277 TVA states that it is unaware of any
shortcomings with the existing information
exchange process and that more specific
requirements may limit the ability of transmission
providers to meet changing needs and processes.
278 E.g., APPA, Duke, and Salt River.
279 E.g., NCPA and TDU Systems.
280 See also Bonneville, California Commission,
Imperial, NCPA, and Seattle.
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performed, and how and why proposed
upgrades were chosen. Old Dominion
suggests that planning information and
data be posted no less than monthly or,
where appropriate, seasonally. TDU
Systems and NCEMC stress that LSEs
should have access to all information at
the same time since if a transmission
provider performs studies without
including other LSEs, it opens the door
for providers to act on sensitive
information before releasing it to other
LSEs.
485. Some commenters advance the
view that distributed generation and
other demand response resources
should be considered in developing a
transmission plan.281
Commission Determination
486. The Commission adopts the
information exchange principle as to
both network and point-to-point
transmission customers. Accordingly,
we will require transmission providers,
in consultation with their customers
and other stakeholders, to develop
guidelines and a schedule for the
submittal of information. In order for
the Final Rule’s planning process to be
as open and transparent as possible, the
information collected by transmission
providers to provide transmission
service to their native load customers
must be transparent and, to that end,
equivalent information must be
provided by transmission customers to
ensure effective planning and
comparability. We clarify that the
information must be made available at
regular intervals to be identified in
advance. Information exchanged should
be a continual process, the frequency of
which should be addressed in the
transmission provider’s compliance
filing required by the Final Rule.
However, we expect that the frequency
and planning horizon will be consistent
with ERO requirements.
487. We also believe that it is
appropriate to require point-to-point
customers to submit any projections
they have of a need for service over the
planning horizon and at what receipt
and delivery points. We believe that any
good faith projections of a need for
service, even though they may not yet
be subject to a transmission reservation,
may be useful in transmission planning
as they may, for example, provide
planners with likely scenarios for new
generation development. If the point-topoint customers do not submit such
projections, then the transmission
provider cannot later be faulted for
failing to consider planning scenarios
281 E.g., New Jersey Board, Ohio Power Siting
Board, and WIRES.
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that might have taken into account
reasonable projections of future system
uses that were not the subject of specific
service requests. To the extent
applicable, transmission customers also
should provide information on existing
and planned demand resources and
their impacts on demand and peak
demand. In addition, stakeholders
should provide proposed demand
response resources if they wish to have
them considered in the development of
the transmission plan.
488. Lastly, in response to the
concerns of some commenters, we
emphasize that the transmission
planning required by this Final Rule is
not intended, as discussed earlier, to be
limited to the mere exchange of
information and then review of
transmission provider plans after the
fact. The transmission planning
required by this Final Rule is intended
to provide transmission customers and
other stakeholders a meaningful
opportunity to engage in planning along
with their transmission providers. At
the same time, we emphasize that this
information exchange relates to
planning, not other studies performed in
response to interconnection or
transmission service requests.
e. Comparability
489. In the NOPR, the Commission
proposed that, after considering the data
and comments supplied by market
participants, each transmission provider
develop a transmission system plan that
(1) Meets the specific service requests of
its transmission customers and (2)
otherwise treats similarly-situated
customers (e.g., network and retail
native load) comparably in transmission
system planning.
Comments
490. Several commenters support the
comparability principle,282 and others
state that existing processes already
follow this principle.283 EEI urges the
Commission to emphasize that the
‘‘comparability’’ principle requires the
transmission provider or transmission
owner to treat similarly-situated
participants comparably in the
development of a plan, but does not
require that all participants be treated
equally. Pinnacle and others support
comparable treatment of similarlysituated customers and request the
Commission to confirm that native load
protections will be recognized in the
concept of comparability.284 New
282 E.g., California Commission, NCPA, CREPC,
Salt River, Seattle, and WAPA.
283 E.g., Duke and Imperial.
284 See also MidAmerican, Progress Energy, and
Xcel.
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12327
Mexico Attorney General asserts that
native load and non-affiliated merchants
and other wholesale customers should
not be treated comparably, because
utilities have a statutory obligation to
serve.
491. TDU Systems and the NRECA
repeat the view that comparability
cannot be achieved if the transmission
provider is the only one developing the
plan, which they believe this principle
contemplates. They argue instead that
LSEs should be allowed to participate
actively in the development of the plan
from the beginning and should have
equal weight in decision-making. TDU
Systems believes that comparability
does not allow for different planning
standards for certain customers, because
it may leave rural electric cooperatives
out of the planning loop.285 TAPS also
argues that comparability is not enough;
rather, substantive goals should be
included.286
492. Noting that not all transmission
service requests may be granted,
Southern urges the Commission to
clarify that the intent of this criteria is
that the transmission provider plan its
system so as to be able to reliably serve
all of its long-term firm commitments on
its transmission system in accordance
with its State and Federal legal
requirements, as well as ERO Standards.
With regard to RTO and ISO planning,
NYAPP argues that it is not comparable
for an RTO or ISO to only plan for bulk
power facilities, while allowing
individual transmission owners the
discretion to plan for lower voltage
transmission facilities.
493. Some commenters argue that
demand resources should be treated
comparably to other resources in
transmission planning.287
Commission Determination
494. The Commission adopts the
NOPR’s proposal as to the comparability
principle and will require the
transmission provider, after considering
the data and comments supplied by
customers and other stakeholders, to
develop a transmission system plan that
(1) Meets the specific service requests of
285 See
also NRECA Reply and Old Dominion.
cites to its ‘‘Balanced Principles for
Transmission Planning & Expansion,’’ which was
attached to its NOI comments, for a description of
the following substantive goals: (1) Reliability/
adequacy, (2) accommodating load growth, (3)
preserving existing transmission rights, (4) access to
regional competitive generation markets, (5)
maintaining deliverability, (6) facilitating regional/
inter-regional power transfers, and (7) integrating
new generation into the regional grid. TAPS
emphasizes that the process should anticipate
needs and propose solutions before serious
transmission problems emerge.
287 E.g., ELCON, New Jersey Board, and WIRES.
286 TAPS
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its transmission customers and (2)
otherwise treats similarly-situated
customers (e.g., network and retail
native load) comparably in transmission
system planning.288 Further, we agree
with commenters that customer demand
resources should be considered on a
comparable basis to the service
provided by comparable generation
resources where appropriate.
495. We are specifically requiring a
comparability principle to address
concerns, such as those raised by
commenters, that transmission
providers continue to plan their
transmission systems such that their
own interests are addressed without
regard to, or ahead of, the interests of
their customers. Comparability requires
that the interests of transmission
providers and their similarly-situated
customers be treated on a comparable
basis. In response to the concerns
expressed by several commenters, we
emphasize that similarly-situated
customers must be treated on a
comparable basis, not that each and
every transmission customer should be
treated the same.289
f. Dispute Resolution
496. In the NOPR, the Commission
proposed that transmission providers
propose a dispute resolution process,
such as requiring senior executives to
meet prior to the filing of any complaint
and using a third party neutral. The
Commission noted that the
Commission’s Dispute Resolution
Service is available to assist
transmission providers in developing a
dispute resolution process. The
Commission also noted that, in addition
to informal dispute resolution, affected
parties would have the right to file
complaints with the Commission under
FPA section 206. The Commission
sought comment on whether any
specific dispute resolution processes
should be required.
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Comments
497. Many commenters support the
proposed dispute resolution
288 As discussed above, we emphasize that the
obligation imposed herein on transmission
providers is meant to include transmission owners
in RTOs and ISOs that no longer have their own
OATTs, as well as non-public utility transmission
providers required to comply with the Final Rule’s
planning process consistent with their reciprocity
obligations.
289 Additionally, in our discussion of the
coordination principle above, we clarify that
transmission planning is the tariff obligation of each
transmission provider, and as such, ultimate
responsibility for planning remains with
transmission providers. Accordingly, we reject the
arguments made by some commenters that
comparability requires that customers have equal
weight in decision-making.
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principle,290 while others believe
existing processes, including section 12
of the pro forma OATT, are
sufficient.291 Other commenters simply
urge flexibility in the development of a
dispute resolution process.292 However,
maintaining that the Commission has no
legal authority to mandate a regional
planning process or dispute resolution
related thereto, Progress states the
Commission should be flexible and
allow for a voluntary dispute resolution
process.293
498. Southern believes that dispute
resolution should be limited to whether
a provider has complied with any
procedural requirements and not be
utilized by parties to modify a
transmission plan. APPA, however,
argues that such an approach would
relegate customers to an advisory role.
EEI believes the Commission should
include principles for dispute resolution
and should allow stakeholders in the
regional planning groups to craft their
own procedures consistent with those
principles. Reflecting concerns of some
of its members, EEI cautions against
mandating dispute resolution that
includes binding resolution of whether,
how, where, or when to construct
additional transmission facilities.
499. Indianapolis Power believes
there should be a dispute resolution
process in place with specific steps
identified, expressing reservations about
the vagueness of the current MISO
process. ATC argues that RTO plans
should recognize which entity is
ultimately accountable for building
transmission, by requiring transmission
customers that have a dispute with a
plan first to appeal to the local
transmission owner to ensure both
entities fully understand what is being
requested, before carrying the dispute
further.
500. Consistent with its focus on
integrated joint planning, TDU Systems
asks that the Commission clarify that a
dispute resolution process is not being
required as a principle as an
acknowledgement that transmission
providers will retain control over the
process. As long as LSEs are an integral
part of the planning process, TDU
Systems stress that there should be no
290 E.g., APPA, Bonneville, California
Commission, Imperial, and NCPA.
291 E.g., East Texas Cooperatives, Salt River,
Seattle, TVA and WAPA. TVA points out that since
planning and its principles are just now being
formed, resources would be better spent on
developing platforms where interested parties could
have input into the planning process, as opposed
to dispute resolution.
292 E.g., Allegheny, Nevada Companies, Pinnacle,
and Southern. Xcel, however, does not believe any
dispute resolution process is required in the OATT.
293 See also Duke and MidAmerican.
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need for an elaborate dispute resolution
process.
Commission Determination
501. The Commission adopts the
NOPR’s proposal to require
transmission providers to develop a
dispute resolution process to manage
disputes that arise from the Final Rule’s
planning process.294 An existing dispute
resolution process may be utilized, but
those seeking to rely on an existing
dispute resolution process must
specifically address how its procedures
will be used to address planning
disputes. The dispute resolution process
should be available to address both
procedural and substantive planning
issues, as the purpose for including a
dispute resolution process is to provide
a means for parties to resolve all
disputes related to the Final Rule’s
planning process before turning to the
Commission.
502. We emphasize that the intent of
the dispute resolution process required
here is not to address issues over which
the Commission does not have
jurisdiction, such as a transmission
provider’s planning to serve its retail
native load or State siting issues. As
discussed above, however, we do intend
that the planning process required by
this Final Rule ensure comparability in
planning between that conducted for a
transmission provider’s retail native
load and its similarly-situated
transmission customers and, therefore,
issues relating to such comparability
may be appropriate for the dispute
resolution process.
503. Lastly, we encourage
transmission providers, customers, and
other stakeholders to utilize the
Commission’s Dispute Resolution
Service to help develop a three step
dispute resolution process, consisting of
negotiation, mediation, and arbitration.
Regardless of the process adopted by a
transmission provider, affected parties
of course would retain any rights they
may have under FPA section 206 to file
complaints with the Commission.
g. Regional Participation
504. In addition to preparing a system
plan for its own control area on an open
and nondiscriminatory basis, the
Commission proposed in the NOPR that
each transmission provider be required
to coordinate with interconnected
systems to: (1) Share system plans to
ensure that they are simultaneously
feasible and otherwise use consistent
294 We have already addressed arguments
concerning our jurisdiction to require a
transmission planning process. A process for
resolving disputes that arise from that planning
process is a necessary incident to it.
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assumptions and data, and (2) identify
system enhancements that could relieve
‘‘significant and recurring’’ transmission
congestion (defined below). The
Commission emphasized that such
coordination should encompass as
broad a region as possible, given the
interconnected nature of the
transmission grid and the efficiency of
addressing these issues in a single
forum. The Commission also recognized
that, as in the West, it may be
appropriate to organize regional
planning efforts on both a sub-regional
and regional level. The Commission
sought comment on whether there are
existing institutions (such as the NERC
regional councils or sub-regional
planning groups) that are well-situated
to perform or coordinate this function.
sroberts on PROD1PC70 with RULES
Comments
Regional Scope
505. EEI agrees that regional planning
should be encouraged, but urges the
Commission not to be prescriptive about
the size of the regions involved.
According to EEI, the Commission
should define regional planning as
planning that involves more than one
transmission provider and allow the
regions to define themselves. CAISO
believes the Commission should leave
the determination of the sub-regional
and regional boundaries to transmission
providers. NC Transmission Planning
Participants assert on reply that the
participants in each regional process are
in the best position determine the
proper scope of the planning process for
their region. NRECA argues that
customers and other stakeholders
should be allowed to participate in the
discussion that leads to the delineation
of regions. NRECA asserts that regions
should be large enough to minimize the
potential for seams problems for LSEs in
multiple control areas. At a minimum,
NRECA argues that the Commission
should ensure that all public utility
transmission providers coordinate with
their adjoining systems to ensure that
the needs of LSEs with loads and
resources in different systems’ areas are
met.
506. TDU Systems support mandatory
regional planning and believe that the
Commission should specify the criteria
for determining regions, rather than
prescribe regional boundaries. In TDU
Systems’ view, ‘‘regional’’ planning at a
minimum means something more than
planning on an individual control area
basis.295 TDU Systems stress that the
295 TAPS
believes joint planning should include
at least two transmission providers and be no
smaller than a State. TAPS suggests that the
transmission providers’ compliance filings identify
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existence of sub-regional planning must
not diminish the obligation to plan on
a broader, more regional level. TDU
Systems also believe that more than
coordination is required; rather,
transmission providers should be
required to conduct planning on an
integrated basis with, at a minimum,
first-tier, adjacent interconnected
systems. If a transmission provider
refuses to do so, TDU Systems believe
that should be considered an exercise of
vertical market power and the
transmission provider should lose its
market-based rate authority. TDU
Systems also urge the Commission to
require regional planning for both
reliability and economic upgrades, in
order to ensure that competitive market
development is not retarded by
inappropriate seams at the borders of
utility systems.296 In its reply, NRECA
argues that regional participation must
be mandatory, because uncoordinated,
unilateral planning by transmission
providers severely handicaps LSEs’
assembly of competitive power
suppliers for their customers.
507. PJM states that transmission
providers bordering RTOs should be
required to participate in the RTO
planning process, but MidAmerican
opposes such a requirement and
believes it already happens in MISO
anyway. MAPP also opposes such
mandatory participation, pointing out
that comparability would then require
that transmission providers in RTOs
participate in the planning processes of
non-RTO providers on their borders as
well.297 MAPP believes that currentlyexisting regions should have the
opportunity to adjust their planning
processes to meet the Commission’s
guidelines for regional transmission
planning.
508. Indianapolis Power emphasizes
that the regional scope of a transmission
provider’s planning process should
consider grid topology and historical
usage to avoid regions that are too broad
or unwieldy. Indianapolis Power
believes that the current MISO region
may be an example of a region that is
too large, but nevertheless asserts that
MISO should have the primary role in
coordination, with regional councils in
supporting roles. AWEA recommends
nine planning regions that coincide
with the nine regions being established
for Regional Triennial Reviews in the
market-based rate rulemaking in Docket
those other providers it proposes to include in its
regular regional planning process.
296 NRECA’s comments on regional planning are
consistent with those of TDU Systems.
297 See also MidAmerican Reply.
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12329
No. RM04–7–000: 298 PJM, New York,
New England, Midwest, SPP, Southeast,
California, Northwest, and Southwest.
509. LDWP and Salt River suggest that
continued participation in existing
regional and sub-regional groups should
satisfy the expectation that municipallyowned transmission providers
participate in open and transparent
regional planning processes. Other
commenters express a similar concern
that the Commission not mandate any
procedures that would interfere with the
processes the West has already
established.299 New Mexico Attorney
General believes that those already
engaged in a planning process should be
allowed a waiver.
510. NARUC urges the Commission to
clarify that planning proposals should
not interfere with or undermine existing
regional planning efforts, such as those
conducted by RTOs and in non-RTO
areas.300 Project for Sustainable FERC
Energy Policy recommends that the
Commission use the Bonneville and
PJM planning processes as models for
evaluating transmission provider
compliance. Arkansas Commission
believes that the active involvement of
states can be a catalyst for regional
planning.
511. National Grid believes the
principles of coordination, openness,
and transparency should extend to
inter-regional planning and requests
clarification that this is the
Commission’s intent for neighboring
regions in a single interconnect.
Existing Institutions
512. Regarding the Commission’s
request for comment on whether there
are existing institutions that are wellsituated to coordinate regional
participation, commenters express
differing views regarding the identity of
the regional coordinator and the size of
the region over which entities should be
required to coordinate. Some
transmission provider commenters cite
NERC regions and regional councils as
well-suited for coordinating regional
participation.301 Taking an opposite
view, ISO/RTO Council maintains that
RTOs and ISOs are the best models for
298 See Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, Notice of Proposed Rulemaking, 71
FR 33102 (Jun. 7, 2006), FERC Stats. & Regs.
¶ 32,602 (2006).
299 E.g., California Commission, Imperial, and Salt
River.
300 See also NC Transmission Planning
Participants Reply and North Carolina Commission
Reply. Also, in its reply, North Carolina
Commission urges the Commission not to be overly
prescriptive with respect to the details of regional
transmission planning.
301 E.g., Allegheny, Constellation, and Duke.
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regional participation, because regional
reliability organizations do not have
mandates or authority to ensure that
adequate system expansion occurs on a
coordinated basis.
513. MISO is concerned the
Commission intends to shift
transmission planning responsibility
from RTOs to the Regional Entities
under the ERO, arguing that these
entities have neither a sufficient level of
independence nor a track record in
transmission planning. TDU Systems
suggest that RTOs, where they exist,
should perform the regional planning
function, although in some other
instances it may be the regional
reliability organizations. Although
CAISO states that a larger regional entity
with the authority to order expansion
has some appeal, it contends there are
too many hurdles to creating such an
entity in the West. TAPS suggests a
‘‘Regional Joint Planning Committee’’
that is not dominated by transmission
providers, which would direct the study
process and be responsible for the
development of uniform planning
criteria, assumptions for base and
changed cases, and transmission plans.
Existing Regional Planning Processes
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The West
514. Transmission provider
commenters in the West (outside
California) generally recommend the
Western Electricity Coordinating
Council (WECC) 302 as a successful
institution and an appropriate model for
designating regions and developing a
plan for the interconnection.303 Many
public power entities and others in the
West also support WECC and suggest
that it should be a primary focus when
deciding which institution can provide
independent regional review and
coordination of grid planning in the
West.304 For example, California
Commission notes that WECC’s
Transmission Expansion Planning
Policy Committee allows for the
consolidated needs of all the system
operators in the Western
Interconnection to be considered in the
planning process and considers both
302 In general, WECC and its sub-regional groups
have adopted an overall division of labor whereby
WECC has undertaken facilitation of interstate,
commercial transmission projects and the subregional groups have facilitated the planning of
their member providers.
303 E.g., ColumbiaGrid, MidAmerican, Nevada
Companies, NorthWestern, Pinnacle, and Xcel.
304 E.g., Anaheim, APPA, California Commission,
Imperial, LDWP, NCPA, PGP, Public Power
Council, CREPC, Salt River, Santa Clara, Seattle,
TANC, WAPA, and Western Governors. APPA
notes, however, that not all of its members that
support the WECC planning process support those
within California.
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reliability and economic transmission
planning. California Commission also
stresses that the processes in the West
have resulted in transmission being
built. Utah Municipals, however, are
critical of the WECC process, and in
reply, assert that the WECC process does
not allow for effective stakeholder
input, but merely review of
transmission plans once they are
formed. Utah Municipals also believe
that sub-regional groups in its area (e.g.,
the Southwest Transmission Expansion
Plan (STEP)) are more effective and
urges the Commission to focus on the
effective implementation of joint
plans.305
515. Other commenters support the
sub-regional planning processes in the
West as well, and generally believe the
Commission should look to each subregion’s existing processes and
institutions.306 For example,
commenters in the Southwest and
California also support the sub-regional
groups located in that region (e.g., STEP
and the Southwest Area Transmission
Expansion Planning group (SWAT)).307
California Commission also supports the
CAISO planning process and states that
CAISO works closely with stakeholders
to proactively identify needed, cost
effective transmission solutions through
an open, non-discriminatory process
that has resulted in $1.8 billion in
transmission being constructed.308 In its
reply, NCPA emphasizes that the
Commission should not equate the
CAISO planning process with a
California-wide process, because not all
transmission providers in California are
members of CAISO. However, California
Commission notes that California, with
the support of WECC, has begun the
work of creating a California-wide subregional planning group that includes
305 Public Power Council does not support
expansion of WECC’s role in coordinating planning
beyond its current activities, as it believes WECC’s
strength lies in the area of reliability and not
planning and, therefore, that WECC would be best
served by focusing on reliability and standards
enforcement, rather than as a participant (as a
facilitator or otherwise) in commercial matters.
306 WAPA points out that certain broad functions
related to planning can be coordinated at the
regional level, but that sub-regional planning is
necessary in an expansive regional area, such as
WAPA’s service territory, in order to provide focus
and detail.
307 E.g., LDWP, New Mexico Attorney General,
and Salt River. LDWP also cites its involvement in
the Public Power Initiative of the West, CAISO, and
the Western Arizona Transmission System group.
308 Anaheim believes that the CAISO process does
not currently proactively evaluate the adequacy of
the system or itself propose projects that will
enhance reliability or efficiency and is based
entirely upon plans presented to it by transmission
owners. It notes, however, that CAISO has proposed
reforms to address these issues. See also Anaheim
Reply.
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the large, unregulated municipal
utilities that do not participate in
CAISO.
Northeast
516. PJM, NYISO, and ISO New
England all have transmission planning
processes that have been approved by
the Commission. ISO/RTO Council cites
billions of dollars of transmission
investment in the Northeast as an
example of the success of these
transmission planning processes and
argues that these processes all satisfy
the Commission’s principles for
coordinated, open, and transparent
planning. PJM maintains that its
Regional Transmission Expansion
Planning Protocol is a successful and
comprehensive regional planning
paradigm. ISO New England also argues
that its transmission planning meets the
principles and further points to the
Northeastern ISO/RTO Planning
Coordination Protocol as providing
coordinated planning across the entire
Northeast region.
517. Utilities in the Northeast are
generally supportive of the transmission
planning in the Northeast RTOs.
Designated NY Transmission Owners
contend that the NYISO Comprehensive
Reliability Planning Process is fully
open, coordinated, and transparent and
meets or exceeds each of the eight
principles in the NOPR. PSEG believes
the PJM planning process embodies the
NOPR principles. Constellation cites the
planning processes in PJM and the
NYISO as examples of planning
processes that, while not perfect, should
serve as models for compliance filings
by others. Old Dominion, however,
expresses concern over continuing
domination of transmission planning by
transmission owners, but nevertheless
commends PJM for recent efforts to
include more stakeholder input in the
planning process. National Grid is
generally supportive of ISO New
England’s planning process.
Northwest
518. Several commenters in the
Northwest generally support the
Northwest Power Pool and the
ColumbiaGrid process (which will
provide for a biennial transmission
expansion plan for certain entities in the
Northwest).309 Also, two groups in the
Northwest are forming to address subregional planning in that region—the
ColumbiaGrid group and the Northern
Tier Transmission Group—but it is not
309 E.g., Bonneville, ColumbiaGrid, PGP, Public
Power Council, and Seattle. APPA also notes its
members’ support for the sub-regional processes in
the Northwest.
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yet clear how such groups intend to
coordinate with each other.
Southeast
519. The public power commenters in
the Southeast were not as supportive of
the existing regional and sub-regional
planning processes in their region. TVA
and Santee Cooper generally support the
process conducted by the Southeast
Electric Reliability Council (SERC), and
Santee Cooper notes that it has had a
formal joint planning process with its
largest wholesale customer for more
than 25 years. APPA, however, notes
that its members did not generally
endorse existing regional entities in the
Southeast. APPA states that SERC, for
example, just ‘‘rolls up’’ the
transmission plans of the transmission
providers, and some working groups
currently exclude non-transmission
owners.310
North Carolina
520. NCEMC points to the North
Carolina Transmission Planning
Collaborative (NC Transmission
Planning), a joint planning process with
an independent facilitator, in North
Carolina. NCEMC emphasizes that more
than regional coordination is required
and that regional planning needs to be
more than mere stakeholder review and
must allow for full participation of LSEs
in planning. NCEMC stresses that
effective regional planning requires
participation on a sufficient scale to
encompass all LSEs within a natural
market area in order to properly address
seams issues and impacts on
neighboring systems. Fayetteville does
not believe NC Transmission Planning
complies with the planning principles
outlined in the NOPR.
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Midwest
521. MISO believes its current
transmission planning process
represents industry best practices,
arguing that it is open and inclusive and
provides multiple opportunities for
entities to participate. MISO
Transmission Owners endorse the
existing MISO transmission planning
process and believe that the process
already provides for regional planning
and an open process with stakeholder
involvement. Ohio Power Siting Board,
however, claims that MISO’s
transmission planning process should
not be regarded as best practices, stating
that it is not sufficiently open and
transparent. It also suggests that RTOs
merely ‘‘rubber stamp’’ investor-owned
310 See
also TDU Systems Reply.
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utility plans. Additionally, FMPA 311
notes that MidAmerican has recently
made efforts to engage in more proactive
planning and has offered joint
transmission investment opportunities.
FMPA also points to its membership in
CAPX 2020, a consortium of Upper
Midwest utilities, which are jointly
studying and planning for the needs of
regional transmission. However, FMPA
makes clear that it believes smaller
customers nevertheless need a tariff
requirement for planning to ensure that
their needs are addressed.
Florida
522. While the Florida Commission
believes that the planning process
conducted by the Florida Reliability
Coordinating Council (FRCC) is
adequate, others, such as FMPA, do
not.312 Florida Commission states that
the FRCC has instituted a transparent
and inclusive planning process whereby
utilities, generators, and marketers
participate in joint transmission
planning studies and evaluate
impediments to transfer capability and
determine solutions to congestion in
order to enhance the reliability of the
FRCC system.
Commission Determination
523. We adopt the NOPR’s proposal to
include a regional participation
principle as a component of the Final
Rule’s transmission planning process.
Accordingly, in addition to preparing a
system plan for its own control area on
an open and nondiscriminatory basis,
each transmission provider will be
required to coordinate with
interconnected systems to (1) Share
system plans to ensure that they are
simultaneously feasible and otherwise
use consistent assumptions and data
and (2) identify system enhancements
that could relieve congestion or
integrate new resources (discussed
further below).313
524. As discussed earlier in this Final
Rule, since the advent of open access,
power markets have become regional in
almost every area of the country. These
regional markets provide opportunities
311 We note that FMPA filed joint comments on
behalf of itself and the Midwest Municipal
Transmission Group.
312 See also Seminole Reply.
313 As provided for above, transmission providers
will be required to file a ‘‘strawman’’ proposal for
compliance with the Final Rule’s planning process
within 75 days after publication of the Final Rule
in the Federal Register that includes, among other
things, a specification of the broader region in
which they propose to conduct coordinated
regional planning. The Commission will then
convene technical conferences in several broad
regions around the country to assist the participants
in developing the appropriate regional planning
groups to the extent they do not already exist.
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12331
for wholesale customers to access
competitive sources of supply, rather
than relying exclusively on local
generation, including resources owned
by their local transmission provider.
However, as discussed above, it is not
in the economic self-interest of
transmission providers to expand the
grid to permit access to competing
sources of supply. A transmission
provider has little incentive to upgrade
its transmission capacity with its
interconnected neighbors if doing so
would allow competing suppliers to
serve the customers of the transmission
provider. We therefore find, as
discussed in greater detail above, that
greater coordination and openness in
transmission planning is required, on
both a local and regional level, to
remedy undue discrimination. The
coordination of planning on a regional
basis will also increase efficiency
through the coordination of
transmission upgrades that have regionwide benefits, as opposed to pursuing
transmission expansion on a piecemeal
basis. The specific features of the
regional planning effort should take
account of and accommodate, where
appropriate, existing institutions, as
well as physical characteristics of the
region and historical practices.
525. The Commission is encouraged
that a number of voluntary coordinated
and regional planning efforts have been
developed throughout the country,
including those administered by RTOs
and ISOs and in certain sub-regions of
the West and Southeast. For example,
each of the Commission-approved RTOs
in the Northeast, Midwest, and
Southwest, as well as CAISO, provide
for a coordinated and regional planning
process with stakeholder input from
each industry segment. There are
several other promising efforts to
establish voluntary coordinated and
regional planning efforts around the
country as noted in our discussion
above of existing regional planning
processes.
526. The Commission fully supports
these existing efforts and believes some
of them are consistent in significant
respects with the nature of the reforms
adopted in this Final Rule. In those
regions and sub-regions that already
have adopted significant reforms, the
Commission’s planning reforms may
require only modest changes, while
other regions and sub-regions may need
to undertake more significant changes to
the way in which transmission currently
is planned. The Commission will not in
this Final Rule opine on the
characteristics of existing regional
planning processes or their consistency
with the reforms we adopt today.
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Rather, each process will be addressed
in the context of the relevant
compliance filing. In general, however,
the Commission urges participants in
existing regional planning processes to
closely examine whether improvements
may be implemented to ensure that each
regional planning process is fully
consistent with the requirements of this
Final Rule.
527. Finally, the Commission
acknowledges the importance of
identifying the appropriate size and
scope of the regions over which regional
planning will be performed. We agree
that transmission providers, customers,
affected State authorities, and other
stakeholders should be involved in
developing those regions. We decline to
mandate the geographic scope of
particular planning regions at this time.
The scope of a particular planning
region should be governed by the
integrated nature of the regional power
grid and the particular reliability and
resource issues affecting individual
regions and sub-regions. In very large
regions, there may well be both subregional and regional processes. For
example, in the West there are various
sub-regional processes in addition to a
WECC regional planning process. We
believe that such an approach can work,
provided that there is adequate scope to
the sub-regional processes and adequate
coordination between sub-regions. We
expect sub-regions to coordinate as
necessary to share data, information and
assumptions as necessary to maintain
reliability and allow customers to
consider resource options that span the
sub-regions.
528. In response to the commenters
that indicate that regional planning
already occurs today as part of the
NERC planning process, we support any
such processes, but reiterate that, if they
are to meet the requirements of the Final
Rule, they must be open and inclusive
and address both reliability and
economic considerations. As we discuss
elsewhere in this section, customers
must be allowed to request that
economic upgrades be studied and,
therefore, we will require transmission
providers to coordinate on these issues
as necessary in sub-regional or regional
planning processes. To the extent the
NERC processes are not considered
appropriate for such economic issues,
individual regions or sub-regions may
develop alternative processes.
h. Economic Planning Studies
529. In the NOPR, the Commission
proposed to require transmission
providers to prepare studies identifying
‘‘significant and recurring’’ congestion
and post such studies on their OASIS.
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The Commission explained that the
studies should analyze and report on (1)
The location and magnitude of the
congestion, (2) possible remedies for the
elimination of the congestion, in whole
or in part, (3) the associated costs of
congestion, and (4) the cost associated
with relieving congestion through
system enhancements (or other means).
The Commission sought comment on
how to define ‘‘significant and
recurring’’ congestion, such as by
reference to generation redispatch,
repeated denials of service requests,
zero ATC, frequent curtailments or a
combination of these factors. The
Commission noted that the required
congestion studies would address both
‘‘local’’ congestion (i.e., within the
transmission provider’s system) and
congestion between control areas and
sub-regions. The Commission stated that
the purpose of this requirement is to
ensure that affected market participants,
State commissions, and the Commission
understand both the costs of recurring
transmission congestion and the
alternatives for relieving it. The
Commission sought comment on how
this information should be used by
transmission providers and market
participants to address significant and
recurring congestion.
Comments
Need for Congestion Studies
530. The Commission’s proposal
regarding congestion studies gave rise to
a wide range of comments. Some
commenters generally support requiring
congestion studies.314 East Texas
Cooperatives asserts that congestion
studies will greatly assist in the
development of transmission plans,
enable planning participants to focus on
key elements of the system and assist in
the preparation of the congestion
studies conducted by DOE. NRECA also
supports requiring congestion studies,
but urges the Commission not to be
prescriptive.
531. Other commenters recommend
eliminating the requirement.315
Southern, for example, argues that
congestion studies could be misleading
because they can imply that all
congestion needs to be remedied.316
314 E.g., APPA, Arkansas Commission, California
Commission, East Texas Cooperatives, Entegra,
NCPA, CREPC, Southwestern Coop, TDU Systems,
and WIRES.
315 E.g., American Transmission, EEI, Progress
Energy, and Southern.
316 Entegra, however, replied to Southern’s
assertion that congestion studies can be misleading,
stating that congestion studies did not need to be
misleading, and were, on the contrary, necessary for
customers to assess the costs of managing versus
eliminating congestion.
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Duke, South Carolina E&G, and
Southern agree that separate studies of
congestion, beyond studies performed to
meet service requests, should not be
required. Rather than mandating
congestion studies, Southern argues that
the Commission should allow
participants to determine which types of
transmission studies have merit. Other
commenters believe that, if congestion
studies are required, they should be
performed at a regional level rather than
by each transmission provider
individually.317
532. The EEI position is
representative of entities calling for
elimination of the congestion study
principle. EEI asserts that these studies
in large part would be duplicative of the
studies being performed by DOE
pursuant to EPAct 2005.318 EEI also
argues that these studies would be
costly and time-consuming and that
transmission providers generally do not
have access to information needed for
cost impact analysis and consequently
cannot assess the cost of constraints.319
TDU Systems assert on reply that it is
difficult to imagine that providers do
not have the information needed or
means to determine the location and
magnitude of congestion on their
systems, since they perform this
function for themselves already. TDU
Systems add that customers will readily
provide any information needed for
congestion studies, as it is in their
interest to do so. APPA believes that
customers should be expressly required
to produce information to help
determine the cost of congestion (e.g.,
the additional cost to them of running
or purchasing more expensive
generation). TDU Systems also argues
that the distinction between economic
and reliability upgrades is a fiction and
should be disregarded.
533. In the Western Interconnection,
entities maintain that WECC will be
performing congestion studies that
should meet the requirement. As a
result, they assert that this principle
should not be applied to individual
transmission providers in the West, but
that these providers should be permitted
to meet the principle through the
interconnection-wide congestion studies
conducted by WECC. Tacoma notes that
ColumbiaGrid is considering the
317 E.g., Imperial, MidAmerican, Nevada
Companies, NorthWestern, Pinnacle, Salt River,
SWAT, WestConnect, and Xcel.
318 Others assert that the DOE studies will be
useful but not necessarily duplicative of the
congestion study principle. E.g., APPA and Salt
River.
319 Bonneville agrees that the costs of congestion
itself are not readily available to transmission
providers and that customers are better positioned
to determine this.
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services it can offer in congestion
assessment at the sub-regional level in
the Northwest. Other commenters, such
as California Commission, Salt River,
and Seattle, support a congestion
studies requirement but believe it
should not be required annually but
rather biennially or triennially.
534. In the Eastern Interconnection,
RTOs and ISOs, and entities in RTOs
and ISOs, believe congestion studies are
not needed where LMP markets are in
place or are satisfied by RTO or ISO
studies.320 Entergy argues that the
congestion studies that will be
performed by its independent
coordinator of transmission should meet
this requirement.
Determining ‘‘Significant and
Recurring’’ Congestion
535. A variety of commenters provide
suggestions as to what constitutes
‘‘significant and recurring’’ congestion.
TDU Systems believe that there should
be a presumption of congestion if a
transmission provider posts zero ATC.
TDU Systems, APPA, and Bonneville
believe that other indications of
significant and recurring congestion
include the need for frequent generation
redispatch, frequent curtailments for
reasons other than force majeure, and
repeated denials of requests for firm
transmission service. California
Commission and CREPC suggest a
similar approach based on a comparison
of ATC and schedules with historical
flows and an assessment of denied
requests, but emphasize that the process
should be forward-looking as well.
536. APPA suggests the use of metrics
to measure congestion (e.g., reporting on
all congestion costs that exceed five
percent of base energy costs and five
percent of the hours in a season).
California Commission also suggests the
use of metrics, but cautions that there
may be East-West differences.
Sacramento stresses that such metrics
should depend on whether the system
being studied uses LMP or physical
rights. In its view, financial metrics are
most useful in LMP markets, while
congestion in physical markets should
be determined by paths that have been
derated by a material percent of their
nominal rating over a certain number of
hours in a season.
537. Santa Clara suggests that
significant and recurring congestion
exists when congestion costs over a
given path during the high use season
approach or exceed the depreciation
plus other fixed costs on the new
facilities that would eliminate
320 E.g., Allegheny, FirstEnergy, Indianapolis
Power, and PSEG.
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congestion on the path. Additionally,
Santa Clara emphasizes that if,
redispatch is necessary on an ongoing
basis, this should be taken as an
indication that new facilities need to be
built.
538. New York Commission urges the
Commission to utilize NYISO’s process
for measuring historical congestion—
defined as the short-run production (i.e.,
dispatch) costs that could be avoided by
system enhancements, as this represents
the savings to society compared to the
cost to society of investing in the system
enhancement. New York Commission
also cautions the Commission against
using analyses focused on the impacts
of transmission investments on
wholesale energy prices, because these
energy price impacts may be temporary
and offset by changes in generation
investments. TDU Systems and Old
Dominion stress that in PJM significant
and recurring congestion should be
based on total gross congestion and not
the much smaller and unrealistic
measure of unhedgeable congestion, as
this masks the economic reality that
congestion itself has an economic
cost.321
539. The Organizations of MISO and
PJM States do not believe the Final Rule
should address criteria for determining
significant and recurring congestion, but
should require each transmission
provider to file criteria for inclusion and
cost responsibility for upgrades that are
included in the transmission plan to
remedy congestion.
540. Seattle asserts that current
OASIS standards do not support
consistent tracking of service denials
and that this inhibits the evaluation of
congestion. Seattle also points out that
the costs of congestion may be difficult
to quantify because reliability dispatch
is a reactive tool used only after service
requests have been denied and
prescheduled limits imposed and,
therefore, foregone transactions will not
be known to the transmission provider.
541. Ohio Power Siting Board asserts
that distributed generation, demand
response, and new technologies should
be available to relieve congestion until
longer-term solutions can be
implemented.
Commission Determination
542. The Commission adopts the
NOPR proposal and retains a congestion
study principle as part of the Final
Rule’s transmission planning process;
however, we modify and clarify the
principle in certain important respects
in response to the comments received.
At the outset, we wish to clarify that our
321 See
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12333
primary objective in adopting this
principle is to ensure that the
transmission planning process
encompasses more than reliability
considerations. Although planning to
maintain reliability is a critical priority,
it is not the only one. Planning involves
both reliability and economic
considerations. When planning to serve
native load customers, a prudent
vertically integrated transmission
provider will plan not only to maintain
reliability, but also consider whether
transmission upgrades or other
investments can reduce the overall costs
of serving native load. Such upgrades
can, for example, reduce congestion
(redispatch) costs or integrate efficient
new resources (including demand
resources) and new or growing loads.
Thus, to represent good utility practice
and provide comparable service, the
transmission planning process under
the pro forma OATT must consider both
reliability and economic considerations.
The purpose of this principle is to
ensure that the latter is considered
adequately in the transmission planning
process.
543. Some commenters argue that
economic upgrades should be
considered only in the context of
individual requests for service under the
pro forma OATT. The Commission
disagrees. The process for addressing
individual requests for service under the
pro forma OATT is adequate for
customers who request specific
transmission rights to purchase power
from a particular resource in a particular
location during a defined time period.
However, it does not provide an
opportunity for customers to consider
whether potential upgrades or other
investments could reduce congestion
costs or otherwise integrate new
resources on an aggregated or regional
basis outside of a specific request for
interconnection or transmission service.
It thus limits, for example, groups of
customers from considering more
comprehensive solutions to
transmission congestion, including
investment in demand response. It also
limits multiple LSEs from considering,
on a more aggregated basis, whether
particular upgrades may represent the
most economic means of integrating
new generation resources (e.g., wind
resources) located in a common area
that could be accessed by many
customers. The Commission believes
such coordinated studies can, for system
planning purposes, be more beneficial
than studies performed on a request-byrequest basis. We also find that they are
consistent with the requirement to
provide comparable service.
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Transmission providers are not limited,
in serving native load customers, to
studying potential transmission
upgrades only in the context of specific
requests for service under the pro forma
OATT.
544. Some transmission providers
appear to object to this principle
because they fear that an obligation to
study potential upgrades is equivalent
to an obligation to fund or build such
upgrades. We clarify that this is not the
intent of this principle. There is a
difference between a planning process
that is coordinated and open and one
that dictates construction and cost
responsibility. Both considerations are
important, but, as we explain above,
they are distinct. The purpose of this
principle is to ensure that customers
may request studies that evaluate
potential upgrades or other investments
that could reduce congestion or
integrate new resources and loads on an
aggregated or regional basis (e.g., wind
developers), not to assign cost
responsibility for those investments or
otherwise determine whether they
should be implemented. The issue of
cost allocation is addressed in Principle
No. 9 below.
545. The Commission also disagrees
with the contentions of certain RTOs or
ISOs that they need not comply with
this principle. Although RTO and ISO
planning processes tend to be more
open and coordinated than the
processes used by vertically-integrated
transmission providers, this does not
mean that RTO or ISO processes
adequately address, in all
circumstances, investments that are
primarily economic in nature. When
many RTO and ISO planning processes
were created, they focused primarily on
system enhancements necessary to
maintain reliability. However, in recent
years, as congestion has increased and
generation reserve margins have
declined, many RTOs and ISOs have
taken increasingly progressive steps to
identify investments that could reduce
congestion and/or integrate new
resources. For example, we recently
approved a proposal by PJM to
significantly enhance its RTEP planning
process.322 We applaud these efforts as
consistent with the direction of the
reforms adopted herein. However, we
decline to provide a blanket exception
for RTOs and ISOs. Each RTO or ISO
must show that its planning process is
consistent with or superior to the
requirements of the Final Rule in all
respects.
322 See PJM Interconnection, L.L.C., 117 FERC
¶ 61,218 (2006), reh’g pending.
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546. Some commenters express
concern that this principle may result in
costly congestion studies that are of
little interest or value to customers. Our
intent is not to impose a costly study
requirement that is unrelated to the realworld concerns of consumers. In the
NOPR, we sought comment on whether
specific metrics (e.g., zero ATC or TLR
frequency) should be used to trigger the
congestion study requirement. After
considering the comments on this topic,
we do not believe that any single metric,
or group of metrics, is adequate for that
purpose. Relying on discrete metrics in
this instance would risk both over- and
under-inclusiveness—i.e., triggering too
many studies, thereby imposing cost
burdens on transmission providers that
are not appropriate, or triggering too few
studies, thereby omitting important
studies that could help customers
identify cost-effective solutions to
congestion. Additionally, we direct
transmission providers, in consultation
with their stakeholders during
development of their Attachment K
compliance filings (as discussed above),
to develop a means to allow the
transmission provider and stakeholders
to cluster or batch requests for economic
planning studies so that the
transmission provider may perform the
studies in the most efficient manner. We
will also require the requests for
economic planning studies, as well as
the responses to the requests, be posted
on the transmission provider’s OASIS or
Web site, subject to confidentiality
requirements.
547. The Commission will modify the
principle to allow customers to choose
the studies that are of the greatest value
to them. Specifically, we are modifying
the principle to require that
stakeholders be given the right to
request a defined number of high
priority studies annually (e.g., five to
ten studies) 323 to address congestion
and/or the integration of new resources
or loads. The intent of this approach is
to allow customers, not the transmission
provider, to identify those portions of
the transmission system where they
have encountered transmission
problems due to congestion or whether
they believe upgrades and other
investments may be necessary to reduce
congestion and to integrate new
resources. The customers should be able
to request that the transmission provider
study enhancements that could reduce
such congestion or integrate new
323 The
example of five to ten studies mentioned
in this Final Rule is merely illustrative. We
recognize that the facts of each case will be used
to determine the number of high priority studies
allowed under a transmission plan.
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resources on an aggregated or regional
basis without having to submit a
specific request for service. This
approach ensures that the economic
studies required under this principle are
focused on customer needs and
concerns, not administratively
determined metrics that may bear no
necessary relation to those concerns.
Once such studies are requested, the
transmission provider would conduct
the studies, including appropriate
sensitivity analyses, in a manner that is
open and coordinated with the affected
stakeholders. The cost of the defined
number of high priority studies would
be recovered as part of the overall pro
forma OATT cost of service.324 By
limiting this principle to a defined
number of high priority studies
annually, we are not precluding
stakeholders from requesting additional
studies. However, to provide
appropriate financial incentives, the
stakeholder(s) requesting these
additional studies would be responsible
for paying the cost of such studies.
548. We also will modify this
principle with respect to the scope of
the studies being performed. The
Commission proposed in the NOPR that
the studies address ‘‘significant and
recurring congestion.’’ However, the
Commission also sought comment on
whether, in addition, the study process
should address upgrades associated
with new generation resources and
provide information needed to
proactively evaluate such resources. We
discuss the comments on this proposal
in more detail below, but, as described
therein, we agree that the study process
should incorporate such considerations.
We therefore modify Principle No. 8 to
encompass the study of upgrades to
integrate new generation resources or
loads on an aggregated or regional basis.
This is appropriate because congestion
can limit both the efficient dispatch of
existing generation resources as well as
inhibit the development of new supply
and demand resources. Moreover, many
regions of the country must make
investments in the near future to meet
load growth and, accordingly, studies of
the most economic means of making
such investments are critically
important to consumers.
549. By expanding the scope of this
principle, we do not intend to supplant
the existing process for individual
customers to integrate new resources or
loads through specific requests for
324 This cost recovery mechanism is comparable
and nondiscriminatory because the transmission
provider already has the ability to include in its pro
forma OATT rates the cost of service associated
with studies performed on behalf of native load
customers.
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interconnection or transmission service
under the pro forma OATT. Rather, we
contemplate that any such studies
conducted pursuant to this principle, as
explained above, would be for purposes
of planning for the alleviation of
congestion through integration of new
supply and demand resources into the
regional transmission grid or expanding
the regional transmission grid in a
manner that can benefit large numbers
of customers, such as by evaluating
transmission upgrades necessary to
connect major new areas of generation
resources (such as areas that can
support substantial wind generation).
Specific requests for service would
continue to be studied pursuant to
existing pro forma OATT processes.
550. With respect to studying the cost
of congestion, several transmission
providers argue that they do not have
access to information regarding
generation costs either from their
merchant function or unaffiliated
customers. We agree that the
transmission provider should be
obligated to study the cost of congestion
only to the extent it has information to
do so. We make clear, however, that if
stakeholders request that a particular
congested area be studied, they must
supply relevant data within their
possession to enable the transmission
provider to calculate the level of
congestion costs that is occurring or is
likely to occur in the near future. To the
extent that the transmission provider’s
merchant function possesses such
information (e.g., redispatch cost
information), it must provide that
information to the extent necessary to
conduct such studies. Providing for
confidential treatment and application
of the Standards of Conduct, as
discussed above, will give assurance to
customers that their cost and other
information will not be used
improperly. To that end, we direct
transmission providers to clearly define
the information sharing obligations
placed on customers in the planning
attachment to their pro forma OATT.
551. In response to those commenters
that argue that regional congestion
studies should be sufficient, we agree
that regional congestion studies can be
used as part of regional transmission
planning processes required by this
Final Rule. For example, to the extent
the DOE has extensively studied
congestion in certain broad areas, it is
not necessary or appropriate for
transmission providers to duplicate
these studies. However, regional studies
typically provide broad information on
overall regional power flows and may
not provide sufficient detail on local
system conditions and congestion, such
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as detail on congested local facilities
that may limit customer supply options,
or detail on local conditions where
additional service could be provided
through redispatch. Moreover, although
the DOE may identify areas where
congestion exists or new generation may
be developed, the purpose of DOE
congestion studies is not to develop
specific transmission system plans to
remedy such congestion or integrate
such resources. The DOE studies are
therefore not a substitute for a more
open and coordinated planning process
to address specific upgrades that could
reduce congestion or integrate new
resources and loads. We therefore
require each transmission provider to
comply with the revised economic
planning studies principle in this Final
Rule both as to its own transmission
system and as to the regional planning
process described above.
i. Cost Allocation for New Projects
552. In the NOPR, the Commission
asked for comment on whether there
should be a requirement for public
utilities to develop cost allocation
principles to address the recovery of
costs associated with new transmission
projects. In particular, the Commission
asked whether the development of
specific cost allocation principles would
provide greater certainty and hence
support the construction of new
infrastructure or whether cost allocation
is better handled on a case-by-case
basis.
Comments
553. Several commenters express
concern that the Final Rule not reopen
cost allocation principles in RTOs and
ISOs or in the OATTs of vertically
integrated transmission providers.325
Duke argues that the Final Rule should
not address cost allocation for new
transmission at all, stating that
transmission pricing should be
evaluated in a separate proceeding.
Other commenters agree that cost
allocation issues should be handled on
a case-by-case basis.326
554. Some commenters urge the
Commission to define cost allocation
principles in this proceeding.327 For
example, E.ON believes that the cost of
upgrades should be directly allocated to
parties benefiting from an expansion
and proposes that the host transmission
owner should coordinate and be
responsible for obtaining funding. Many
325 E.g., Duke, EEI, ELCON, ISO/RTO Council,
MISO Transmission Owners, SCE, and Southern.
326 E.g., APPA, Arkansas Commission, PGP,
Santee Cooper, Southwestern Coop, and
Sacramento.
327 E.g., E.ON, National Grid and WIRES.
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12335
transmission customers, however,
support rolled-in cost recovery for
network upgrades.328 TDU Systems ask
the Commission to clarify that direct
assignment of facility upgrade costs
only applies to point-to-point service,
unless it is being used for the delivery
of designated network resources to serve
network load. If direct assignment is
retained, TDU Systems suggest the
Commission consider standardizing
directly assignable facilities on a
regional basis and stress that the critical
factor is comparability. TAPS suggests
‘‘regional’’ cost-spreading for backbone
high voltage facilities and criticizes
participant funding because it
encourages would-be beneficiaries to
wait and hope that others will step
forward first.
555. Old Dominion emphasizes the
need for cross-border transmission cost
allocation mechanisms. In joint projects,
Salt River emphasizes that it is
inconsistent with an open season
approach to assign benefits to a party
and then assign cost responsibility
beyond what the project participant
would voluntarily assume based on the
subscription rights received. Both
Bonneville and TVA believe that cost
allocation principles should be based on
a determination of beneficiaries and cost
causation. New Mexico Attorney
General stresses that cost recovery for
construction of transmission intended
for wholesale or market transactions
should not be allocated to native load.
NCPA states that it would expect some
Commission deference to recovery of
costs of projects identified in a truly
collaborative process.
556. At the October 12 Technical
Conference, PJM stated that the
Commission should provide generic
guidance on what would be acceptable
regarding cost allocation, though
Progress Energy did not favor putting a
cost allocation approach in the pro
forma OATT, as modified by the Final
Rule. National Grid expressed the view
that the Commission would need to
address cost allocation generally,
arguing that cost allocation solely on a
project-by-project basis is inefficient.
Commission Determination
557. The Commission finds, after
considering the comments, that it is
appropriate to include a specific
principle regarding cost allocation. The
manner in which the costs of new
transmission are allocated is critical to
the development of new infrastructure.
Transmission providers and customers
cannot be expected to support the
328 E.g., AWEA, NCEMC, NCPA, NRECA, Seattle,
and TDU Systems.
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construction of new transmission unless
they understand who will pay the
associated costs. We therefore find that,
for a planning process to comply with
the Final Rule, it must address the
allocation of costs of new facilities.
558. The Commission emphasizes,
however, that we are not modifying the
existing mechanisms to allocate costs
for projects that are constructed by a
single transmission owner and billed
under existing rate structures. Our
intent is not to upset existing cost
allocation methods applicable to
specific requests for interconnection or
transmission service under the pro
forma OATT. The cost allocation
principle discussed herein is intended
to apply to projects that do not fit under
the existing structure, such as regional
projects involving several transmission
owners or economic projects that are
identified through the study process
described above, rather than through
individual requests for service. We will
not impose a particular allocation
method for such projects, but rather will
permit transmission providers and
stakeholders to determine their own
specific criteria which best fit their own
experience and regional needs. The
proposal should identify the types of
new projects that are not covered under
existing cost allocation rules and,
therefore, would be affected by this cost
allocation principle.
559. Although the Commission does
not prescribe any specific cost
allocation method in the Final Rule, we
believe some overall guidance is
appropriate. Our decisions regarding
transmission cost allocation reflect the
premise that ‘‘[a]llocation of costs is not
a matter for the slide-rule. It involves
judgment on a myriad of facts. It has no
claim to an exact science.’’ 329 We
therefore allow regional flexibility in
cost allocation and, when considering a
dispute over cost allocation, exercise
our judgment by weighing several
factors. First, we consider whether a
cost allocation proposal fairly assigns
costs among participants, including
those who cause them to be incurred
and those who otherwise benefit from
them. Second, we consider whether a
cost allocation proposal provides
adequate incentives to construct new
transmission. Third, we consider
whether the proposal is generally
supported by State authorities and
participants across the region.
560. These three factors are
interrelated. For example, a cost
allocation proposal that has broad
support across a region is more likely to
329 Colorado Interstate Gas Co. v. FPC, 324 U.S.
581, 589 (1945).
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provide adequate incentives to construct
new infrastructure than one that does
not. The states, which have primary
transmission siting authority, may be
reluctant to site regional transmission
projects if they believe the costs are not
being allocated fairly. Similarly, a
proposal that allocates costs fairly to
participants who benefit from them is
more likely to support new investment
than one that does not. Adequate
financial support for major new
transmission projects may not be
obtained unless costs are assigned fairly
to those who benefit from the project.
561. These factors are particularly
important as applied to the economic
upgrades discussed above—e.g.,
upgrades to reduce congestion or enable
groups of customers to access new
generation. As a general matter, we
believe that the beneficiaries of any
such project should agree to support the
costs of such projects. However, we
recognize that there are free rider
problems associated with new
transmission investment, such that
customers who do not agree to support
a particular project may nonetheless
receive substantial benefits from it. In
the past, different regions have
attempted to address such issues in a
variety of ways, such as by assigning
transmission rights only to those who
financially support a project or
spreading a portion of the cost of certain
high-voltage projects more broadly than
the immediate beneficiary/supporters of
the project. We believe that a range of
solutions to this problem are available.
We therefore continue to believe that
regional solutions that garner the
support of stakeholders, including
affected State authorities, are preferable.
Moreover, it is important that each
region address these issues up front, at
least in principle, rather than having
them relitigated each time a project is
proposed. Participants seeking to
support new transmission investment
need some degree of certainty regarding
cost allocation to pursue such
investments.
3. Additional Issues Relating to
Planning Reform
a. Independent Third Party Coordinator
562. In the NOPR, the Commission
acknowledged that an independent
third party coordinator would provide
benefits for transmission planning, but
did not propose to require
independence. Noting that
independence could take many forms,
the Commission sought comment on the
level of independence that could
provide benefits and the institutions
that could offer such independence.
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Comments
563. Overall comments on the use of
an independent third party to oversee or
coordinate the planning process range
from those who believe it is not needed
to those who feel that it should be
required rather than merely encouraged.
Arguing against the need for an
independent coordinator, South
Carolina E&G does not believe an
independent third party is either
necessary or desirable. Arguing in favor
of an independent coordinator, EPSA
strongly supports independent oversight
and believes that third party oversight
will be necessary in non-RTO areas,
particularly where transmission
providers have conducted nontransparent processes.330 Most
commenters fall somewhere between
these two positions, finding potential
benefits in independence but concurring
with the proposal not to mandate it.
564. Several public utility
commenters acknowledge the potential
benefits of using an independent
coordinator and believe the Commission
should encourage it.331 National Grid,
for example, finds it difficult to see how
a non-independent transmission
provider would be able to manage
confidential information in a manner
fair to all stakeholders and recommends
finding independent administration of
planning ‘‘superior to’’ nonindependent administration. Other
commenters note only that
independence can be beneficial or
suggest that the Commission be open to
independent third parties when
offered.332 Progress agrees there can be
benefits, but does not believe an
independent coordinator is needed to
ensure confidence.
565. EEI argues against an
independence requirement, seeing no
need to require non-RTO/ISO
transmission providers to engage
independent third parties to oversee the
planning process.333 EEI believes the
330 See also AWEA, Arkansas Commission, Old
Dominion, and Project for Sustainable FERC Energy
Policy. Old Dominion stresses that even in RTOs,
the transmission owners may have the ability to
exercise market power and, therefore, the market
monitoring unit should have the requisite
independence and authority to investigate and
address undue influence.
331 E.g., National Grid, PPL, Constellation, and
Tacoma.
332 E.g., APPA, Bonneville, California
Commission, Duke, Indianapolis Power, NCEMC,
NorthWestern, Progress Energy, CREPC,
Sacramento, Seattle, and TDU Systems. Some
public power entities, such as APPA, NRECA, and
TDU Systems are concerned with ensuring that the
costs of an independent coordinator do not
outweigh the benefits.
333 TVA believes that the levels of independence
practiced in NERC and NAESB and the
implementation and administration of those
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planning processes proposed in the
NOPR are adequate without third party
oversight and maintains that requiring
third party coordination could add
another layer of administration, might
encroach on State authority, and could
create the possibility that the
transmission provider would lose
control of the transmission plan. EEI
however also notes that the Commission
could require independent oversight in
circumstances where a transmission
planner has failed to implement the
principles or has engaged in undue
discrimination in planning for customer
needs.
566. The consensus at the October 12
Technical Conference was generally
supportive of the potential benefits of an
independent facilitator, but not
supportive of a mandate. There was
general support for the idea that an
independent facilitator can assist with
handling sensitive information and
provide confidence that analysis of
information would be fair, although
several participants stated that sufficient
trust and confidence could be obtained
without an independent facilitator.
meaningful concerns if a plan does not
treat similarly-situated customers in a
comparable manner, where planning
appears to be conducted in a
discriminatory manner, or in other
instances where the independence of
planning may be in question. If disputes
do arise in these areas and cannot be
resolved consensually, we are available
to either encourage a consensual
resolution (e.g., by use of the Dispute
Resolution Service) or resolve them
ourselves if a complaint is filed.
b. State Commission Participation
569. In the NOPR, the Commission
strongly encouraged the participation of
State commissions and other State
agencies in the coordinated planning
process, particularly with regard to
regional planning. The Commission
sought comment on how best to
accommodate effective State
participation.
Commission Determination
567. The Commission adopts the
NOPR proposal to not require the use of
an independent third party coordinator
at this time. We agree that there are
benefits to be gained from independent
third party oversight, as cited by
commenters, such as the ability to
manage confidential information and
the ability to ensure equitable treatment
of all viewpoints in planning. We
therefore encourage transmission
providers and their customers and other
stakeholders to explore aspects of
planning where the use of an
independent coordinator would be
beneficial and to incorporate those
aspects in their planning process
compliance filings.
568. It is, however, possible to comply
with the principles without the use of
an independent third party. We expect
the transmission plans themselves to be
developed under an open process that
includes coordination among each
transmission provider, its customers,
other stakeholders, and its neighbors. A
transmission provider will need to
demonstrate to us in a compliance filing
that the plan meets the principles,
including providing a dispute resolution
process. We believe that an open,
transparent planning process, with
meaningful coordination and dispute
resolution, will provide a sufficient
basis for customers to identify and raise
Comments
570. All commenters addressing the
question of State participation agree that
states have an important role in
transmission planning, but there were
only limited comments recommending
specific processes to encourage State
participation. Supporters of State
participation generally believe that it
can assist in obtaining siting approval
and in cost recovery. ISO/RTO Council
and individual RTOs and ISOs point to
their current processes for including
states in their region in the planning
process. Noting the local benefits that
can derive from interstate transmission
projects, American Transmission
supports collaborative efforts among
states such as the Organization of MISO
States. However, American
Transmission and other commenters
suggest that the Commission defer to the
states to determine how they participate
in the planning process.334
571. Allegheny believes it should be
the responsibility of the transmission
provider to maintain good
communication with State
commissions. Nevada Companies assert
that the real question the Commission
should be posing is how to coordinate
the State jurisdictional role in
transmission planning and construction
and the obligations imposed by the
Commission on transmission providers,
so that the system of coordination does
not put transmission providers in the
middle between conflicting State and
Commission requirements. Moreover,
Santa Clara notes that some State
commissions do not represent all energy
standards by the regional entitities (such as SERC)
are adequate and appropriate.
334 E.g., American Transmission, Duke, and
Progress Energy.
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12337
consumers, since they are charged only
with regulating public utilities, and
could be conflicted and disinclined to
act in the best interests of entities not
under their jurisdiction.
572. NARUC supports active State
commission participation in both RTO
and non-RTO markets.335 NARUC asks
that the Commission clarify that its
planning proposals assume that the
results of State commission planning
decisions relating to retail load will be
incorporated into the planning process
rather than subject to further review.
NARUC and New Mexico Attorney
General also ask for clarification that
joint planning will allow for
communications between resource and
transmission planners for the purpose of
developing State-required resource
plans and that this will not be
considered a violation of the Standards
of Conduct. PNM–TNMP and Southern
support the NARUC position in their
reply comments.
573. New York Commission wants to
ensure that the Commission’s planning
responsibilities cover only transmission
that serves a bulk power system
function.336 Florida Commission
believes that it already has direct
oversight of grid planning and related
issues, through among other things its
participation in the FRCC planning
process and review of the annual Ten
Year Site Plan. Seattle does not believe
that any additional requirements are
needed for State commission
participation. Other commenters are
concerned that State policy goals, such
as California’s Renewable Portfolio
Standard, be included in the
coordinated planning required by the
Final Rule.337 NARUC and California
Commission also discuss State staff and
fiscal constraints on participation, and
California Commission suggests that the
Commission consider a tariff rider to
fund State participation.
Commission Determination
574. The Commission strongly
encourages State participation in the
transmission planning process and
expects that all transmission providers
will respect states’ concerns, such as
retail resource needs, in the planning
335 Similar views are expressed by APPA,
Arkansas Commission, Bonneville, California
Commission, NCEMC, NYAPP, and CREPC.
NYAPP, however, asks the Commission to be
vigilant in not allowing State commissions
improper control over the planning process.
336 NYAPP, on the other hand, urges the
Commission to require planning for all transmission
facilities, not just bulk power facilities.
337 E.g., AWEA, California Commission, and
Project for Sustainable FERC Energy Policy.
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process.338 As with any other interested
stakeholder, we emphasize that
planning must be coordinated with
relevant State regulators (including city
councils, local siting boards, and other
agencies) that wish to participate in the
transmission provider’s planning
process. We will not prescribe a
particular level of State participation,
but rather encourage states to determine
their own level of participation,
consistent with applicable State law.339
We stress that State determinations with
respect to retail load will not be secondguessed, but that once those
determinations are incorporated into the
transmission plan, the transmission
planning principles will apply (e.g., for
purposes of determining whether
similarly-situated customers are treated
comparably).
575. Just as we intend to coordinate
with State regulators and other agencies,
we also encourage those parties to
collaborate amongst themselves as well,
particularly regionally, in order to reach
agreement on how best to review and
approve new transmission facilities that
are the product of the coordinated and
regional planning process required by
this Final Rule. We intend to defer to
such agreements between State
regulators and other agencies in a given
region as appropriate. We are, moreover,
sensitive to concerns, such as
Allegheny’s, about the overlapping
nature of regulatory jurisdiction over
planning matters. We believe the
planning principles in this Final Rule
will help alleviate this concern by
facilitating coordination through open,
transparent planning and enhanced
exchange of information. We also
understand Santa Clara’s concern that
certain State regulators do not represent
all energy consumers in some states;
however, we do not believe this detracts
from the significant interest that State
regulators and other agencies have with
regard to transmission planning for their
State and region.
c. Flexibility in Implementation and
Examples of Compliant Processes
576. In the NOPR, the Commission
sought comment on how much
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338 As
noted above, we expect the concerns of
NARUC and others that the application of the
Commission’s Standards of Conduct are inhibiting
State resource planning will be addressed in the
rulemaking proceeding on the Standards of Conduct
in Docket No. RM01–7–000. See supra note 257.
339 We also recognize that there are concerns
about how State regulators and other agencies will
recover the costs associated with their participation
in the planning process. As discussed below, we
direct transmission providers to propose a
mechanism for cost recovery in their planning
compliance filings. These proposals should include
relevant cost recovery for State regulators, to the
extent requested.
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flexibility the transmission provider
should be given in implementing the
principles and requested examples of
transmission planning processes that
comply with the proposed principles.
Comments
577. Commenters generally favor
flexibility and urge the Commission not
to be too prescriptive regarding how the
planning processes must satisfy the
planning principles. Many entities in
the Western Interconnection cite the
overall WECC process as largely
compliant with the principles. Nevada
Companies notes that the WECC process
works well under the existing pro forma
OATT, so that few changes should be
required to implement the proposal. In
the East, Progress Energy and Duke cite
NC Transmission Planning as an
example of an effective planning
process that generally meets the
principles.
578. Constellation agrees with
providing flexibility, but believes the
Commission should strongly encourage
transmission providers to model their
compliance filings after existing
processes, such as those in RTOs and
ISOs. ISO/RTO Council and all
individual RTOs and ISOs argue that
their processes are generally compliant
and should not be disturbed.
Transmission providers in RTOs and
ISOs generally support this position.340
579. Some entities believe that
flexibility should be permitted in order
to deal with regional variations, but that
individual transmission providers
should have limited flexibility in
implementing the planning process.341
Some commenters simply state that
regional flexibility should be permitted,
without further elaboration.342 Other
commenters urge the Commission to
limit both regional and local
flexibility.343
580. NRG argues that system planning
models should reflect economic
dispatch to facilitate efficient utilization
and also argues in favor of requirements
for specific criteria on the treatment of
system overloads and contingencies.
AWEA proposes a specific regional
planning protocol patterned off the
‘‘Collaborative Governance’’ model
developed during mediation for the
Southeast RTO in Docket No. RT01–100.
581. In reply to commenters arguing
in favor of less flexibility, Indianapolis
Power maintains that its experience in
340 E.g.,
Allegheny, Duke, and National Grid.
APPA, East Texas Cooperatives, Seattle,
and TDU Systems.
342 E.g., Bonneville, Salt River, PJM, and TVA.
343 E.g., Arkansas Municipal, Project for
Sustainable FERC Energy Policy, and Southwestern
Coop.
341 E.g.,
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MISO shows that flexibility is needed,
citing the wide variations within the
MISO footprint and the difficulties
experienced in planning for a single
large region. MidAmerican opposes the
NRG proposal for regional modeling
standards, as well as the AWEA
proposal for a regional planning
protocol, as too burdensome. Exelon
expresses general agreement with the
EEI position on flexibility, but states
that planning processes outside RTOs
do not presently meet the NOPR’s
requirements. Exelon states planning
processes outside RTOs should follow
the planning direction of RTOs like
PJM.
Commission Determination
582. Although we allow flexibility in
the development of a coordinated and
regional planning process, the
Commission will carefully review
transmission planning compliance
filings to ensure that each planning
process is consistent with the planning
principles and other requirements in
this Final Rule. We encourage
transmission providers to give
consideration to existing planning
processes, such as those already
implemented by ISOs or RTOs, or those
proposed by AWEA, as they work with
their customers and other stakeholders
to develop a transmission planning
process that complies with the Final
Rule. The Commission makes clear,
however, that we do not endorse any
specific existing process as a model for
all transmission providers.
d. Recovery of Planning Costs
583. In the NOPR, the Commission
recognized that participants in the
planning process must be assured of
recovery of their costs incurred in the
planning process, as well as assured that
the costs will be borne equitably by all
parties benefiting from the process. The
Commission also sought comment on
whether there should be a principle or
requirement regarding cost recovery and
allocation associated with funding the
regional planning requirement.
Comments
584. Public utility commenters
generally support the principle that
costs should be borne by the
beneficiaries of the process. EEI agrees,
but argues that the Commission should
not establish a specific cost basis for
recovery, and several other commenters
concur.344 NorthWestern and PSEG
support a cost causation principle for
344 E.g., Duke, Indianapolis Power, MidAmerican,
Progress Energy, PSEG, South Carolina E&G, and
SPP.
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allocation of costs of planning, and
Southern argues that entities that
request any transmission sensitivity
studies should bear the costs of those
studies.
585. There is general agreement with
the principle that costs should be
recoverable, and some public utilities
request that the Commission clarify that
all planning costs not directly assigned
are recoverable through transmission
provider transmission rates.345 Other
commenters believe that the parties in
the planning process should determine
how planning costs should be allocated
and funded. APPA urges simplicity, the
avoidance of double collecting (e.g.,
LSEs should not have to pay through
both transmission rates and
individually) and stresses the need to
assess costs based on size and assets.
Other comments are consistent with
equitable allocation of planning
costs.346
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Commission Determination
586. We will not propose a specific
method for recovery and allocation of
planning costs in this Final Rule. We
recognize, however, the importance of
planning cost recovery and will require
transmission planning processes to
provide a mechanism for recovery of
costs. We direct transmission providers
to work with other participants in the
planning process, as part of the
collaborative process described above,
to develop their cost recovery proposals
in order to determine whether all
relevant parties, including State
agencies, have the ability to recover the
costs of participating in the planning
process. Transmission providers should
also consider whether mechanisms for
regional cost recovery may be
appropriate, such as through agreements
(formal or informal) to incur and
allocate costs jointly. The Commission
will consider resulting cost recovery
proposals, including special riders to
transmission rates, with an eye toward
encouraging the broadest participation
in the planning process possible.
e. Open Season for Joint Ownership
587. In the NOPR, the Commission
expressed its belief that an open season
to allow market participants to
participate in joint ownership,
particularly for large new transmission
projects, could stimulate grid
investment and ensure that all
customers have the ability to participate
in new projects on a nondiscriminatory
basis. The Commission sought comment
on whether to include such a
345 E.g.,
346 E.g.,
Southern and South Carolina E&G.
Bonneville, NRECA, and CREPC.
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requirement and, if so, what conditions
or limitations should be associated with
it.
Comments
588. As a general matter, a number of
commenters believe that the planning
process should include a mandate to
construct identified upgrades or
otherwise hold transmission providers
accountable for carrying out the plan.347
EEI and others argue that such a
mandate would go beyond planning and
result in providers giving up control of
their systems. In their replies, LPPC and
Sacramento assert that the decision to
build facilities and to carry out
transmission plans must rest with
transmission providers and State
authorities and that, in any event, it is
unclear that the Commission has the
authority to compel construction
pursuant to regional transmission plans.
At the October 12 Technical Conference,
there was considerable discussion of the
obligation to build and its relationship
to the planning process proposed in the
NOPR.
589. While not necessarily opposed to
voluntary joint ownership arrangements
in general, many commenters oppose
the idea of mandated open seasons.348
EEI provides a representative summary
of the arguments of those opposed to
open seasons. First, EEI argues that the
Commission does not have the authority
to order joint ownership and that joint
ownership could interfere with State
siting authority. It maintains that the
instances where the Commission can
order transmission construction are very
limited and do not extend to the
authority to order joint ownership.349
Second, EEI argues that joint ownership
will not provide the benefits cited by
the Commission, stating that there is
ample evidence that joint ownership of
transmission lines is not needed to
347 E.g., APPA, East Texas Cooperatives Reply,
FMPA, NCPA, TAPS, TDU Systems, Utah
Municipals, and WIRES.
348 E.g., Allegheny, American Transmission,
Constellation, New York Transmission Owners,
MidAmerican, Duke, EEI, Entergy, FirstEnergy,
MISO, National Grid, Northeast Utilities,
NorthWestern, Progress Energy, PSEG, South
Carolina E&G, SCE, Southern, SPP, Tacoma,
Tucson, and Xcel.
349 APPA, FMPA, TAPS, and TDU Systems,
however, point to various sources of authority on
which the Commission could rely to mandate open
seasons and joint ownership, such as: To remedy
undue discrimination under FPA sections 205 and
206; to carry out FPA section 214(b)(4)’s
requirement to facilitate the planning and
expansion of transmission facilities to satisfy the
needs of load-serving entities; as a condition of
market-based rate authority, FPA section 203
approval, or transmission rate incentives under FPA
section 219; and under the permitting regulations
promulgated under FPA section 216(c)(2)(B) dealing
with backstop siting authority.
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12339
achieve economies of scale in
construction. In its view, the level of
transmission investment is currently
increasing and joint ownership should
not be expected to create additional
sources of transmission investment.
Third, EEI contends that prospective
joint owners mistakenly believe they
will not be subject to the same
requirements as Commissionjurisdictional owners and urge the
Commission to make clear that both
jurisdictional and nonjurisdictional
owners would be subject to the same
requirements for service over jointlyowned facilities. If the Commission
were to order joint ownership, Duke
argues that it must condition such
ownership by a nonjurisdictional entity
on that entity filing a safe harbor OATT
ensuring reciprocal open access by that
joint owner.
590. Tacoma notes that ColumbiaGrid
includes a mechanism for small users to
participate in transmission projects in
the proposal it is considering for its
planning process. Xcel supports
adopting the open season concept as an
option in joint planning requirements.
Though it does not completely oppose
the principle, MidAmerican sees
significant practical problems in
developing and implementing an open
season proposal and regards the open
season idea as premature. Others
generally support allowing for open
seasons and joint ownership, but also do
not believe they should be mandated.350
591. A number of other commenters,
however, support requiring open
seasons as a method of ensuring that
identified upgrades are constructed.
ELCON is strongly in favor, stating that
open seasons for joint ownership is an
‘‘idea whose time has come’’ and
expressing frustration that the
Commission has not already acted on
this proposal. FMPA argues that joint
ownership will aid in providing
additional capital for transmission
projects. TDU Systems urge the
Commission to require transmission
providers, including RTOs and ISOs, to
hold open seasons.351 Joined by
Arkansas Commission, TDU Systems
argue that open seasons should not be
limited to large projects. PGP supports
open seasons when providers do not
voluntarily agree to add capacity based
on the results of the transmission plan.
TDU Systems cite the Neptune and
350 E.g., Bonneville, California Commission, and
CREPC. Bonneville stresses that any jointly-owned
facilities should have a single operator.
351 Similar comments were made by APPA,
Arkansas Commission, FMPA (includes a legal
analysis in an attachment), NCPA, MISO/PJM
States, Santa Clara, Southwestern Coop, TANC, and
TAPS.
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Cross-Sound Cable projects, where
regulated utilities failed to provide
solutions despite the need for expansion
of the system in those regions. Seattle
argues that voluntary joint ownership of
projects should not be contingent upon
an open season requirement. TANC
points to current joint ownership
arrangements in the Western
Interconnection. Sacramento likewise
notes that the joint planning and
ownership process in the Western
Interconnection has been a success, but
asks the Commission to make clear that
physical rights set asides are available
in CAISO to accommodate non-LMP coowners.
592. On reply, EEI, Entergy, and
Southern repeat arguments against joint
ownership and open seasons. EEI
replies that FMPA’s claim that joint
ownership will result in increased
investment is not based on fact and will
not increase access. In its reply, TDU
Systems states that joint ownership
would not, as argued by EEI, infringe on
State siting, as states would retain this
authority over the jointly-developed
project. APPA also stresses that its
members have fewer difficulties
obtaining service where joint ownership
is permitted. In their replies, Lassen,
Santa Clara, and TANC argue that the
Commission should not, as suggested by
Duke, condition the participation of a
nonjurisdictional entity in a jointlyowned project on that entity filing a safe
harbor OATT, as public power entities
use the capacity they need and sell the
rest whether or not they have a safe
harbor OATT on file. However, TAPS
asks on reply that access to jointlyowned facilities be available through a
pro forma OATT. Participants at the
October 12 Technical Conference
expressed both support for joint
ownership, as well as caution. National
Grid states that it has had good success
with joint ownership, but that jointlyowned projects are more complicated
and can take longer to develop.
Commission Determination
593. The Commission believes there
are benefits to joint ownership of
transmission facilities, particularly large
backbone facilities, both in terms of
increasing opportunities for investment
in the transmission grid, as well as
ensuring nondiscriminatory access to
the transmission grid by transmission
customers. The comments received in
response to the NOPR support the
notion that joint ownership can provide
these benefits in many cases. For
example, as TDU Systems note, the
Neptune and Cross-Sound Cable
projects have resulted in significant
amounts of new transmission capacity
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in regions facing chronic constraints.
We encourage joint ownership for other
large backbone transmission upgrades
included in the transmission plan
developed by the planning process
required by this Final Rule.352
594. We acknowledge, however, that
joint ownership can increase the
complexity of planning and developing
a transmission project and are sensitive
to concerns that formal open seasons
can add to that complexity. We
therefore do not mandate open season
procedures to allow market participants
to participate in joint ownership. We
recognize that there may be reasons,
given the complexity of the
transmission grid and changing
conditions of supply and demand for
power, why any given facility identified
in a transmission plan may not
ultimately be constructed.
Consequently, our planning reforms do
not include an obligation to construct
each facility identified in the plan,
whether individually or through joint
ownership mechanisms. At the same
time, the Commission agrees that joint
ownership may be useful in certain
situations and encourages transmission
providers and customers alike to
consider the use of open seasons to
realize construction of upgrades
identified in the planning studies. If a
transmission provider declines to
construct an identified upgrade, we also
encourage customers and third parties
to consider, either individually or
jointly, development and ownership of
a project to the extent consistent with
applicable State law.
f. Specific Study Processes Beyond
Reliability and Congestion Reduction
595. In the NOPR, the Commission
sought comment on whether there
should be a specific study process to
identify opportunities to enhance the
grid for purposes beyond maintaining
reliability or reducing current
congestion. Such a study process could
allow interested entities, including State
resource agencies and others, to request
the transmission provider to model grid
upgrades needed to accommodate the
construction of new resources and
provide information needed to
proactively evaluate such resources. The
Commission expected that such studies
would not conflict with State
prerogatives, but rather would provide
states with better information to
evaluate all relevant resource options.
352 As the Commission stated in Order No. 679–
A, ‘‘[t]he Commission will look favorably on
incentive requests that include public power joint
ownership.’’ Order No. 679–A at P 102.
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Comments
596. Most transmission provider
commenters favor providing for study of
some grid enhancement beyond
reliability and congestion-related needs,
but believe the Final Rule should not
mandate a specific study process.
Various commenters argue that the
Commission should allow planning
participants to determine details such as
the scope, number, and cost
responsibility for the studies.353 MISO
states that it is working on these issues,
but enhancement beyond maintaining
reliability or reducing congestion is a
complicated subject best left to each
RTO or ISO to decide.
597. Some commenters are more
explicit or expansive in their
recommendations. CAISO recommends
that the Commission develop a policy to
encourage construction of transmission
lines necessary to connect renewable
resources,354 and Suez Energy NA
provides similar comments about new
remote generation. PJM believes the
planning process should look at future
congestion and building for resources
not yet announced. The New Jersey
Board believes that demand-side
management and other solutions, such
as distributed renewable generation,
also should be considered. WIRES and
ELCON believe all credible proposals
should be studied. TAPS asserts that
planning should study grid
enhancements needed for new potential
resources.355 These views are consistent
with the views of many of the
commenters that support additional
study processes.356 TDU Systems,
however, point out that planning for
reliability and economics should be
incorporated into the open and
inclusive planning process and,
therefore, a special study process should
not be needed.
598. Other commenters are opposed
to additional processes: South Carolina
E&G does not see a need for additional
studies; Southern believes additional
study processes would be overly
burdensome and would divert attention
away from the fundamentals of prudent
planning; and Bonneville notes that
market participants often make requests
353 E.g., EEI, MISO, NorthWestern, PSEG, and
Tacoma.
354 Related to this, California Commission asserts
that regional planning processes need to be closely
linked with the resource adequacy planning
processes and renewable energy portfolio standards
on the State level.
355 EEI replies in opposition to TAPS’ assertions
that planning should address transmission for
potential resources, arguing that such a requirement
would be cost prohibitive and would harm users.
356 E.g., APPA, Arkansas Commission, AWEA,
CREPC, Sacramento, and Seattle.
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Commission Determination
599. We believe that development of
a study process for identifying
opportunities for grid enhancement
beyond reliability and congestion
reduction has the potential to provide
useful information and would generally
benefit development of the transmission
grid. We therefore will include such
study processes within the scope of
Principle No. 8. In the NOPR, that
principle concerned only congestion
studies, but, as modified above, it now
includes studies regarding upgrades that
could integrate new generation
resources. We note that various
commenters argued for the
consideration of demand resources in
development of enhancements to the
transmission grid.357 As we explain
above, consideration of such resources
falls within Principle No. 8, as modified
by the Final Rule.
g. Level of Detail in the OATT
600. In the NOPR, the Commission
sought comment on the level of detail to
be required to be in the transmission
provider’s OATT regarding its planning
process.
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Comments
601. Several commenters argued that
the details of the planning process
should be included in the transmission
providers’ OATTs.358 Seattle noted that
the OATT should balance the need for
detailed planning requirements with the
need for regional processes to evolve.
Commission Determination
602. The Commission agrees that the
transmission planning attachment to a
transmission provider’s OATT must
include sufficient detail to enable
transmission customers to understand
the transmission provider’s planning
process. This new attachment must
therefore include:
(a) The process for consulting with
customers and neighboring transmission
providers;
(b) The notice procedures and
anticipated frequency of meetings or
planning-related communications;
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1. General
603. As the Commission explained in
Order No. 888, the pro forma OATT was
designed to include primarily non-rate
terms and conditions of open access
non-discriminatory transmission
service. Transmission providers first
were required to adopt the non-rate
terms and conditions of the pro forma
OATT and then, in a subsequent filing
under FPA section 205, to propose
corresponding rates for service provided
under their OATTs. Consistent with the
focus of Order No. 888 on the non-rate
terms and conditions of open access, the
Commission did not propose broad
reform of transmission pricing policy
through the NOPR. Rather, the
Commission identified in the NOPR
several discrete pricing rules that it
considered part and parcel of OATT
service that merit reform, which we
discuss in more detail later in this
section. The Commission also
specifically noted in the NOPR that the
purpose of this rulemaking is to
strengthen the pro forma OATT to
remedy undue discrimination and not to
create new market structures.
604. Despite the clear scope of this
rulemaking, several commenters
contend that broader ratemaking
reforms should be implemented in order
to remove obstacles to achieving
competitive markets. Various
commenters assert that rate pancaking
must be eliminated in this reform,
noting that the Commission has
recognized in the past that pancaked
rates inhibit the development of
competitive markets.359 Arkansas
Municipal and TDU Systems contend
that pancaked rates are particularly
burdensome for customers with loads
and resources on multiple transmission
providers systems and those that sit
essentially at or on the boundaries. TDU
Systems argue that the failure to
eliminate pancaked rates has caused
many of the TDU Systems to spend
many millions of dollars to build
transmission from generation to
interconnect with multiple control areas
in order to avoid paying multiple
wheeling charges.
605. Some of these commenters also
advocate that the Commission should
move towards joint rates.360 Arkansas
Municipal Power argues that moving
toward joint rates outside an RTO will
not only eliminate competitive barriers
outside RTOs, but would reduce the
disincentive to formation of new and
expanded RTOs. TAPS complains that
the NOPR requires regional planning,
but has no provision requiring
transmission providers to build facilities
to support regional needs, arguing that
joint rates would ease this problem.
TDU Systems argue, however, that any
joint rate methodology should not shift
costs to other network customers,
especially where surcharges are sought
that might open the door to potential
over-recovery by transmission providers
as argued in the PJM/MISO proceedings.
Old Dominion also contends that the
Commission should add a requirement
in the pro forma OATT that regional
transmission costs be recovered through
a single regional transmission rate of a
rolled-in nature. Relative to cost
recovery, Old Dominion believes that
rolled-in zonal rates work for local
facilities within a single transmission
owner footprint, but regional rolled-in
rates would be necessary for larger
footprints.
606. Old Dominion also contends that
the lack of periodic review by the
Commission of stated transmission rates
sends a strong economic signal to
transmission owners to not invest in
new transmission. Old Dominion argues
that the Commission should require
periodic rate reviews at least every five
years or implement formula rates which
would remove economic incentives for
failing to build transmission.
607. EEI argues that the Commission
should not address in this proceeding
TDU Systems’ proposal to require
transmission providers to eliminate
pancaked transmission rates in nonRTO regions because it involves
complex issues that are not easily
resolved. EEI contends that transmission
providers should not be required to
eliminate multiple transmission rates
across multiple systems simply to allow
TDU members to avoid the economic
consequences of their decisions to
359 E.g., Arkansas Municipal, AWEA, FMPA, and
TDU Systems.
for expensive studies without following
through on them. Santee Cooper
cautions the Commission against giving
license to those who would attempt to
hijack the regional planning process in
order to advance a generation-related
agenda, and notes that the
Commission’s authority does not extend
to generation resource adequacy.
357 E.g., New Jersey Board, Ohio Power Siting
Board, and WIRES.
358 E.g., APPA, NRECA, Old Dominion, and
Seattle. APPA also suggests OASIS posting.
(c) A written description of the
methodology, criteria, and processes
used to develop transmission plans;
(d) The method of disclosure of
transmission plans and related studies
and the criteria, assumptions and data
underlying those plans and studies;
(e) The obligations of and methods for
customers to submit data to the
transmission provider;
(f) The dispute resolution process;
(g) The transmission provider’s study
procedures for economic upgrades to
address congestion or the integration of
new resources; and
(h) the relevant cost allocation
procedures or principles.
12341
360 E.g., Arkansas Municipal, TAPS, and TDU
Systems.
C. Transmission Pricing
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purchase energy from off-system
resources.
608. Other commenters ask the
Commission to institute much broader
market reforms in this rulemaking,
arguing that the Commission will not be
able to achieve its objectives of
remedying undue discrimination and
developing competitive wholesale
markets without a fundamental change
in market structures. Several
commenters advocate changing the
market structure in non-RTO markets to
allow transmission customers to access
the transmission provider’s dispatch
and redispatch options.361 Some
commenters 362 go further to assert that
the Commission require the use of
locational marginal pricing (LMP) as a
part of OATT reform. Other
commenters 363 assert that the
Commission would not need to adopt a
full RTO market design to achieve its
more limited objectives, but contend
that eliminating the fundamental
inconsistency between the OATT rules
and actual operation of the grid would
remove a major obstacle to other
reforms. Several commenters 364
contend that requiring use of a security
constrained economic dispatch is a
needed part of this reform.
609. Chandley-Hogan contend that the
key element to ensuring transmission
services are provided on a just,
reasonable and not unduly
discriminatory basis is to provide open
access to the security constrained
economic dispatch and the associated
imbalance pricing that arises from that
dispatch. Chandley-Hogan state that
using a security constrained economic
dispatch would also substantially
reduce the problems inherent in the pro
forma OATT’s reliance on contract
paths and ATC for transmission service
scheduling.
610. Chandley-Hogan contend that a
viable path to Order No. 888 reform is
to start from the premise that open
access to the dispatch (and redispatch)
and marginal cost pricing for
imbalances and redispatch to
accommodate transmission are keys to
getting open, non-discriminatory access
to transmission. Chandley-Hogan argue
that dispatch is the essential
transmission service and providing
open access to this dispatch is a path to
achieving open, non-discriminatory
access to transmission. Chandley-Hogan
contend that a third party cannot
effectively access the grid without
361 E.g.,
Chandley-Hogan, Constellation, and PJM.
Morgan Stanley and Steel Manufacturers
Associations.
363 E.g., Chandley-Hogan and PJM.
364 E.g., EPSA and Chandley-Hogan.
362 E.g.,
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accessing and closely interacting with
the system operator’s dispatch,
including determining if transmission
service is available, acquiring redispatch
service to allow its schedule to proceed
without curtailment, and settling
imbalances from scheduled levels.
Williams agrees with Chandley-Hogan
that a system allowing non-RTO utilities
to deny and curtail service requests
whenever there is little ATC left and
without offering redispatch to a third
party is completely flawed. Williams
argues that these same requests would
be accommodated in an RTO through
redispatch as long as the RTO has
sufficient offers to arrange a security
constrained economic dispatch.
611. EPSA argues on reply that an allinclusive, ‘‘asset-blind’’ administration
of open dispatch is needed to fully
eliminate undue discrimination. EPSA
states that security constrained dispatch
will provide reliable operation and
efficient utilization of the transmission
grid by promoting the use of newer,
cleaner and less expensive power
plants. EPSA urges that these issues
should be explored further here or in
another policy proceeding. Project for
Sustainable FERC Energy Policy asserts
that there is no assurance of nondiscriminatory access to transmission
services and competitive wholesale
markets unless load and potential
competitors of the control area operators
are treated comparably during dispatch.
Project for Sustainable FERC Energy
Policy supports additional provisions to
the pro forma OATT requiring
transparency and fairness in system
dispatch and redispatch such as either
an ‘‘open dispatch’’ requirement or a
rule-based framework with standards of
conduct and OASIS disclosure, as well
as reporting and auditing requirement to
eliminate anticompetitive incentives.
Project for Sustainable FERC Energy
Policy argues that sufficient data to
establish marginal system costs and
permit comparisons with the prices/
costs of neighboring systems should be
disclosed on OASIS.
612. PJM proposes open dispatch
consisting of control of the dispatch
function by a disinterested entity and
the institution of a spot or balancing
market to allow for the formation of
real-time prices. Project for Sustainable
FERC Energy Policy encourages the
further separation of the system
operator’s dispatch functions from its
merchant functions, to include specific
dispatch transparency and
comparability mandates as per PJM’s
and Transparent Dispatch Advocates’
request. Project for Sustainable FERC
Energy Policy supports comparable
dispatch services through an
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independent entity. In its reply
comments, Williams supports the rules
based dispatch service proposed by PJM
and states that it will reduce the
opportunity for transmission providers
to levy unjust and unreasonable
redispatch rates.
613. PJM also contends that non-RTO/
ISO systems have negative impacts on
RTO systems because of the respective
treatment of import transactions by nonRTOs/ISOs and RTOs/ISOs and the
incidence of loop flows in market
environments. PJM argues that entities
scheduling flows through PJM that
actually loop onto other systems
nevertheless benefit financially because
they collect the difference between the
relatively high price at the interface
where the energy is scheduled to enter
the PJM footprint and the lower price at
the interface where the energy is
scheduled to leave the PJM footprint.
When energy does not flow as
scheduled, PJM states that the otherwise
expected, beneficial impact on the
transmission constraints are not
realized, resulting in price differentials
between the affected interfaces. As a
result, PJM contends that such
scheduled transactions only contribute
to the FTR revenue adequacy issues PJM
has experienced over the last 12
months.
614. PJM asserts that it is unduly
preferential for a non-RTO/ISO utility to
take advantage of the benefits of the
organized markets of a bordering RTO/
ISO without any obligation to bear any
of the costs of administering those
markets. PJM contends that it is unduly
discriminatory and an impediment to
the development of competitive markets
to permit a non-RTO/ISO utility
adjacent to an RTO/ISO’s organized,
transparent markets to accept the
benefits of those markets and the
regional transmission planning process
that sustains them, while the same
utility relies on non-market-based
congestion management and limits the
access of its competitors, including
those who are members of the relevant
RTO/ISO, to its dispatch sequence and
wholesale prices within its service area.
PJM asks the Commission to declare that
it would not be unduly discriminatory
for an RTO/ISO to include in its tariff
a provision that makes an external
system operator’s access to those
markets contingent on the external
operator providing reciprocal access to
its dispatch and planning functions for
RTO/ISO members, as well as access to
the external system’s real-time marginal
system cost information.
615. Transparent Dispatch Advocates
propose on reply that the Commission
require the industry to develop inter-
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control area coordination agreements to
provide for reciprocal redispatch to
alleviate constraints at specified border
flowgates. Transparent Dispatch
Advocates argue that redispatch over a
larger area provides transmission
providers more options to extract the
full efficiency of their systems by
allowing import/export transactions and
intra-control area flows to continue that
would otherwise be curtailed by
providing redispatch of generation
across a border at a lower cost than
would result had the transaction been
curtailed. Transparent Dispatch
Advocates further propose that the
Commission establish principles in the
Final Rule to guide the development of
these coordination agreements and
require filing of the agreements within
12 months of the issuance of the Final
Rule. Transparent Dispatch Advocates
suggest that technical conferences may
need to be scheduled to address any
utility specific issues that arise.
616. Morgan Stanley and Steel
Manufacturers Association contend that
every control area should be moving
toward LMP and that facing an
imbalance cost measured by full
replacement value of redispatch
measured under LMP is the correct
incentive to follow a schedule. Entegra
similarly argues that customers and
State regulators would benefit from
more transparency regarding congestion
on the transmission system and that the
most efficient way to provide this
transparency is to require transmission
providers to apply LMP models to their
systems and to post the resulting
modeled LMPs.
617. Several commenters object to the
proposal for a mandatory all-inclusive
redispatch using bid-based pricing.365
These commenters generally argue that
such a proposal could not lawfully be
adopted in the Final Rule because it
dramatically departs from the scope of
the NOPR. They also argue that the
proposal is bad policy because there is
no record showing that consumers
would benefit from the costly and
disruptive implementation required for
the proposal and that adoption of the
proposal would create controversy given
that Congress and the Commission have
already rejected an LMP-based model of
industry restructuring. Sacramento adds
that given the record of transmission
investment in RTOs, open redispatch
might not meet the transmission
expansion goals of the NOPR.
618. Southern argues on reply that
there is no legal basis for claims that a
lack of open dispatch results in undue
discrimination. Southern states that the
365 E.g.,
LPPC, Entergy, and Sacramento.
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entities at issue are not similarly
situated and that open dispatch
concerns resource procurement, an area
beyond the scope of the Commission’s
jurisdiction. Southern further argues
that the open dispatch remedy proposed
by PJM and others would require radical
restructuring and market reforms that
are unfounded, lack a legal basis and
would result in political discord.
Southern states that open dispatch
would violate FPA section 217 by
threatening the ability of LSEs to
maintain access to transmission rights to
serve native load. In its reply comments,
Entergy states that the open dispatch
proposal should be rejected because it is
unnecessary to ensure open access
transmission service, is contrary to the
Congressional intent in passing EPAct
2005, exceeds the scope of the
Commission’s jurisdiction by overriding
State jurisdiction over sales to retail
customers, and would result in
opposition that will delay other reforms
and distract the Commission with
divisive litigation.
619. Sacramento states that the
proposals for mandatory redispatch, the
control of the dispatch by a
disinterested entity, and the institution
of a spot or balancing market to allow
for the formation of real-time prices
would undermine customers’ objectives
to receive uninterrupted transmission
service at a predictable price and ignore
transmission system operational
limitations. Sacramento states that the
value of mandatory redispatch in the
Western Grid is limited because
constraints often overlap and change
from thermal to voltage to stability
constraints at differing load levels and
redispatching large amounts of
generation to relieve constraints because
of the distance between loads and
generation cannot be achieved in the
timeframes required to maintain
reliability. Sacramento is concerned that
PJM’s proposal would cause
appropriation of generation built to
serve a transmission provider’s native
load in order to effectuate third-party
transmission transactions, strain the
transmission provider’s grid, and cause
additional curtailment of native load
and firm transactions when a force
majeure event occurs.
620. Entergy cites the approval of the
ICT proposal as ample evidence that the
incremental approach proposed in the
NOPR is a better means of improving
clarity, transparency and improvements
in dispatch efficiency than the
Transparent Dispatch Advocates and
PJM seek to mandate. Entergy states that
the arguments posed by PJM and
Chandley-Hogan do not target
remedying discrimination or ensuring
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12343
comparability, but rather focus on what
they believe are mechanisms for more
efficient use of the grid. Overall, Entergy
does not support any changes to the
basic nature of the services available
under the pro forma OATT or the
development of real-time markets to
ensure comparable access.
621. In its reply comments,
Sacramento disagrees with PJM’s claims
that TLRs are a discriminatory
substitute for real-time redispatch and
PJM’s proposal to eliminate such use of
TLRs in favor of an expanded redispatch
obligation. Sacramento argues that firm
customers under the pro forma OATT
do not expect TLRs, while those in Day
2 RTOs expect that generation will be
redispatched. Sacramento adds that
TLRs affect all loads, but that the nature
of firm physical rights service is that it
will not be interrupted except in very
narrow defined circumstances.
622. Southern argues that customers
selling between RTO and non-RTO
systems are treated equally since part of
the transaction is under an LMP
treatment and the other part is under
OATT treatment. In response to PJM’s
allegations that loop flows are unduly
discriminatory to its customers,
Southern states that loop flows are
unavoidable consequences of integrating
electrical systems and that PJM itself
imposes loop flows on non-RTO
systems, the effects of which are not
compensated by PJM. If PJM believes
that entities are free-riding on its system
or manipulating its system, Southern
argues that PJM could seek to increase
market participation charges or file a
complaint with the Commission.
Sacramento agrees that this rulemaking
is the wrong forum for resolving seams
issues given the stated scope of the
NOPR. Sacramento adds that border
utilities do not ‘‘free ride’’ on RTO
markets because these markets impose
significant costs on border entities.
Sacramento also disagrees that open
redispatch would resolve loop flow
problems and suggests other mechanism
for addressing loop flow. Finally,
Sacramento states that TLRs are an
Eastern Interconnection process that,
although rare, occur in RTOs and nonRTO areas.
Commission Determination
623. As the Commission explained in
the NOPR, we do not intend to
undertake a comprehensive overhaul of
our transmission pricing policies in this
rulemaking. Instead, the Commission
proposed a number of specific reforms
to discrete provisions in the pro forma
OATT and a clarification to our ‘‘higher
of’’ policy for pricing of transmission
system expansions. Given the limited
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scope of this proceeding, we do not
believe it would be appropriate to adopt
the broader ratemaking proposals
suggested by commenters. Issues of rate
pancaking, including joint rates,
regional rolled-in rates and rate reviews
are beyond the scope of this proceeding.
624. Similarly, the Commission made
clear in the NOPR that the purpose of
the proposed rule is to strengthen the
pro forma OATT to remedy undue
discrimination and not to impose any
particular market structure on the
industry. The Commission’s focus in
this proceeding was and remains the
development of competitive wholesale
markets through the reduction of
barriers to entry created through the
control of transmission assets. We
continue to believe that the appropriate
focus of this rulemaking is to strengthen
competitive wholesale markets by
adopting reforms to address remaining
areas of undue discrimination and
issues of comparability rather than
mandating a fundamental change in the
market structure.
625. We therefore reject requests to
institute systems that require the realtime use of regional security constrained
economic dispatch and LMP for
granting real-time transmission service
and for the settlement of imbalances or
to otherwise require transmission
providers to use LMP-based modeling.
We believe that LMP market designs can
provide significant benefits to customers
through more efficient use of the grid,
but do not believe that such market
designs are the only way to remedy
undue discrimination or achieve
comparability. We continue to support
regional flexibility in market
development, provided that the market
design implemented by the transmission
providers provides other transmission
customers with comparable service to
that which the transmission providers
provide to their own native loads and
affiliates.
626. We also reject arguments
regarding seams issues creating an
undue discrimination between market
and non-market areas that must be
resolved in this proceeding. We note
that there are currently processes
underway to address seams issues both
in the Eastern and Western
Interconnections.366 We believe that
such seams issues are beyond the scope
of this rule and are better addressed on
a case-by-case basis or, as appropriate,
in the proceeding on RTO Border Utility
Issues.367
2. Energy and Generation Imbalances
627. In Order No. 888, the
Commission concluded that six
ancillary services must be included in
an OATT.368 One of those ancillary
services is energy imbalance service
under Schedule 4 of the pro forma
OATT.369 Energy imbalance service is
provided when the transmission
provider makes up for any difference
that occurs over a single hour between
the scheduled and the actual delivery of
energy to a load located within its
control area.370 The Commission
recognized, in general, that the amount
of energy taken by load in an hour is
variable and not subject to the control
of either a wholesale seller or a
wholesale requirements buyer.371
628. The Commission found that
energy imbalance service should have
an energy deviation band appropriate
for load variations and a price for
exceeding the deviation band that is
appropriate for excessive load
variations.372 The Commission
established an hourly deviation band of
+/¥1.5 percent (with a minimum of 2
MW) for energy imbalance. The
Commission explained that this
deviation band promotes good
scheduling practices by transmission
customers, which ensures that the
implementation of one scheduled
transaction does not overly burden
another.373
629. With respect to compensation
associated with the hourly energy
deviation band, the Commission
explained that, for energy imbalances
within the deviation band, the
transmission customer may make up the
difference within 30 days (or other
reasonable period generally accepted in
the region) by adjusting its energy
deliveries to eliminate the imbalance
(i.e., return energy in kind within 30
days).374 In addition, the Commission
explained that the transmission
customer must compensate the
transmission provider for each
imbalance that exceeds the hourly
deviation band and for accumulated
minor imbalances that are not made-up
within 30 days.375 With respect to the
367 Id.
368 Order
No. 888 at 31,703.
369 Id.
370 See
Id. at 31,960.
No. 888–A at 30,230.
371 Order
372 Id.
373 Id.
366 See,
e.g., RTO Border Utility Issues, Notice of
Technical Conference on Seams Issues for RTOs
and ISOs in the Eastern Interconnections, (Docket
No. AD06–9–000) (issued Jan. 25, 2007).
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at 30,232.
at 30,229.
375 Id. The Commission further stated that the pro
forma OATT permits schedule changes up to
twenty minutes before the hour at no charge, and
374 Id.
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price of energy imbalance service, the
Commission explained that it
intentionally did not provide detailed
pricing requirements.376 Instead, the
Commission required transmission
providers to propose rates for energy
imbalance service.377
630. Although transmission providers
have different energy imbalance
charges, they typically require
customers to correct energy imbalances
within the deviation band through
return in kind or a financial settlement
that requires payment for
underdeliveries of energy equal to 100
percent of the transmission provider’s
system incremental cost for the hour the
deviation occurred. For energy
overdeliveries, the transmission
customer would receive a payment
equal to 100 percent of the transmission
provider’s decremental cost for the hour
the deviation occurred.378 Outside the
deviation band, transmission providers
either charge the transmission customer
(1) A percentage of the utility’s system
cost, such as 110 percent of incremental
costs for underscheduling or 90 percent
of decremental costs for overscheduling
or (2) the greater of a percentage of
system costs or a fixed charge, such as
$100 per MWh.379
631. While the Commission found in
Order No. 888 that energy imbalance
was an ancillary service, it also
recognized that another imbalance may
arise for differences between energy
scheduled for delivery from a generator
and the amount of energy actually
generated in an hour,380 commonly
called generator imbalance. The
Commission concluded, however, that a
generator should be able to deliver its
scheduled hourly energy with precision
and expressed concern that allowing a
generator to deviate from its schedule by
1.5 percent without penalty, so long as
that it would allow the transmission provider and
the customer to negotiate and file another deviation
band more flexible to the customer, if the same
deviation band is made available on a not unduly
discriminatory basis. Id. at 30,232–33.
376 Id. at 30,234
377 Id.
378 See, e.g., Arizona Public Service Co., FERC
Electric Tariff, Twelfth Revised Volume No. 2,
Schedule 4 (Energy Imbalance Charge), accepted in
Arizona Public Service Co., Docket No. ER04–442–
003 (Sep. 30, 2004) (unpublished letter order);
Public Service Company of New Mexico, FERC
Electric Tariff, Second Revised Volume No. 4.,
Schedule 4 (Energy Imbalance Charge), accepted in
Public Service Co. of New Mexico, Docket No.
ER04–416–002 (Sep. 30, 2004) (unpublished letter
order).
379 See Idaho Power Co., 102 FERC ¶ 61,351
(2003); Duke Electric Transmission FERC Electric
Tariff, Third Revised Volume 4, Original Sheet No.
120 accepted in Duke Energy Corp., Docket No.
ER04–812–001 (Jul. 2, 2004) (unpublished letter
order).
380 Order No. 888–A at 30,230.
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it returned the energy in kind at another
time, would discourage good generator
operating practices.381 The Commission
stated that a generator’s interconnection
agreement with its transmission
provider or control area operator should
specify the requirements for the
generator to meet its schedule and any
consequence for persistent failure to
meet its schedule.382
632. The Commission subsequently
accepted in a number of cases
modifications to a transmission
provider’s OATT to include generator
imbalance provisions.383 Moreover, in
Order No. 2003–B, the Commission
permitted the transmission provider to
include a provision for generator
balancing service arrangements in
individual interconnection
agreements.384 Further, in a NOPR
concerning generator imbalance
provisions for intermittent resources,
the Commission proposed to establish a
standardized schedule under the pro
forma OATT to address generator
imbalances created by intermittent
resources and to clarify the application
of the current energy imbalance
provision of the pro forma OATT.385 In
particular, the Commission proposed
that generator imbalance provisions for
intermittent resources would reflect a
deviation band of +/¥10 percent (with
a minimum of 2 MW) and allow net
hourly intermittent generator
imbalances within the deviation band to
be settled at the system incremental cost
at the time of the imbalance.386 The
Commission also reiterated its policy
that a transmission provider may only
381 Id.
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382 Id.
383 See, e.g., Niagara Mohawk Power Corp., 86
FERC ¶ 61,009, order on reh’g, 87 FERC ¶ 61,148
(1999) (Niagara Mohawk); PacifiCorp, 95 FERC
¶ 61,145, order on reh’g and clarification, 95 FERC
¶ 61,467 (2001); Alliant Energy Corporate Services,
Inc., 93 FERC ¶ 61,340 (2000); Wolverine Power
Supply Coop., 93 FERC ¶ 61,330 (2000);
Commonwealth Edison Co., 93 FERC ¶ 61,021
(2000); FirstEnergy Operating Cos., 93 FERC
¶ 61,200 (2000), order denying reh’g & granting
clarification, 94 FERC ¶ 61,184 (2001); Tampa
Electric Co., 90 FERC ¶ 61,330 (2000), reh’g denied,
95 FERC ¶ 61,101 (2001); Florida Power Corp., 89
FERC ¶ 61,263 (1999); Consumers Energy Co., 87
FERC ¶ 61,170 (1999) (Consumers).
384 Order No. 2003–B at P 74–75.
385 Imbalance Provisions for Intermittent
Resources; Assessing the State of Wind Energy in
Wholesale Electricity Markets, Notice of Proposed
Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC
Stats. & Regs. ¶ 32,581 at P 9 (2005) (Imbalance
Provisions Proceeding).
386 The Commission defined incremental cost as
‘‘the transmission provider’s actual average hourly
cost of the last 10 MW dispatched to supply the
transmission provider’s native load, based on the
replacement cost of fuel, unit heat rates, start-up
costs, incremental operation and maintenance costs,
and purchased and interchange power costs and
taxes.’’ Id. at P 9 n.17 (citing Consumers, 87 FERC
¶ 61,170 at 61,179 (1999)).
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charge the transmission customer for
either hourly generator imbalances or
hourly energy imbalances for the same
imbalance, but not both.387
633. A variety of different deviation
bands and pricing methods are on file
for generator imbalances. Rates for
generator imbalance underdeliveries
range from the greater of $100/MWh or
110 percent of system incremental cost
to the greater of $150/MWh or 200
percent of the incremental cost.388
Generator imbalance rates for
overdeliveries range from 90 percent 389
of system decremental cost to 50
percent 390 of the decremental cost.
a. Tiered Approach to Imbalance
Penalties in the OATT
NOPR Proposal
634. In the NOPR, the Commission
noted that the existing energy imbalance
charges described in Order No. 2003 are
the subject of significant concern and
confusion in the industry. The
Commission expressed concern about
the variety of different methodologies
used for determining imbalance charges
and whether the level of the charges
provides the proper incentive to keep
schedules accurate without being
excessive. The Commission therefore
proposed to modify the current pro
forma OATT Schedule 4 treatment of
energy imbalances and to adopt a
separate pro forma OATT schedule for
the treatment of generator imbalances.
635. The Commission proposed to
create new energy and generator
imbalance schedules based on the
following three principles: (1) The
charges must be based on incremental
cost or some multiple thereof; (2) the
charges must provide an incentive for
accurate scheduling, such as by
increasing the percentage of the adder
above (and below) incremental cost as
the deviations become larger; and (3) the
387 Under existing Commission policy, a
transmission provider may only charge a
transmission customer for the penalty percent adder
to the incremental cost for either hourly generator
imbalances or hourly energy imbalances for the
same imbalance. For example, if a transmission
customer has a 100 MWh point-to-point schedule
in a control area, but produces 105 MWh and
consumes 105 MWh, the transmission provider may
charge the transmission customer 110% of its
incremental cost for the 5 MWh of energy
imbalance, but then must pay the transmission
customer its incremental cost for the 5 MWh
generator imbalance.
388 See Duke Energy Corp., Docket No. ER05–855–
000 (Dec. 20, 2005) (unpublished letter order)
(accepting Duke Electric Transmission’s Large
Generator Interconnection Agreement with Power
Ventures Group, LLC (Duke Delegated Letter
Order)).
389 See Entergy Services, Inc., 90 FERC ¶ 61,272
(2000) (concerning various generator imbalance
agreements).
390 See Duke Delegated Letter Order.
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provisions must account for the special
circumstances presented by intermittent
generators and their limited ability to
precisely forecast or control generation
levels, such as waiving the more
punitive adders associated with higher
deviations.
636. The Commission noted that
Bonneville has adopted an energy
imbalance pricing approach based on a
three-tiered deviation band that appears
workable for both energy imbalance
service and generation imbalance
service. Under this approach,
imbalances of less than or equal to 1.5
percent of the scheduled energy (or two
megawatts, whichever is larger) would
be netted on a monthly basis and settled
financially at 100 percent of incremental
or decremental cost at the end of each
month. Imbalances between 1.5 and 7.5
percent of the scheduled amounts (or
two to ten megawatts, whichever is
larger) would be settled financially at 90
percent of the transmission provider’s
system decremental cost for
overscheduling imbalances that require
the transmission provider to decrease
generation or 110 percent of the
incremental cost for underscheduling
imbalances that require increased
generation in the control area.
Imbalances greater than 7.5 percent of
the scheduled amounts (or 10
megawatts, whichever is larger) would
be settled at 75 percent of the system
decremental cost for overscheduling
imbalances or 125 percent of the
incremental cost for underscheduling
imbalances. Intermittent resources are
exempt from the third-tier deviation
band and pay the second-tier deviation
band charges for all deviations greater
than the larger of 1.5 percent or two
megawatts.
637. The Commission sought
comment regarding whether this tiered
approach should be adopted for
inclusion in the pro forma OATT for
energy and generator imbalances. The
Commission specifically asked whether
this approach provides sufficient
incentives to ensure that transmission
systems can be operated in a reliable
manner and ensure that customers are
treated in a just and reasonable manner.
Comments
638. A number of entities generally
support a tiered approach to imbalance
penalties that progressively increases
the penalties for imbalances, as
implemented by Bonneville.391 These
391 E.g., Ameren, Northwest IOUs, Progress
Energy, Suez Energy NA, Public Power Council,
Sacramento, South Carolina E&G, Pinnacle,
Allegheny, TDU Systems, Constellation, Imperial,
and Morgan Stanley.
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commenters generally state that a
graduated bandwidth approach
recognizes the link between escalating
deviations and potential reliability
impacts on the system. Other entities,
however, take issue with aspects of the
Commission’s proposal or propose a
different approach to resolving
imbalances. For example, Entegra
submits that the Commission should
require transmission providers to
establish, or permit market participants
to establish, markets or pools for the
netting and settlement of imbalances.
Steel Manufacturers Association argues
for the Commission to require real-time
balancing markets.
639. Among those supporting the
Commission’s proposal, Ameren asserts
that the tiered approach properly allows
for higher penalties for imbalances that
have a greater impact on the system and
thus have a greater potential to affect
reliability. NorthWestern is not opposed
to the generation imbalance provisions
applying to all generators, arguing that
imbalance charges must be based upon
incremental cost and must provide an
incentive for accurate scheduling.
Morgan Stanley contends that basing the
imbalance charge on incremental cost
should be a bedrock principle for
developing methods to financially settle
imbalances.
640. Progress Energy, Sacramento,
and Entergy encourage the Commission
to allow each transmission provider to
have the flexibility to craft penalty
provisions that provide the right
incentives to encourage their
transmission customers to act
responsibly. Grant similarly contends
that the transmission provider must be
able to decide what to charge for
imbalance services and must consider
the incentives for resource development
and the potential for cross-subsidies
paid by other customers associated with
such pricing. Grant argues that
transmission providers should have an
ability to ‘‘opt out’’ if they can
demonstrate an inability to provide the
service without creating an undue
burden on other ratepayers.
641. Constellation, while supporting
the Commission’s proposal, asks that
transmission providers be required to
utilize a security-constrained economic
dispatch to procure and settle
imbalances at least cost, which would
ensure that least cost is determined on
the most efficient basis. Constellation
contends that imbalance charges should
be based on the transmission provider’s
actual cost of meeting a positive
imbalance or liquidating a negative
imbalance, which costs can include
required ancillary services and
redispatch costs. Morgan Stanley states
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that facing an imbalance cost measured
by full replacement value of redispatch
measured under LMP would be an
appropriate incentive. Morgan Stanley
contends that the pro forma OATT
should specify using opportunity cost
principles to charge for imbalance
solutions in those areas without LMP
and come as close to mimicking the
result under LMP as possible. In reply
comments, Mark Lively suggests the
Commission make the price for
imbalances a function of the size of Area
Control Error. Public Power Council
recommends that transmission
providers not assess penalties against
loads or resources when their deviations
from the schedule help the system in a
given delivery hour. TDU Systems argue
that inadvertent scheduling errors that
do not threaten system integrity or
reliability should not be penalized
through charges for imbalances that
exceed incremental cost in the upper
tiers of imbalance bandwidths.
642. Although FirstEnergy states that
the Bonneville approach for generator
imbalances is appropriate, it argues that
the current pro forma OATT
methodology for calculating and
assessing energy imbalances should be
retained. FirstEnergy argues that it is
more appropriate and fair to apply a
graduated penalty structure to
generation imbalances since greater
deviations usually occur from
generation. Ameren, however, believes
that generators are generally better able
to control their imbalances than
transmission customers who take energy
off of the system and that the use of a
narrower deviation band may be
appropriate for generator imbalances.
Nonetheless, Ameren states that it does
not oppose the Commission’s proposal
to use the same deviation bandwidths
for both energy imbalances and
generator imbalances.
643. Ameren contends that
developing standardized provisions for
generator imbalances in the OATT
would eliminate the plethora of
penalties that now exist. Ameren asserts
that moving to a tariff approach would
increase transparency and would help
address the situation where such
provisions may appear either in the
relevant OATT or in specific
interconnection agreements (at least for
interconnection agreements entered into
as of the date of the revised tariff
provisions). Progress Energy and South
Carolina E&G support separate tariff (or
Generator Interconnection Agreement)
provisions for these services, suggesting
that generator and energy imbalance
provisions could be tailored for
generators and LSEs. NorthWestern
states that it has long been an advocate
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of the inclusion of a generation
imbalance OATT mechanism. TDU
Systems contend that the Commission
should require that the specific
bandwidths and the basis for the
charges be spelled out in detail in the
revisions to the pro forma OATT and in
each transmission provider’s tariff.
Allegheny argues that changing Energy
Imbalance Service from Schedule 4 to
Schedule 4a, adding a new Schedule 4b
for Generator Imbalance Service, and
eliminating proposed Schedule 9 would
call attention to the fact that a
transmission provider may only charge
a transmission customer either an
hourly generator imbalance charge or an
hourly energy imbalance charge, but not
both for the same imbalance.
644. Other entities contend that the
Commission’s imbalance proposal will
not do enough to protect reliability and
prevent entities from deviating from
their schedules. Entergy states that the
Commission should recognize that a
system with significant hydro resources,
such as the Bonneville system, faces
different challenges in matching
generation and load than a system with
predominantly thermal generation.
Unlike the fast ramping capability of
hydro units, Entergy asserts that thermal
units have a more limited ability to
adjust and compensate for imbalances.
Entergy adds that the Bonneville model
may not provide sufficient incentives in
those areas with large amounts of
independent generation. In reply
comments, some APPA members noted
that wind variability may pose
significant operational concerns that
could increase regulating reserve
requirements, particularly on smaller
transmission systems.
645. Steel Manufacturers Association
asks the Commission to delete any
further reference to charges based on
some multiple of incremental costs,
which applies to scheduling incentives,
not cost recovery. It believes that
charges based on multiples of
incremental costs are not necessary and
do not produce rates that are just and
reasonable. Steel Manufacturers
Association asserts that balancing
mechanisms based on real time marketclearing prices provide full
compensation and adequate scheduling
incentives in the organized markets and
there is no reason to apply a deadband/
penalty mechanism for individual
OATT providers unless there is a
demonstrated need, i.e., a showing that
excessive gaming by LSEs or generators
has been a problem.
646. Steel Manufacturers Association
also contends that the current imbalance
mechanism is a losing proposition for
loads that cannot control energy
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consumption to match an hourly
schedule of energy deliveries, with
transmission providers receiving
windfall revenues. It argues that the
mechanism is unfair to smaller
transmission systems that are not
control areas (and therefore may not
settle all of their imbalances through
return-in-kind energy) and certain retail
customers that take unbundled retail
transmission service. Steel
Manufacturers Association asks the
Commission to institute a larger
bandwidth of, at minimum, 10 percent
for small wholesale customers and
discrete retail loads. It contends that
large utilities and wholesale
transmission customers that acquire
power for many discretely operated
loads with varying load stages and load
factors and averaging those loads creates
an overall predictability to load curves
that permits the practical use of a 1.5
percent bandwidth for large utilities and
wholesale customers.
647. Utah Municipals assert that the
Commission is wrong to believe that
imbalances tend to result from
carelessness or intentional conduct
rather than unavoidable uncertainties
and error. Utah Municipals contend
that, while technology that permits
perfectly accurate scheduling (i.e.,
namely the AGC equipment used by
control area operators) is theoretically
available, it is prohibitively expensive
for many transmission customers and
unavailable to those who do not own
generation. Utah Municipals argue that
financial incentives for accurate
scheduling do not alter scheduling
behavior or actual imbalances, but only
result in a potential windfall for the
transmission provider and a potentially
significant competitive advantage for
the transmission provider’s market
function, which (because of the AGC
equipment that all transmission
customers pay for through rates) will
not be subject to the charges. Utah
Municipals suggest that the Commission
limit the imbalance charges for
unintentional deviations by applying
the third deviation band only to
intentional imbalances.
648. Imperial argues that the
Bonneville approach would not provide
appropriate incentives for small
geothermal generating units on its
system to control their scheduled
output, especially if imbalances are
recorded on an hourly basis rather than
on a cumulative basis over the course of
a month. Under the Bonneville
approach, Imperial asserts that it would
have to pay its generators 100 percent of
its incremental cost for overgeneration
because such imbalances are usually
less than 2 MW in any given hour. It
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states that using a 100 percent credit for
net overgeneration would result in
crediting the generator more than
$28,500.
649. WECC states that it is very
important to differentiate between the
kind of behavior that the Commission is
worried about and appropriate practices
that support system reliability. WECC is
concerned that inflexible generator
imbalance provisions in the pro forma
OATT may create incentives for
generators in the West to restrict
governor action on their generators in
ways that degrade system reliability.
WECC notes that the number of rotating
machines connected to the grid in the
Eastern Interconnection is much greater
than in the Western Interconnection,
which impacts the ability of generators
to respond to maintain frequency when
a system’s load-resource balance
changes. WECC explains that a sudden
change in load-resource balance of a
particular magnitude (for example, the
loss of a 1,000 MW generating plant)
will require a proportionately greater
response from each generating unit in
the West as compared to the Eastern
Interconnection. WECC contends that in
the West a significant frequency decline
could cause responding generators to
exceed a 1.5 percent deviation threshold
applied under current pro forma Tariff
imbalance schedules.
650. If the manner of implementing
generator imbalance charges in the West
does not consider the need for
generators to respond to frequency
deviations, WECC worries that these
charges could produce perverse
incentives that will undermine
reliability. WECC argues that generators
that use set-point controllers to override
governor action will be less likely to
incur imbalance charges and penalties,
while those with properly operating
governors may be punished for
deviating from scheduled output to
respond to system reliability needs.
WECC believes that this has in fact been
happening in the West and is one of the
reasons that frequency response in the
Western Interconnection has
deteriorated in recent years. WECC
urges the Commission to consider how
generators can be given appropriate
incentives to meet their obligations to
supply energy to load but also to
support system reliability by effectively
responding to frequency deviations.
WECC explains that the Commission
could adopt a policy that set-point
controllers should not be allowed to
override governor response. WECC
suggests that deviations from scheduled
generator output needed to correct
frequency decay could be excused from
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imbalance penalties under the pro
forma OATT.
651. Indianapolis Power contends on
reply that variation should be allowed
to account for the individual facts and
circumstances associated with a specific
region as well as specific types of
intermittent resources. A number of
entities agree with providing flexibility
to intermittent generators, but suggest
different ways of doing so.392 Fertilizer
Institute agrees that intermittent
resources should be exempt from any
penalties beyond the 90 percent/110
percent ‘‘second tier.’’ However,
Fertilizer Institute also believes that
intermittent resources should receive
greater tolerance before they run into
the 90 percent/110 percent penalty level
in the first place. Fertilizer Institute
urges the Commission to relax the firsttier tolerance band from 2MW to 20MW
(or 40 percent of nameplate capacity,
whichever is greater) for intermittent
generators only. It asserts that this
action is consistent with the
Commission’s recognition that
intermittent generators can undergo
sudden changes of conditions for which
they cannot fairly be held responsible.
Fertilizer Institute argues that a broader
first-tier tolerance band for these
generators will present no threat to the
transmission grid, because intermittent
generation facilities are limited both in
size and in number.
652. Geothermal Producers supports a
first-tier deviation band of +/¥5 percent
for intermittent resources, rather than
the 1.5 percent threshold proposed by
Bonneville. Geothermal Producers
believes a 5 percent band is appropriate
for intermittent resources, since a five
percent band more accurately
recognizes that intermittent resources
are less capable of controlling
deviations from schedules than are
conventional resources. For over- or
under-deliveries in excess of five
percent, Geothermal Producers contends
that intermittent resources should be
charged no more than the control area’s
cost of supplying energy to correct the
imbalance. Geothermal Producers also
supports Bonneville’s position that
intermittent resources should be exempt
from the third-tier deviation band and
instead should pay the second-tier
deviation band charges for all deviations
greater than the second-tier deviation
band.
653. Other commenters, however, do
not support providing exceptions for
392 E.g., NorthWestern, Fertilizer Institute, and
Geothermal Producers.
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intermittent resources.393 If society
decides to provide incentives for
intermittent resources, Morgan Stanley
states that this is better done in a direct
fashion, such as a certification program
akin to resource adequacy rules that
require LSEs to source a proportion of
supply from such resources. Morgan
Stanley asserts that this would motivate
developers to mitigate imbalance costs
through other market or technical means
to the full extent of the economic signal
imbedded in the imbalance price and
thereby optimize the design and
operation of such resources.
MidAmerican argues on reply that
special treatment of intermittent
resources and loads has the effect of
penalizing those resources and loads
that have made investments to manage
scheduling and enhance reliability. TDU
Systems believe that the NOPR’s third
principle, which requires transmission
providers to accord special treatment to
intermittent generators, is contrary to
the principle of comparability.
654. Northwest IOUs argue that the
transmission provider should have the
option to elect whether to exempt
intermittent resources from the thirdtier deviation band and instead charge,
in a not unduly discriminatory or
preferential manner, the second-tier
deviation band charge for all deviations
greater than the larger of 1.5 percent or
2 megawatts.
655. Several commenters suggested
that the Commission include a
definition of intermittent resource in the
final rule. Fertilizer Institute and South
Carolina E&G contend that it is essential
for the Commission to provide a clear
definition of ‘‘intermittent generation’’
or ‘‘intermittent resource’’ to avoid
disputes. Fertilizer Institute argues that
the question of whether a given
generator is ‘‘intermittent’’—and thereby
entitled to the special provisions—is
likely to become a source of contention.
Fertilizer Institute suggests that an
intermittent resource be defined as ‘‘an
electric generator that (1) Cannot store
its fuel sources and (2) has limited
capability to be dispatched and to
respond to changes in system demand
and transmission security constraints.’’
EEI, however, suggests that the
definition apply only to weather-driven
units. Fertilizer Institute argues on reply
that restricting the definition in this way
would be unduly discriminatory.
Fertilizer Institute argues that the
definition should include the most
common forms of intermittent
generation—wind and solar power—as
well as the less common but equally
393 E.g., Morgan Stanley, Northwest IOUs, Steel
Manufacturers Association, and TDU Systems.
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valuable forms, such as generation with
ocean energy or ‘‘waste heat’’ from an
industrial process. Fertilizer Institute
asserts that the Commission should not
broaden the definition of intermittent
resource to encompass generators who
are not truly ‘‘intermittent’’ and should
not narrow the definition to exclude
some intermittent generators in favor of
others. Fertilizer Institute contends on
reply that a generator should not have
to be ‘‘weather-driven’’ to qualify as
‘‘intermittent.’’ Geothermal Producers
supports the inclusion of geothermal
energy as an intermittent resource.
Geothermal Resources contends that
geothermal resources satisfy both the
Commission’s proposed definition and
the EEI proposal.
656. Ameren and Entergy ask the
Commission to clarify that it does not
intend to amend any existing
interconnection agreements to require
the use of any pro forma imbalance
penalties. Entergy believes that the
present form of its Generation
Interconnection Agreement is absolutely
critical to managing imbalances on its
system and maintaining reliability.
Entergy states that it has developed
specialized software to monitor and
manage generator imbalances and
employs six system operators (one per
shift) to monitor and manage generator
imbalances.
657. Although Entergy supports the
‘‘grandfathering’’ of existing generator
imbalance arrangements, it does not
believe that it would be appropriate to
require the prospective use of a different
methodology while simultaneously
maintaining the grandfathered
arrangements. Entergy contends that
administering two different generator
imbalance arrangements would not be
consistent with the comparability
principles of Order No. 888 and would
be difficult and costly from an
operational perspective.
658. Several commenters 394 argue on
reply that it would be inappropriate for
the Commission to grandfather existing
imbalance provisions. In its reply
comments, Entegra argues that prior
arrangements should remain in place
only if a transmission provider can
demonstrate that its existing imbalance
arrangements are consistent with or
superior to the provisions of the pro
forma OATT as modified by the Final
Rule in this proceeding.
659. EEI and Exelon contend that the
transmission provider may not be able
to charge a generator under its OATT if
the generator is not the transmission
customer and, therefore, generators
should be able to include standardized
394 E.g.,
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Frm 00084
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imbalance terms in agreements with
eligible customers prior to providing
service. Exelon suggests that the
Commission both adopt in the pro
forma OATT a standard imbalance
penalty structure and direct
transmission providers to include the
same terms and conditions in their
interconnection agreements with
generators. TAPS suggests on reply that
each generator could simply be required
to sign a service agreement that requires
it to comply with the generator
imbalance provisions of the
transmission provider’s OATT. Unless
the pro forma OATT governs both
generator and load imbalances, TAPS
argues that it would be impossible to
implement and enforce the
Commission’s prohibition against
charging both energy and generator
imbalances for a single transaction.
660. ICNU argues on reply that the
Commission should adopt less
restrictive imbalance charges for retail
access customers or, at a minimum,
continue to recognize that the standard
energy imbalance charge needs to be
modified to accommodate direct access
customers. ICNU asks the Commission
to modify its proposed imbalance
provision to reflect the unique
characteristics of direct access
customers by adopting wider imbalance
bandwidths and/or waiving the more
punitive adders associated with higher
deviations.
661. Several entities assert that the
proposed imbalance reform should not
apply to RTOs. Exelon requests that the
Commission explicitly state that these
rules do not apply in regions that have
organized markets, such as PJM, that
obviate the need for imbalance
penalties. They contend that within
organized markets, an imbalance
penalty rule is not necessary, as the
independent transmission operators
have effectively addressed the concerns
that the proposed imbalance schedules
are intended to address. Indicated New
York Transmission Owners contend that
the Commission should grant the
NYISO a regional variation from the
revised pro forma OATT with respect to
imbalance charges. It contends that the
existing mechanisms in ISO/RTO
markets with LMP are consistent with
the Commission’s objectives in its
NOPR and that the Commission should
permit a regional variation to the
NYISO. SPP states that the Commission
should state that it does not intend to
affect its effort to implement a real-time
energy imbalance market by any final
rule. SPP further contends that the
Commission should clarify that its
energy imbalance changes do not apply
to ISOs and RTOs with organized
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markets providing for real-time energy
imbalance markets. SPP believes that
the Commission should view the
existence of a spot energy price in
organized markets as superior to
penalties based on incremental costs or
some multiple thereof.
662. Entegra suggests that, since many
RTOs have (or are developing) separate
markets for commitment costs, it may
not be necessary to incorporate such
costs into imbalance prices in certain
RTO markets. Organizations of MISO
and PJM States contend that this
proposed change to Schedule 4 is not
applicable in the RTO context and argue
that, to the extent that the Commission’s
suggestions regarding the special
circumstances presented by intermittent
generators are applicable to RTOs, those
issues are best addressed in a context
other than the instant rulemaking
proceeding.
Commission Determination
663. In order to increase consistency
among transmission providers in the
application of imbalance charges, and to
ensure that the level of the charges
provides appropriate incentives to keep
schedules accurate without being
excessive, the Commission adopts in the
pro forma OATT imbalance provisions
similar to those implemented by
Bonneville. We agree with commenters
that a graduated bandwidth approach
recognizes the link between escalating
deviations and potential reliability
impacts on the system. Furthermore, we
conclude that these provisions adhere to
the three principles discussed in the
NOPR, which we also adopt here: (1)
The charges must be based on
incremental cost or some multiple
thereof; (2) the charges must provide an
incentive for accurate scheduling, such
as by increasing the percentage of the
adder above (and below) incremental
cost as the deviations become larger;
and (3) the provisions must account for
the special circumstances presented by
intermittent generators and their limited
ability to precisely forecast or control
generation levels, such as waiving the
more punitive adders associated with
higher deviations.
664. Specifically, imbalances of less
than or equal to 1.5 percent of the
scheduled energy (or two megawatts,
whichever is larger) will be netted on a
monthly basis and settled financially at
100 percent of incremental or
decremental cost at the end of each
month. Imbalances between 1.5 and 7.5
percent of the scheduled amounts (or
two to ten megawatts, whichever is
larger) will be settled financially at 90
percent of the transmission provider’s
system decremental cost for
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overscheduling imbalances that require
the transmission provider to decrease
generation or 110 percent of the
incremental cost for underscheduling
imbalances that require increased
generation in the control area.
Imbalances greater than 7.5 percent of
the scheduled amounts (or 10
megawatts, whichever is larger) will be
settled at 75 percent of the system
decremental cost for overscheduling
imbalances or 125 percent of the
incremental cost for underscheduling
imbalances.
665. The Commission adopts
Bonneville’s tariff provisions that
provide that intermittent resources are
exempt from the third-tier deviation
band and would pay the second-tier
deviation band charges for all deviations
greater than the larger of 1.5 percent or
two megawatts. We believe this is
consistent with the fact that intermittent
generators cannot always accurately
follow their schedules and that high
penalties will not lessen the incentive to
deviate from their schedules.
666. Several commenters argue that
the Commission should adopt a
standard definition of intermittent
resource. In order to clarify application
of imbalance charges, we define an
intermittent resource for this limited
purpose as ‘‘an electric generator that is
not dispatchable and cannot store its
fuel source and therefore cannot
respond to changes in system demand
or respond to transmission security
constraints.’’ 395 We conclude that this
definition of intermittent resource
properly limits the exemption from
imbalance charges, without excluding
certain classes of intermittent generators
for which the exemption is appropriate
(e.g., non-weather driven intermittent
resources).
667. The Commission believes that
adopting a tiered approach for both
energy and generation imbalances will
best balance the needs of transmission
providers to operate their transmission
systems in a reliable manner with the
needs of transmission customers to have
reasonable access to those systems at
just and reasonable rates. Furthermore,
we conclude that the partial exemption
from imbalance charges for intermittent
resources appropriately reflects the
special circumstances faced by such
resources and, consequently, is not
unduly discriminatory. Moreover,
395 See Docket No. RM05–10–000. We note that
this definition was proposed by the Commission in
the NOPR on Imbalance Provisions for Intermittent
Resources. See Imbalance Provisions for
Intermittent Resources; Assessing the State of Wind
Energy in Wholesale Electricity Markets, Notice of
Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005),
FERC Stats. & Regs. ¶ 32,581 (2005).
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12349
formalizing generator imbalance
provisions in the pro forma OATT will
standardize the future treatment of such
imbalances from the wide variety of
generator imbalance provisions that
exist today in various generator
interconnection agreements.
Standardizing generator imbalances
should lessen the potential for undue
discrimination, increase transparency
and reduce confusion in the industry
that results from the current plethora of
different approaches.
668. Several commenters debate
whether the imbalance provisions
adopted here should be applied to
energy imbalances, generation
imbalances, or both. The Commission
concludes that subjecting both energy
and generation imbalances to the same
charges is appropriate. Energy and
generation imbalances have the same
net effects on the transmission system in
requiring other generation to be ramped
up or down to make up for the
imbalance. As such, the Commission
will modify the current pro forma
OATT Schedule 4 treatment of energy
imbalances and adopt a new separate
pro forma OATT Schedule 9 for the
treatment of generator imbalances, each
based on the tiered structure described
above. To the extent a transmission
provider wishes to deviate from these
revised pro forma provisions, it may
demonstrate in an FPA section 205
proceeding that the proposed changes
are consistent with or superior to the
pro forma OATT as modified by this
Final Rule. However, we note that
proposed alternative provisions must
comply with the three imbalance charge
principles addressed in the NOPR and
adopted in this Final Rule and be
consistent with or superior to the
specific imbalance charges set forth in
the pro forma OATT (and discussed
above).
669. Some commenters stated that the
Commission should require
transmission providers to establish, or
permit market participants to establish,
markets or pools for the netting and
settlement of imbalances. As explained
previously, the purpose of this rule is to
strengthen the pro forma OATT to
remedy undue discrimination and not to
impose any particular market structure.
If transmission providers offer to modify
their OATTs to allow such pools, we
will consider such proposals. But,
imposing such requirements goes
beyond the scope of this proceeding.
The Commission therefore declines, for
all these reasons, to impose the
structural reforms requested by some
commenters.
670. The Commission instead adopts
the three-tiered approach in the pro
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forma OATT. As with other reforms
adopted in this Final Rule, all
transmission providers must submit
compliance filings containing these pro
forma tariff provisions. Transmission
providers with previously-approved
tariff provisions governing imbalances
that no longer conform to the pro forma
OATT, as revised in this Final Rule,
may seek renewed approval of those
tariff deviations in accordance with the
procedures described in section IV.C
above, demonstrating that the
alternative imbalance charge structures
are consistent with or superior to the
reformed pro forma OATT. With respect
to the concerns raised by ISOs and
RTOs, we agree that LMP-based markets
can provide an efficient and
nondiscriminatory means of settling
imbalances and, as indicated in the
NOPR, we are not proposing to redesign
ISO/RTO markets in this rulemaking.
Nevertheless, ISOs and RTOs must
follow the procedures described in the
Applicability section for seeking
approval of deviations that are
consistent with or superior to the pro
forma OATT.
671. We do not, however, abrogate
existing generator imbalance agreements
between transmission providers and
their customers. These agreements have
been negotiated between willing parties,
and the Commission will not re-open
them generically in this proceeding. To
the extent a particular party desires to
amend an existing generator imbalance
agreement in light of the reforms we
adopt in this Final Rule, that party may
exercise whatever rights it may have
under the agreement or FPA section
206.
672. With regard to WECC’s
frequency-response concerns, we agree
that a generator should be excused from
imbalance penalties that occur due to
directed reliability actions by generators
to correct frequency. It would not be
appropriate to assess imbalance charges
on generator deviations that are
associated with supporting system
reliability by responding to frequency
deviations as directed by the
transmission provider or general
reliability requirements. As such, if a
response from a generator (particularly
in the West) is required to prevent
frequency decay and the corresponding
deviations from the generator’s schedule
would cause additional imbalance
penalties, the transmission provider
should exempt the generator from those
penalty charges.
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b. Intentional Deviations
NOPR Proposal
673. In the NOPR, the Commission
noted that the Bonneville imbalance
provision allows for greater charges
when a customer has an ‘‘intentional
deviation.’’ 396 The Commission sought
comment on whether the pro forma
OATT imbalance provision should
provide for similar penalties for
behavior that represents deliberate
reliance on the transmission provider’s
generation resources, as opposed to
scheduling errors, with such penalties
being subject to prior notice and
approval by the Commission and based
on the facts and circumstances of the
individual transmission provider.
Comments
674. Several entities contend that
higher imbalance charges and penalties
for deliberately leaning on the grid can
be appropriate.397 Imperial supports an
imbalance provision that allows for
greater charges for persistent or
patterned deviations. Pinnacle agrees
that deliberate reliance on the
transmission provider’s generation
resources is inappropriate and could
adversely affect the reliability of the
transmission system, but they are
unsure if such an intentional deviation
could be proven. Imperial also expresses
concern that the burden to prove the
intent of the generator will fall on
transmission providers and that, in
reality, transmission providers may face
an uphill battle to prove a generator’s
deviation was intended. South Carolina
E&G and Imperial request that the
Commission provide a specific process
for imposing such penalties, including
what procedures should be followed if
a transmission provider seeks to have
the Commission impose such penalties.
675. Several entities oppose penalties
for intentional deviations or suggest
modifications. Constellation supports an
396 See 2006 Transmission and Ancillary Service
Rate Schedules, approved in United States Dep’t of
Energy—Bonneville Power Administration, 112
FERC ¶ 62,258 (2005). The Bonneville tariff
provides that ‘‘For any hour(s) that an imbalance is
determined by [Bonneville] to be an Intentional
Deviation: (1) No credit is given when energy taken
is less than the scheduled energy, (2) When energy
taken exceeds the scheduled energy, the charge is
the greater of: (i) 125% of [Bonneville’s] highest
incremental cost that occurs during that day, or (ii)
100 mills per kilowatthour.’’ An ‘‘Intentional
Deviation’’ is defined as ‘‘a deviation that is
persistent during multiple consecutive hours or at
specific times of the day,’’ a ‘‘pattern of underdelivery or over-use of energy,’’ or ‘‘persistent overgeneration or under-use during Light Load Hours,
particularly when the customer does not respond by
adjusting schedules for future days to correct these
patterns.’’ Id. at 46.
397 E.g., Imperial District Irrigation, Progress
Energy and Ameren.
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elimination of the separate penalty
structure for customers deliberately
leaning on the system. Constellation and
Grant believe that a graduated
percentage adder/discount will provide
the right incentives and disincentives
without the need for an intentional
deviation provision. If deviation costs
are properly calculated, Morgan Stanley
contends that requiring those who
deviate to pay the full marginal cost of
that deviation would result in fair
allocation of cost responsibility and
sufficient stability of system operations
as a result of both cost and risk
avoidance by participants. TDU Systems
argue that the Commission should
eliminate the 100 mill per kWh floor for
penalties for intentional deviations.
Commission Determination
676. The Commission recognizes the
need to provide transmission customers
with the appropriate incentives not to
intentionally dump power on the
system or lean on other generation. We
do not believe, however, that separate
penalties for intentional deviations need
to be generically imposed in the pro
forma OATT. The tiered imbalance
penalties adopted in this Final Rule
generally provide a sufficient incentive
not to engage in such behavior.
Proposals to assess additional penalties
for intentional deviations will continue
to be considered on a case-by-case basis,
subject to a showing that they are
necessary under the circumstances. We
note that any such tariff provisions must
include clearly defined processes for
identifying intentional deviations and
the associated penalties.
c. Calculation of Incremental Cost
NOPR Proposal
677. With respect to the pricing of
energy and generation imbalances, the
Commission stated in the NOPR its
belief that charges based on incremental
costs or multiples of incremental costs
would provide the proper incentive to
keep schedules accurate without being
excessive. The Commission proposed
that incremental cost be defined to
include both energy and
commitment 398 costs, to the extent
additional commitments are needed.399
398 The Commission noted that ‘‘capacity
commitment’’ is generally defined as the generating
capacity committed by a utility to provide
capability for another utility to attain its reserve
level. See, e.g., Central & South West Services, Inc.,
48 FERC 61,197 at 61,731 n.9 (1989).
399 The Commission proposed defining
incremental cost, based on its decision in
Consumers, as the transmission provider’s actual
average hourly cost of the last 10 MW dispatched
to supply the transmission provider’s native load,
based on the replacement cost of fuel, unit heat
rates, start-up costs, incremental operation and
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The Commission sought comment on
how such charges should be calculated,
as well as how they would be applied
to transmission customers. The
Commission sought further comment as
to how additional demand and energy
costs, if incurred in responding to
imbalances, such as redispatch,
commitment, or additional regulation
reserves, should be appropriately
reflected in the calculation of imbalance
charges and which customers should be
charged for such costs.
Comments
678. Several entities argue that
incremental pricing for both energy
imbalances and generator imbalances
should reflect the full incremental costs
incurred by the transmission provider
(e.g., such as redispatch costs, capacity
commitment costs or additional
regulation reserve costs) resulting from
the imbalance.400 Allegheny questions
whether the Consumer’s definition is
appropriate because ‘‘the last 10 MW’’
requirement is independent of the time
of the scheduling deviation. Allegheny
contends that the definition should be
modified such that it specifically
addresses the incremental dispatch to
supply the transmission provider’s load
‘‘in the hour in which the imbalance
occurs.’’
679. Entergy argues that imbalance
pricing on an hourly basis does not
capture all of the costs and reliability
risk to the transmission provider of
over- and under-deliveries. Entergy
states that the real-time regulation
burden imposed by IPPs is similar to the
real-time regulation burden imposed by
loads, and loads are charged for this cost
through a transmission provider’s
Schedule 3 Regulation and Frequency
Response Service. Entergy asserts that
the NOPR does not propose any
recovery mechanism for the regulation
burden imposed by IPPs, recognizing
that Bonneville may not face significant
generator regulation costs due to the
rapid ramping rate and relatively low
cost of hydroelectric resources. Entergy
submits that its regional experience has
demonstrated that generator regulation
service is a necessity. Entergy states that
its generator regulation service recovers
charges for the generating capacity that
Entergy must maintain on-line in order
to respond to the moment-to-moment
deviations between scheduled output
and actual generation. Entergy explains
that the charge compensates Entergy on
a cost-basis for the generation capacity
maintenance costs, and purchased and interchange
power costs and taxes.
400 E.g., Allegheny, Ameren, Indicated New York
Transmission Owners, and FirstEnergy.
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used by IPPs, while at the same time
sending the appropriate economic signal
that encourages generators to match
their generation with their schedules.
680. In its reply comments, EEI argues
that a transmission provider should be
entitled to recover the cost of additional
reserves needed to meet the increased
reliability requirements resulting from
the provision of the imbalance energy if
the transmission provider generates
additional energy to compensate for a
load that schedules less energy than it
takes or a generator that produces less
energy than it schedules. EEI further
contends that transmission providers
should be permitted to include in their
calculation of imbalance charges any
other costs associated with committing
a unit that is not on-line such as
minimum run times, losses, etc.
681. Entergy opposes a single price for
settling over-deliveries and underdeliveries. For transmission providers
who choose to base energy and
generator imbalance charges on
incremental and decremental costs,
Entergy requests that the Commission
not adopt standardized definitions of
incremental cost and decremental cost
in the pro forma OATT. In its reply
comments, Entergy further argues that a
requirement that the transmission
provider post incremental and
decremental cost information is unfair
and harmful to the market, placing the
transmission provider at an unfair
competitive disadvantage in the market.
Duke on reply proposes that System
Incremental Cost (SIC) be used to price
both over-deliveries and underdeliveries. Duke defines SIC to mean the
incremental expense, measured in
dollars per megawatt hour, incurred by
the utility to produce or procure the
next megawatt hour (MWh) of energy,
after serving all of the utility’s electric
energy and/or capacity sales. Duke
proposes that SIC shall include but not
be limited to: The replacement cost of
fuel; incremental operating and
maintenance costs; emissions allowance
replacement costs and other
environmental compliance costs; the
cost of starting and operating any
generating units, (including costs
incurred due to minimum runtimes or
loading levels); purchase and
interchange power costs; and all
applicable taxes or assessments based
on the revenues received or quantities
sold.
682. Allegheny states that the
Commission should clarify that the
definition of incremental cost is equally
applicable to intermittent generator
imbalance service as well as nonintermittent generator imbalance
service.
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12351
683. Pinnacle and Utah Municipals
request that the Commission allow the
use of alternative pricing
methodologies, such as market proxy
pricing methodology based on trading
hubs in or adjacent to their respective
control areas, where appropriate. Utah
Municipals urge the Commission to
make clear in the final rule that marketbased pricing may be acceptable in
some circumstances and to amend
Schedule 4 of the pro forma OATT to
ensure that imbalance charges are
designed not only to provide legitimate
incentives for accurate scheduling, but
also to avoid unjustified penalties
(masquerading as ‘‘incentives’’), to
minimize the discriminatory impact of
such charges, and to avoid penalizing
behavior or results that in fact help to
keep the system as a whole in balance.
684. TDU Systems believe the
Commission should disallow recovery
of demand charges or capacity
commitment costs in any charges
approved for imbalances. TAPS and
TDU Systems argue that capacity
required to follow load is already paid
for by charges for regulation and
reserves under Schedules 3, 5 and 6.
TDU Systems also support that the
Commission continue to apply its
existing policy of imposing a heavy
burden on transmission providers to
justify such demand or capacity
commitment charges in the context of a
full base rate case, and of requiring
transmission providers to develop
alternative solutions for balancing
schedules and loads.
685. To the extent transmission
providers are permitted to include
commitment costs in negative
imbalance charges, Entegra believes that
additional monitoring would be needed,
to include posting of hourly imbalance
charges, even if with a lag of a day or
so. Suez Energy NA contends that the
Commission should require a
transmission owner to support its
incremental cost filing on the basis of
Form No. 423 data and actual operations
of the selected units, based on
operational data as reported in utilities
Continuous Emission Monitoring
reports.
686. EEI argues that since Schedule 3,
5 and 6 charges recover the costs of
capacity based on test year data, they
would not recover the additional costs
of reserves that transmission providers
incur to compensate for their customers’
failures to match their schedules and
their loads or generator output, and they
also do not recover other commitment
costs such as start-up costs or minimum
run times. EEI argues that if
transmission providers could not
recover such costs through imbalance
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charges, they would not be able to
recover them at all.
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Commission Determination
687. The Commission concludes that
it is appropriate to define incremental
cost, for purposes of the tiered
imbalance provisions adopted above, as
the transmission provider’s actual
average hourly cost of the last 10 MW
dispatched to supply the transmission
provider’s native load, based on the
replacement cost of fuel, unit heat rates,
start-up costs, incremental operation
and maintenance costs, and purchased
and interchange power costs and taxes,
as applicable.
688. In deriving such charges, we note
that the Commission proposed in
paragraph 244 of the NOPR that
incremental cost be defined to include
both additional energy and commitment
costs. The Commission also sought
comment on how additional demand
and energy costs, such as redispatch,
commitment, or additional regulation
reserves, would be appropriately
recovered if incurred in responding to
imbalances.
689. The Commission finds that it is
appropriate, through the definition of
incremental cost, to allow for recovery
of both commitment and redispatch
costs while excluding the cost recovery
of additional regulation reserve costs.
Commitment and redispatch costs shall
be accommodated as a part of the hourly
cost of the last 10 MW dispatch and in
the start up cost portion of the
definition. The Commission concludes
that excluding additional regulation
costs as a general matter is appropriate
since much of those costs would be
demand costs.401 We believe including
charges for unit commitment costs (e.g.,
start-up and minimum load costs) and
O&M costs is necessary to ensure that
both energy and generation imbalance
charges reflect the full incremental costs
incurred by the transmission provider.
We emphasize, however, that such costs
should only be the additional costs
incurred by the transmission provider
due to the imbalance. If applicable,
start-up costs should be allocated pro
rata to the offending transmission
customers based on cost causation
principles.
690. If the transmission provider
elects to have separate demand charges
assigned to customers for the purpose of
recovering the cost of holding additional
401 To the extent a transmission provider wishes
to recover costs of additional regulation reserves
associated with providing imbalance service, it
must do so via a separate FPA section 205 filing
demonstrating that these costs were incurred
correcting or accommodating a particular entity’s
imbalances.
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reserves for meeting imbalances, the
transmission provider should file a rate
schedule and demonstrate that these
charges do not allow for double
recovery of such costs. To address
Entergy’s concern that the real-time
regulation burden imposed by IPPs is
similar to the real-time regulation
burden imposed by loads, we will allow
transmission providers to propose
separate regulation charges for
generation resources selling out of the
control area and consider such
proposals on a case-by-case basis. We
believe that the other demand costs of
providing imbalance service are already
being provided under Schedule 3, 5,
and 6 charges.
691. In responding to Allegheny’s
comments, we clarify that the definition
of incremental cost is equally applicable
to intermittent generator imbalance
service as well as non-intermittent
generator imbalance service.
692. We do not believe it appropriate
to require transmission providers to use
market proxy pricing to calculate
incremental costs in the pro forma
OATT. The feasibility of using market
proxies must be considered on a caseby-case basis, given the characteristics
of each market. If proposed, the proxy
price must represent a valid alternative
to the incremental cost calculation,
reflecting competitive, transparent and
liquid conditions similar to those that
would exist in the seller’s market.402
d. Inadvertent Energy Treatment
NOPR Proposal
693. The Commission proposed in the
NOPR to continue to allow inadvertent
energy to be treated differently from
energy and generator imbalances,
explaining that these two types of
service are not comparable. The
Commission noted that, given the nature
of inadvertent energy and historical
practices, transmission providers pay
back inadvertent energy imbalances and
that the Commission has accepted this
practice as just and reasonable. The
Commission sought comment on
whether the current return-in-kind
approach to inadvertent energy
encourages leaning on the grid in times
of shortage and, therefore, whether any
reforms in this area are appropriate. The
Commission asked whether pricing
inadvertent energy at incremental cost
(or some variant thereof) would be an
appropriate disincentive and, if any
reforms in this area are appropriate,
402 See RockGen Energy, LLC, 100 FERC ¶ 61,261
(2002) (setting for hearing, inter alia, whether
proposed market proxy price is reliable, verifiable,
and also indicative of the prevailing price in liquid
non-redispatch markets in the region).
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whether they should be pursued under
FPA section 215 as part of the review of
reliability standards.
Comments
694. A number of commenters
support continuing to allow inadvertent
energy to be treated differently from
energy and generator imbalances,
agreeing that these two types of services
are not comparable.403 Allegheny argues
that this historical practice makes sense
because the variables germane to
inadvertent interchange are beyond the
control of individual transmission
providers and, therefore, are best
addressed in the context of reliability.
Entergy notes that transmission
customers have some flexibility to
mitigate the deviations between their
schedules and the operation of their
load in real-time, while control area
interchange imbalances may involve the
failure of control areas to match their
scheduled inflows and outflows due to
contingencies occurring even in a third
control area.
695. Northwest IOUs argue that there
is no reason to think that there is abuse
of one system leaning on another in
regards to inadvertent energy,
particularly in light of Control
Performance Standards 1 and 2 and
other protocols for balancing flows
across interconnections. Public Power
Council states that in-kind return of
inadvertent energy between Balancing
Authorities is governed by numerous
agreements and tariffs that are designed
to limit the ability of one system to lean
on another.
696. Sacramento states that the
Commission expressed concern in other
settings that generators may
intentionally undergenerate during
high-cost hours and make it up by
overgenerating during low-cost hours
under a return-in-kind approach.
Sacramento contends that in kind
means not only a return of energy, but
a return of energy at like times and
conditions and does not believe that this
results in leaning. In its reply
comments, Exelon requests that the
Commission’s imbalance penalty rules
explicitly prohibit the local utility
Balancing Authority operator from
relying on inadvertent energy to balance
its affiliated generators’ schedules and
thus obtaining a competitive advantage.
697. Other commenters disagree that
inadvertent energy should continue to
be treated differently. Exelon expresses
concern that in regions without
organized markets there is the potential
403 E.g., Entergy, Allegheny, Progress Energy,
Public Power Council, South Carolina E&G, PGP,
and Ameren.
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for local utility balancing authority
operators to seek to avoid paying
deviation charges by favoring their own
generators over merchant generators or
by using inadvertent energy to balance
their schedule. Exelon argues that a
balancing authority operator could
maintain system balance by choosing to
order its affiliated generators to deviate
from the schedule and thereby allow its
affiliated generator to avoid deviation
charges that the merchant generator
could not avoid. If the local utility
balancing authority operator relies on
inadvertent energy to balance its
affiliated generators’ schedules, Exelon
contends it is using an option that is
unavailable to other generation
resources and obtains a competitive
advantage.
698. TDU Systems argue that energy
imbalances and inadvertent interchange
may occur for many of the same reasons,
e.g., telemetry failure, meter error,
generator governor response to system
problems, human error, and under- or
over-supply of generation. TDU Systems
state that deviations between load and
supply, whether in the form of energy
imbalances or inadvertent interchange,
require adjustment or compensation, but
there is no reason why the form of that
adjustment or compensation should be
different among transmission users.
TDU systems explain that NERC’s Final
Report of the Control Area Criteria Task
Force describes inadvertent interchange
as one of the ‘‘strong incentives’’ driving
the newer market participants, such as
independent generators, to become
control areas, and driving existing
control area operators to retain their
functions.
699. TDU Systems explain that as the
Commission acknowledged in Order No.
2000, for transmission providers in RTO
regions, unequal access to balancing
options can lead to unequal access in
the quality of transmission service. TDU
Systems oppose deferring consideration
of inadvertent interchange issues until
the Commission’s order in the
Mandatory Reliability Standards
rulemaking proceeding in Docket No.
RM06–16–000. TDU Systems argue that
the Commission should place energy
imbalance service on a footing as nearly
comparable to inadvertent interchange
as feasible by allowing like-kind
exchanges of energy, at the incremental
cost of their own supply portfolio, to
remedy imbalances in lieu of the
present paradigm of punitive charges.
700. TDU Systems also argue that the
Commission should require
comparability between transmission
providers and transmission customers
by imposing charges for inadvertent
interchange at the suppliers’
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incremental cost. FirstEnergy believes
that the Commission should establish a
tiered penalty structure that, similar to
the Bonneville method discussed by the
Commission, levies penalties based on
the severity of the inadvertent energy
violation. TDU Systems state that
currently there are no penalties for
under-supply even when one control
area could be deemed to be
intentionally ‘‘leaning’’ on the grid to
arbitrage energy market prices; but there
should be.
701. FirstEnergy argues that a
nationwide process should be
established by the Commission to
eliminate regional differences in the
treatment of inadvertent energy.
Constellation asks the Commission to
require that transmission providers
specifically separate imbalances from
inadvertent energy and closely track and
report the two.
Commission Determination
702. As stated in the NOPR, the
Commission finds that inadvertent
energy is not comparable to energy and
generation imbalances and, therefore,
we will continue to allow inadvertent
energy to be treated differently from
energy and generation imbalances.
Inadvertent energy represents the
difference between a control area’s net
actual interchange and the net
scheduled interchange. It is caused by
the combined effects of all the
generation and loads in the control area
and generation and loads outside of the
control area. Variables affecting
inadvertent interchange often depend
on the actions or the omissions of
utilities other than the individual
transmission providers and are distinct
from those resulting in energy and
generation imbalances.
703. We also note that management of
inadvertent energy is needed to adhere
to NAESB standards. Historically,
transmission providers have paid back
inadvertent interchange imbalances in
kind, which has not, as a general matter,
proven to be problematic. Our primary
concern with respect to inadvertent
energy is to avoid incentives that could
degrade reliability. To date, the returnin-kind approach has proven to be
adequate as a general matter. However,
if there is evidence that it is no longer
sufficient to maintain reliability, or is
allowing certain entities to lean on the
grid to the detriment of other entities,
the Commission has authority under
FPA section 215 to direct the ERO to
develop a new or modified standard to
address the matter.
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12353
e. Netting/Crediting of Energy and
Generator Imbalances
NOPR Proposal
704. In the NOPR, the Commission
sought comment on whether or not it is
appropriate to allow a transmission
customer to net energy and generator
imbalances for a particular transaction
within a single control area to the extent
they offset.404 The Commission asked
whether the potential to allow netting
for offsetting imbalances contradicts the
principle of encouraging good
scheduling practices. The Commission
sought further comment on what would
be a reasonable percentage to net
without concerns that allowing such
netting would lead to reliability
concerns from using unscheduled
transmission or would cause redispatch
costs by the transmission provider.
705. The Commission also proposed
to add provisions to schedule 4—Energy
Imbalance Service and schedule 9—
Generator Imbalance Service of the pro
forma OATT to reflect the Commission’s
policy that a transmission provider may
only charge a transmission customer for
either hourly generator imbalances or
hourly energy imbalances for the same
imbalance, but not both.405 The
Commission explained that this policy
only applies to a transmission customer
that otherwise would be charged for
both generator imbalances and energy
imbalances for the same imbalance
occurring within the same control area.
Comments
706. A number of entities believe that
transmission customers should be
permitted to net energy and generator
imbalances to the extent that such
imbalances offset.406 Ameren and
FirstEnergy assert that netting better
reflects the impact of imbalances.
Morgan Stanley argues that allowing
such netting provides a clear
competitive benefit because it would
allow competitive suppliers to offer a
load following service in competition
with the transmission provider.
Sacramento agrees that netting of
offsetting imbalances should be allowed
404 For example, the Commission noted that a
transmission customer scheduling 100 MWh over
an hour, but with a load of 120 MWh, would face
an imbalance of 20 MW. The Commission
questioned whether there should be a net charge if
the customer also dispatched its generation to the
same 120 MWh. Similarly, what if a transmission
customer schedules 100 MWh, but has a load of 80
MWh and dispatches its generation to 80 MWh?
405 Imbalance Provisions Proceeding at 32,123
note 19 (citing Niagara Mohawk, 86 FERC ¶ 61,009
at 61,028).
406 E.g., Ameren, FirstEnergy, Xcel, Suez Energy
NA, Morgan Stanley, Sacramento, TDU Systems,
and Utah Municipals.
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provided the transmission customer
relies on reasonable load forecasts.
707. Utah Municipals and Steel
Manufacturers Association argue that
the Commission should impose charges
based on netted imbalances, both for
each customer and across the system as
a whole. PGP contends that there is no
reason to charge for both imbalances if
a generator overruns during the same
hour when a load overruns, so long as
the overruns cancel out within a given
control area. Steel Manufacturers
Association contends that the
Commission should incorporate control
area-wide netting of imbalances to
ensure that penalties are only assessed
on significant imbalances and energy
imbalance charges do not become a
windfall profit center for utilities. Utah
Municipals suggest that the Commission
provide that all imbalances be netted for
each hour and that penalties (charges
above or credits below actual costs) be
imposed only when the system as a
whole is out of balance by more than a
de minimis amount and, even then, only
on those customers whose imbalances
fall in the same direction as the system
imbalance. Utah Municipals note that
Sierra Pacific has established a similar
imbalance mechanism, which appears
to be working well in its control area.
708. TDU Systems argue that the
netting rules should be sufficiently
flexible to allow individual customers to
net their transactions within an hour, a
day, a week or a month, so long as the
results keep the transmission provider
economically whole. TDU Systems state
that the Commission should not impose
a cap on the quantity of netting allowed
unless the transmission provider is able
to demonstrate that good system
performance requires such a cap.
Ameren suggests that the Commission
use a tiered system for determining
when imbalances can be netted, but
argues that a transmission customer
should not be allowed to net offsetting
imbalances elsewhere on the system if
the imbalance has the potential to have
a significant reliability impact.
709. FirstEnergy and Utah Municipals
contend that both point-to-point and
network transactions should be eligible
for netting. Utah Municipals and
NRECA in their reply comments note
that the Commission’s reference to ‘‘a
particular transaction’’ does not mesh
with the needs and practices of network
customers, who do not attempt to match
portions of their total hourly loads with
particular resources or ‘‘transactions.’’
Utah Municipals argue that the
Commission’s proposal should be
modified to make clear that such
customers should be permitted to net
energy and generator imbalances within
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a single control area to the extent they
offset, with no requirement that the
imbalances be part of a single
‘‘transaction.’’
710. Other commenters, however,
contend that transmission customers
should not be permitted to net energy
and generator imbalances.407 For
example, Entergy and Pinnacle believe
that to permit netting of energy and
generator imbalances is to undercut the
very purpose of the imbalance
provisions, which is to provide
adequate incentives to schedule
correctly and in accordance with good
utility practice. Pinnacle asserts that,
depending upon the location, energy or
generator imbalances could create
reliability or economic problems for
specific areas of the system and it is
important that the transmission operator
know what is happening on its system
and for the customer to adhere to
accurate scheduling. SPP argues that
allowing netting of imbalance energy
between generation and load would
allow price arbitrage that would be
unjust and unreasonable. Indicated New
York Transmission Owners assert that
positive and negative imbalances do not
actually offset, as the NOPR would
suggest, but rather each imbalance
independently places stress on the
transmission system. Duke states on
reply that, although several commenters
support netting imbalances, not one
entity supporting such netting has put
forth a workable proposal for how to
implement such netting where multiple
generators are serving multiple loads.
711. Entergy believes that
independent generators must take full
responsibility for meeting their own
schedules, including making
adjustments to their schedules to
conform them to their operation in realtime. Entergy argues that a netting
approach, however, would provide an
incentive for a generator to overgenerate above its schedule if its load
proves to be greater than expected in
real-time. Entergy argues that allowing
the netting of these imbalances will
result in the virtual elimination of
transmission schedules.
712. In instances in which
transmission customers intentionally
game the transmission system through
netting, FirstEnergy contends that the
transmission provider should have the
ability to apply punitive measures
through a Commission-mandated
penalty process. FirstEnergy states that
there appears to be no clear cut number
which defines the boundary between
‘‘good’’ netting and ‘‘bad’’ netting
407 E.g., Entergy, Pinnacle, Indianapolis Power,
and Indicated New York Transmission Owners.
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associated with reliability issues and
additional redispatch cost. During
periods when transmission constraints
exist, Entergy contends that it may in
fact be ramping up some generators to
respond to imbalances while ramping
down other generation to respond to
other imbalances at exactly the same
time and, therefore, it is incorrect to
assume that over-generation supplied by
one IPP accompanied by undergeneration from another IPP, even
simultaneously, will have no
operational effect or impose no costs on
a transmission provider.
713. Allegheny believes that allowing
netting of hourly deviations inside the
first deviation band on a monthly basis
would not allow for full recovery of
imbalance costs because balances that
occur in on-peak periods cost more than
imbalances that occur during off-peak
periods. Allegheny contends that
deviations within the first band should
be measured and settled financially on
an hourly or, at least, an on-peak/offpeak basis, rather than allowing
deviations during one part of the month
to be offset by deviations in another part
of the month. Indianapolis Power &
Light Company argues that the
imbalance volume could be within the
allowed bandwidth tolerance, but still
be significant enough to allow for the
energy market participant to make
money off of the price difference.
714. Entergy also contends that a
crediting mechanism for generator
imbalances would be not appropriate.
Entergy asserts that such a credit would
result in indifference by generators by
largely immunizing them from the costs
resulting from their imbalances and, as
a consequence, produce economic
inefficiencies and a potential threat to
system reliability. Entergy argues that
the current method, which provides an
incentive to generators to control their
own imbalances, is appropriate because
generators have a desire to accurately
schedule to avoid imbalances. Entergy
argues that a non-offending generator in
one hour can be an offending generator
in the next hour and that the credit will
bankroll generators so that penalty
payments in one hour will be offset and
paid for by penalty receipts in another
hour.
Commission Determination
715. The Commission recognizes that
there is a trade off between the
competitive benefits of reducing
imbalance charges, including allowing
transmission customers to net energy
and generation imbalances, and the
reliability implications of the
transmission provider needing to plan
to accommodate such imbalances.
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Allowing transmission customers to net
imbalances would further comparability
between the transmission provider’s
dispatch and the transmission
customers serving load. However,
netting and crediting could lessen the
incentive for accurate scheduling and
resulting energy or generator imbalances
could create reliability or economic
issues for specific areas of the system if
the transmission provider cannot
adequately plan for such imbalances.
716. In weighing these tradeoffs, the
Commission concludes that for both
energy and generator imbalance services
it is not appropriate to require
transmission providers to allow netting
of imbalances outside of the tier one
band. We agree that netting can cause
problems because netting would lessen
the incentive for transmission customers
to schedule accurately, and inaccurate
schedules, in turn, could require actions
by the transmission provider even when
the imbalances offset. Where
transmission constraints exist, a
transmission customer whose load and
generation was on net equal could still
have an effect on the transmission
system if, as Entergy contends, some
generation is ramping up to respond to
some imbalances while other generation
is ramping down at exactly the same
time. Similarly, where transmission
constraints exist, if one IPP has a
positive deviation from its schedule
while another IPP has a corresponding
negative deviation from its schedule, the
transmission provider could need to
ramp up generation in one area while
simultaneously ramping down
generation in another area. Further, we
believe that flexible scheduling
deadlines should allow transmission
customers to change their schedules
such that their loads can be accurately
met and implementation of the tiered
imbalance bands will ensure that
charges corresponding to imbalances are
just and reasonable.
f. Intra Hour Netting
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NOPR Proposal
717. Under the current pro forma
OATT, energy imbalances occur when
there is a difference between the
scheduled and the actual delivery of
energy to a load located within a control
area aggregated over a single hour. As a
result, if a transmission customer is
under its scheduled level for the first
half of a given hour, but over its
schedule the second half of the hour,
there would be no imbalance charge.
The Commission did not address intra
hour netting in the NOPR.
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Comments
718. Several commenters argue that
the Final Rule should address withinhour deviations that occur when
generator imbalances are calculated on
an integrated hour basis.408 If the
generator imbalance is measured over
an integrated hour, as is typical of the
current practice, TVA asserts that
significant intra-hour swings may be
masked.
719. South Carolina E&G states that
generators, unable to ramp precisely to
the 15-minute schedules, often
undergenerate in the initial part of the
hour, then overgenerate in later parts of
the hour, in order to integrate closer to
the schedule when settled over the
entire hour. South Carolina E&G
contends these intentional swings
burden the balancing authorities who
are charged with continuously keeping
Area Control Error within predefined
limits. International Transmission
argues that intentional swings in output
can be quite severe, imposing
operational strains on the system,
negatively impacting the control area’s
ability to meet NERC Control
Performance Standards, and potentially
jeopardizing reliability.409 Entergy
agrees that settling hourly energy
imbalances with generators does not
provide adequate incentives for
generators to schedule and dispatch
accurately within the hour. Entergy
asserts that generators have imposed
significant moment to moment swings
within the hour requiring it to deploy its
regulating reserves in response. Entergy
states that it has been increasingly
difficult to meet NERC’s operating
criteria for control area performance
without committing, and incurring the
costs for, additional regulating reserves.
TVA contends that all generators should
be required to ensure that the
instantaneous generation level equals
the scheduled output. International
Transmission asks that the imbalance
provisions in the Final Rule address this
situation by either specifying penalties
that may be assessed for within-hour
variations or advising that transmission
providers may implement their own
penalties to the extent that within-hour
variations cause operational difficulties.
720. South Carolina E&G contends
that allowing generator imbalance
settlements over a shorter period, such
as at 15-minute intervals, together with
408 E.g., TVA, South Carolina E&G, and
International Transmission.
409 International Transmission provides the
example that a large generator with scheduled
output of 100 MW for an hour might stay at zero
for the first 50 minutes of the hour and then
generate 600 MW during the last ten minutes.
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12355
the proposed tiered charges for
imbalances, would provide better, more
refined incentives for generators to more
closely match their scheduled deliveries
and would help balancing authorities
reduce Area Control Error excursions.
TVA suggests generator imbalances be
measured on ten-minute intervals rather
than integrated over an hour. These tenminute imbalances would not be netted
against other imbalance intervals, so as
to avoid the problem of encouraging
undergeneration followed by
overgeneration and vice versa. In
addition to having generator imbalance
charges for generation outside the
operating bands, TVA argues that there
should be a separate charge assessed
based on the peak generator imbalance
between the scheduled and actual
generation recorded instantaneously
during the clock hour to provide a
further incentive for proper generator
scheduling.
721. Pinnacle and Utah Municipals
assert that a transmission provider
should only charge hourly generator
imbalances or hourly energy imbalances
for the same imbalance. PGP argues that
customers should pay only one charge
for the net imbalance that occurs within
a single control area, either energy or
generation, unless congestion occurs
inside a control area that requires
redispatch.
Commission Determination
722. The Commission concludes that
it is appropriate to maintain the status
quo of aggregating net generation over
the hour in the pro forma OATT.
Requests by transmission providers to
adopt a shorter interval will continue to
be considered on a case-by-case basis.410
The Commission acknowledges that
shorter intervals may be appropriate in
particular circumstances and, for this
reason, declined to use a clock-hour
interval in the Large Generator
Interconnection Final Rule.411 There,
the Commission permitted use of an
interval ‘‘consistent with the scheduling
requirements of the Transmission
Provider’s Commission-approved Tariff
and any applicable Commissionapproved market structure.’’ 412
Allowing transmission providers to
continue to propose alternative intervals
for purposes of the pro forma OATT
imbalance provisions is therefore
appropriate provided that such
proposals are consistent with relevant
market structures.
410 See Entergy Services, Inc., 102 FERC ¶ 61,014
(2003) and Entergy Services, Inc., 111 FERC
¶ 61,314 (2005).
411 See Order No. 2003 at P 335.
412 See pro forma LGIA Article 4.3.1
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g. Distribution of Penalty Revenues
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NOPR Proposal
723. The Commission also sought
comment in the NOPR regarding the
treatment of revenues the transmission
provider receives above the cost of
providing the imbalance service.
Comments
724. Various commenters state that
the transmission provider should retain
any amounts above the incremental cost
of providing imbalance service. Ameren
and Constellation argue such revenues
should serve as a contribution towards
the fixed costs of providing this service.
Entergy argues that premium charges
would compensate it for the
administrative costs of maintaining an
organization capable of providing this
purchase and sales function and provide
generators with an incentive to avoid
mismatches between scheduled
quantities and actual deliveries to
Entergy. Entergy states that the
Commission has previously recognized
that these generator imbalance charges
are analogous to the economy power
rates that have historically included a
percentage adder for out-of-pocket costs
to recover difficult-to-quantify costs.
725. On the other hand, FirstEnergy
states that the additional revenue
derived from charges above incremental
costs should be provided to generators
and/or customers able to regulate load
that provided the redispatch,
commitment, or additional regulation
reserves. Utah Municipals contend that
the Commission should credit revenues
from charges above incremental costs to
accurately-scheduling customers, rather
than to the transmission provider. Utah
Municipals argue that the penalty
portion of incremental and decremental
charges and rates could be credited back
to all transmission customers who incur
imbalance charges and whose schedules
fell within the first deviation band for
that hour. Progress Energy suggests that
all imbalance revenues above the cost of
providing the imbalance should be
distributed to all non-offending
transmission customers, based on the
weighted amount of each non-offending
transmission customer’s usage of the
transmission provider’s transmission
system. TAPS and TDU Systems ask on
reply that penalty revenues not be
earmarked for retail customers.
726. Morgan Stanley believes that
imbalance charges should be ‘‘keep
whole’’ charges calculated and designed
to reimburse whoever remedied
whatever problem the imbalance caused
while leaving the transmission provider
financially indifferent.
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Commission Determination
727. In this Final Rule, the
Commission has reformed existing
imbalance provisions to reduce the
variety of different methodologies used
for determining imbalance charges and
ensure that the level of the charges
provide appropriate incentives to keep
schedules accurate without being
excessive. We also believe that
transmission providers should have a
consistent method of treating revenues
received through imbalance penalties or
charges that are in excess of incremental
cost. The Commission has previously
required transmission providers with
significant imbalance penalties to
develop a mechanism to credit penalty
revenues to non-offending transmission
customers.413 This was intended to
remove the incentive of the
transmission provider to hinder the
development of other imbalance
services that do not rely on penalties.414
We believe it is appropriate to maintain
the requirement that transmission
providers credit revenues in excess of
incremental costs. Therefore, as part of
their compliance filings in this
proceeding, transmission providers are
required to develop a mechanism for
crediting such revenues to all nonoffending transmission customers
(including affiliated transmission
customers) and the transmission
provider on behalf of its own customers.
Such a distribution of penalty revenues
recognizes that transmission providers
bear the responsibility to correct
imbalances and often use their own
facilities to do so.
728. We acknowledge that in the
CP&L decision, the Commission
declined to allow the transmission
provider to allocate a share of imbalance
penalty revenues to itself as a user of the
transmission system on behalf retail
customers. Given the reforms to the pro
forma OATT imbalance provisions
adopted in this Final Rule, we believe
the circumstances presented in that case
are no longer applicable. There, the
Commission based its holding on its
understanding that the high imbalance
penalties imposed by the transmission
provider were an interim measure that
were intended to be in place only until
an imbalance market was developed.415
In this Final Rule, we are adopting
imbalance charges that are closely
related to incremental cost and therefore
413 See Carolina Power & Light Co., 103 FERC
¶ 61,209 at P 25 (2003) (CP&L); Entergy Svcs., 105
FERC ¶ 61,319, reh’g denied, 109 FERC ¶ 61,095 at
P 65–66 (2004).
414 See Carolina Power & Light Co., 97 FERC
¶ 61,048 at 61,279 (2001).
415 Id.
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minimize any incentive on the part of
the transmission provider to rely on
penalty revenues rather than seeking
other methods of encouraging accurate
scheduling. Under these circumstances,
there remains no reason to exclude the
transmission provider from receiving an
appropriate share of penalty revenues.
3. Credits for Network Customers
729. In Order No. 888, the
Commission established that network
customers should be eligible for credits
for customer-owned transmission
facilities under certain circumstances.
Specifically, section 30.9 of the pro
forma OATT states that a network
customer owning existing transmission
facilities that are integrated with the
transmission provider’s transmission
system may be eligible to receive cost
credits against its transmission service
charges if the network customer can
demonstrate that its transmission
facilities are integrated into the plans or
operations of the transmission provider
to serve its power and transmission
customers. Section 30.9 also states that
new facilities are eligible for credits
when the facilities are jointly planned
and installed in coordination with the
transmission provider.
NOPR Proposal
730. In the NOPR, the Commission
proposed severing the link in the pro
forma OATT between joint planning
and credits for new facilities owned by
network customers because such linkage
can act as a disincentive to coordinated
planning. The Commission proposed
deleting from section 30.9 the language
that permits transmission providers to
refuse crediting for new network
customer-owned facilities that are not
part of its planning process, and adding
language that puts a greater emphasis on
comparability. Specifically, the
Commission proposed that the network
customer shall receive credit for
transmission facilities added subsequent
to the effective date of the Final Rule in
this proceeding provided that such
facilities are integrated into the
operations of the transmission
provider’s facilities and if the
transmission facilities were owned by
the transmission provider, they would
be eligible for inclusion in the
transmission provider’s annual
transmission revenue requirement as
specified in Attachment H of the pro
forma OATT.
731. In the NOPR, the Commission
also declined to allow transmission
providers as part of this proceeding to
automatically add costs of credits to the
transmission provider’s cost of service.
However, the Commission stated that a
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transmission provider may propose to
add an automatic adjustment clause to
its rates in a filing submitted under
section 205 of the FPA. The
Commission also explained that it
would not propose to make credits
generically available to point-to-point
customers that own transmission
facilities, but clarified that if some
facilities owned by a point-to-point
customer meet all the criteria for credits,
consistent with the Commission’s
statement in Order No. 888, the
Commission would address such
situations on a fact-specific, case-bycase basis.416
a. Severance of Credits and Planning
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Comments
732. The NOPR proposal to sever the
link between transmission credits and
joint planning by eliminating the jointplanning requirement for credits for
new facilities constructed by network
customers is supported by a crosssection of the industry.417 Exelon asserts
that linking credits to network
customers with coordinated planning
simply creates an incentive for the
transmission provider to avoid
coordinated planning with the network
customers so that the provider can avoid
providing credits. In addition, the
criterion of ‘‘jointly planned’’ with the
transmission provider provides little or
no value for discerning what facilities
should qualify for crediting treatment.
Further, Exelon argues, tying credits to
joint planning is no longer necessary
because the Commission’s regional
planning initiatives will insure that
most, if not all, newly constructed
facilities will be jointly planned. While
EEI disagrees that the joint planning
provision has acted as a disincentive to
joint planning, it agrees that the
coordinated planning initiatives in the
NOPR has made the link unnecessary.
733. FMPA also argues that the link
between credits and planning
discourages joint planning because
companies can avoid transmission rate
credits, often for competitors, by simply
refusing to jointly plan. FMPA asserts
that it makes no sense to create
economic disincentives to joint
planning. According to these
commenters, transmission lines cannot
be built without some exchange of
information; the joint planning link may
discourage the most productive
exchange and can create needless and
416 Order No. 888 at 31,742; Order No. 888–A at
30,271.
417 E.g., Allegheny, East Texas Cooperatives,
ELCON, Exelon, FMPA, MDEA, MidAmerican,
MISO, Suez Energy NA, Tacoma, TAPS, and Utah
Municipals.
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non-productive disputation over
whether joint planning did or should
have taken place.
734. PGP points out, however, that
credits for new facilities can only result
from joint planning, because new
facilities must be interconnected with
the existing grid, and planning studies
are necessary for that to happen.
NorthWestern requests that the
Commission reconsider its proposal to
allow crediting of customer-owned
facilities that have not been jointly
planned with the transmission provider.
NorthWestern contends that allowing
the construction of network facilities
and making a judgment after the fact is
inefficient and will result in protracted
litigation and facilities that do not serve
the overall grid as efficiently as planned
facilities. PNM–TNMP contends that the
Commission’s proposed action to ‘‘sever
the link’’ will excuse the network
customer from the coordinated planning
process and can only operate at crosspurposes with the coordinated
transmission planning goal that is
addressed in the planning sections of
the NOPR.
Commission Determination
735. The Commission adopts the
NOPR proposal to sever the link in the
pro forma OATT between joint planning
and credits for new facilities owned by
network customers. The proposal
received broad industry support, and we
agree with these commenters that the
link between credits for new facilities
and the requirement for joint planning
can act as a disincentive to coordinated
planning, which is contrary to the
Commission’s original objective in
adopting the provision. A transmission
provider has an incentive to deny
coordinated planning in order to avoid
granting credits for customer-owned
transmission facilities.
736. We find that arguments against
the proposal are largely theoretical and
do not adequately take into account the
coordinated planning provisions
proposed in the NOPR. The coordinated
planning initiatives that the
Commission is adopting in the Final
Rule will ensure that most, if not all,
transmission facilities are planned on a
coordinated basis, making it
unnecessary to retain this provision of
section 30.9.
b. The New Test to Determine Eligibility
for Credits
737. Comments support the test for
new facilities proposed in the NOPR.418
418 E.g., Allegheny, EEI, Exelon, MISO, Nevada
Companies, South Carolina E&G, Suez Energy NA,
and Tacoma.
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12357
Some argue that the test for network
customer credits should continue to be
whether the network customer’s
facilities provide capability and
reliability benefits to the grid—the same
standard that would apply to inclusion
of the facilities in the transmission
provider’s cost of service if the
transmission provider constructed the
facilities.419 MidAmerican states that
further clarification of this point in the
Final Rule would be beneficial in
minimizing disputes over this issue.
Likewise, MidAmerican asks the
Commission to clarify in the Final Rule
that such credit can be applied only to
network customers taking OATT service
and not to transmission customers that
are under non-OATT (i.e., grandfathered
bundled agreements) contracts. PGP
supports the new rules for granting
credits to network customers, but argues
implementation details should be left
up to individual transmission providers.
738. Although several transmission
providers support the continued use of
the integration test,420 other
commenters representing municipal and
public power interests ask that the
Commission reconsider or clarify its
application.421 Some commenters argue
that given the Commission’s current
interpretation of ‘‘integration’’ for
transmission credit purposes and the
historical application of the test,
retaining any integration requirement
for existing or new facilities conflicts
with comparability or constitutes undue
discrimination.422 TDU Systems argue
that the integration standard has
encouraged discriminatory behavior by
allowing transmission providers to
charge network customers for
transmission provider facilities
constructed to serve the transmission
provider’s native load, while refusing to
pay the network customer for
comparable customer-owned
transmission facilities. TDU Systems
further argue that the integration test
has resulted in a form of ‘‘and’’ pricing
since the TDU Systems, as network
transmission service customers, remain
obligated to pay their load ratio share of
the full transmission revenue
requirement of the transmission
provider’s system, including the cost of
transmission facilities built to serve the
transmission provider’s own loads.
739. NRECA questions the
Commission’s statement in the NOPR
that, in order to satisfy the integration
419 E.g.,
Allegheny, Ameren, and MidAmerican.
EEI, MidAmerican, and Nevada
Companies.
421 E.g., FMPA, NRECA, and TAPS.
422 E.g., East Texas Cooperatives, NRECA, TAPS,
and TDU Systems.
420 E.g.,
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standard, a customer ‘‘must demonstrate
that its facilities not only are integrated
with the transmission provider’s system,
but also provide additional benefits to
the transmission grid in terms of
capability and reliability and can be
relied on by the transmission provider
for the coordinated operation of the
grid.’’ 423 According to NRECA, that
statement identifies three nominal
requirements for customer facilities—
integration, benefits and ‘‘relied
upon’’—as compared to the one nominal
requirement for transmission provider
facilities—integration. This is
fundamentally inconsistent with
comparability, NRECA continues, as the
Commission seems to recognize in its
rationale for adding the comparability
requirement to new facilities.
740. NRECA further argues that the
NOPR failed to distinguish the proposed
new standard in revised section 30.9
from the Commission’s recent decision
in North East Texas Electric
Cooperative, Inc.,424 which found
transmission provider facilities
integrated on the grounds that a
showing of any degree of integration is
sufficient, rejected a ‘‘benefits’’
requirement, and did not consider a
‘‘relied upon’’ requirement. East Texas
Cooperatives argues that the
Commission’s decision in East Texas
Electric Cooperative, Inc. v. Central and
South West Services, Inc.,425 applied an
integration requirement for customer
facility credits that was different and
stricter than the standard applied to a
transmission provider’s facilities.
741. Regarding the application of the
integration component, FMPA argues
that, in order to avoid continued
discrimination, it is important that the
Commission reaffirm that ‘‘additional
benefits to the transmission grid in
terms of capability, delivery options,
and reliability’’ 426 are benefits,
regardless whether the transmission
customers or the transmission provider
(or others) benefit. Similarly, FMPA
continues, the requirement that facilities
must ‘‘be relied upon for the
coordinated operation of the grid’’ 427
423 NRECA further notes that proposed OATT
section 30.9 does not include these additional
‘‘benefits’’ and ‘‘relied upon’’ requirements. NRECA
argues that these requirements cannot be part of the
section 30.9, since regulatory preambles cannot
vary the words of the rule, citing Wyoming Outdoor
Council v. U.S. Forest Service, 165 F.3d 43, 53 (D.C.
Cir. 1999) (‘‘[L]anguage in the preamble of a
regulation is not controlling over the language of
the regulation itself’’).
424 108 FERC ¶ 61,084 (2004), reh’g denied, 111
FERC ¶ 61,189 (2005).
425 114 FERC ¶ 61,027 at P 42 (2006), appeal
docketed, No. 06–1090 (D.C. Cir. Mar. 10, 2006).
426 NOPR at P 256.
427 Id.
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must equally include operations that
serve transmission providers, customers
or others.
742. Comments on the comparability
component of the proposed credits test
for new facilities range from several
requesting that the Commission adopt a
comparability-driven analysis 428 to one
asking the Commission to eliminate the
comparability component in favor of an
integration-only analysis.429
743. Some commenters argue that
eligibility for credits should turn in the
first instance on the comparability
standard set forth in the NOPR,
otherwise the proposal does not
eliminate undue discrimination.430
NRECA argues that this requirement
does not abandon integration because
current Commission policy requires a
Transmission Provider’s facilities to be
integrated for their cost to be rolled in
to the transmission provider’s annual
transmission revenue requirement.431
APPA would apply an integration test
only if the transmission facilities for
which the customer seeks credits are
found not to be eligible under this
comparability standard.
744. TAPS states that, by eliminating
the integration test and simply
providing that customer-owned
facilities would be eligible for credits to
the extent they would be included in
the transmission provider’s rate base if
they were owned by the transmission
provider (i.e.comparability test), the
Commission would avoid litigation over
what (if anything) the separate
‘‘integration’’ requirement adds in the
proposed formulation. If the integration
terminology is retained in section 30.9,
TAPS argues that the Commission at
least should clarify that the new
integration test is truly different from
the old integration test and cannot
properly be read as limiting the
comparability requirement and that the
Commission will not follow precedents
developed in credits cases decided
under the original section 30.9.
745. To provide a comparability
baseline and eliminate the need for an
integration test, APPA recommends that
transmission providers provide a
428 E.g.,
APPA, FMPA, and NRECA.
429 Entergy.
430 E.g., APPA, East Texas Cooperatives, FMPA,
and NRECA.
431 NRECA compares North East Texas Electric
Cooperative, Inc., 108 FERC ¶ 61,084 (2004), reh’g
denied, 111 FERC ¶ 61,189 (2005) (finding
transmission provider facilities integrated and
rolling in their cost over transmission provider
objection) with Mansfield Municipal Electric
Department v. New England Power Co., 97 FERC
¶ 61,134 (2001), reh’g denied, 98 FERC ¶ 61,115
(2002) (finding transmission provider facilities not
integrated and rolling out their cost over
transmission provider objection).
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detailed inventory of the existing
facilities owned by transmission
provider and network transmission
customers that are included in their
annual transmission revenue
requirement. Network transmission
customers could use the inventory,
which would be updated annually, to
assess whether they currently own
transmission facilities comparable to
those included in the transmission
provider’s transmission rate base, or to
third-party transmission facilities for
which credits are being provided.
746. MDEA argues that proposed
section 30.9 appears contrary to
comparability principles by imposing a
standard for transmission facilities
owned by customers that is more
stringent than the one applied to the
transmission provider’s own facilities.
In MDEA’s view, the NOPR proposal is
inconsistent with prior Commission
precedent to the extent comparability is
not required in evaluating eligibility of
existing facilities owned by
transmission providers for cost
recovery.432
747. TDU Systems ask that the
Commission clarify that the
comparability prong will be aggressively
enforced. For example, TDU Systems
request that the Commission consider a
bright-line voltage criterion to address
comparability, rather than leaving it to
the transmission provider’s discretion as
to whether the facilities would be
eligible for inclusion in the transmission
provider’s annual transmission revenue
requirement.
748. Arguing against the use of the
comparability component, Entergy
contends that it could cause significant
confusion, and should in no way change
the basic requirements needed to show
integration of network customer
facilities. According to Entergy, a
network customer should be entitled to
credits only when the transmission
provider cannot meet the transmission
provider’s firm obligations without the
customer’s transmission facilities.
749. On reply, MDEA states that the
principle of comparability requires that
there be no distinction based on
ownership or between existing and new
facilities. It further asserts that Entergy
attempts to draw a distinction between
customer-owned transmission facilities
needed by the transmission provider to
meet the transmission provider’s
obligations to native load and firm
transmission customers (for which
credits should be available) and
432 MDEA cites Florida Power and Light Co., 116
FERC ¶ 61,013 (2006), and notes that the
Commission applied principles of comparability to
a transmission provider’s existing facilities.
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facilities that a network customer
decides that it needs to meet its
obligations. Entergy argues that credits
should be available only for the former
type of facility. According to MDEA,
there is no justification for the
distinction Entergy seeks to draw or the
standard it proposes to apply. Network
customers pay a full load ratio share of
the embedded costs of the transmission
grid, based on the premise that the
entire grid is available and required to
support network loads. In this regard,
there is no difference between Entergy’s
native load and network customer loads.
Transmission facilities required to meet
network customer needs by definition
are required to meet grid needs,
provided that such facilities are
integrated with the transmission
network.
750. Several commenters ask the
Commission to consider crediting
mechanisms other than the NOPR
proposal.433 For example, Entergy and
Exelon contend that new facilities
should be eligible for credit only if
determined through the regional
planning process that such new
facilities are needed, i.e., that a
measurable system capability or
reliability benefit is provided. In their
view, this will avoid litigation of cases
addressing questions of integration.
Utah Municipals argue that the
Commission should not discount the
potential evidentiary value of joint
planning in assessing eligibility for
customer credits. Taking a more
expansive view, APPA argues that
network transmission customers also
should be able to obtain credits for
transmission facilities they build
pursuant to an open and collaborative
transmission planning process in their
region or sub-region. This additional
opportunity for credits, according to
APPA, would spur participation in the
transmission planning process and
would be superior to litigating the
proper application of the integration
standard.
751. Entegra argues that the
Commission should make the crediting
policy for network customers consistent
with the Commission’s policies for
generator interconnection facilities, and
require credits to be available for
facilities that are integrated with the
transmission grid, without any showing
of additional benefits and irrespective of
whether the service in question is
interconnection service, network
service, or point-to-point service.
Entegra further argues that the
Commission should allow customers to
sell transmission credits to obtain
433 E.g.,
Entergy, Exelon, and Utah Municipals.
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transmission service elsewhere on the
transmission provider’s system. By
allowing the development of a more
liquid market for such credits, Entegra
reasons, the Commission could increase
the willingness of market participants to
fund upgrades to the transmission
system.
752. TDU Systems request that the
Commission recognize that inequities
have occurred and, if any upgrades are
required to make network customers’
facilities comparable (or comparably
integrated), the costs of such network
upgrades should be rolled into the
transmission providers’ rates.
Commission Determination
753. The Commission declines to
adopt the credits test for new facilities
proposed in the NOPR. The intent
underlying that proposal was to prevent
application of the integration test in a
manner that exclusively benefits the
transmission provider.434 After
reviewing the comments, we conclude
that the proposed test may not in fact
accomplish this objective. The test
proposed in the NOPR may not
effectively set forth the relationship of
the integration standard to the
comparability requirement. We
therefore revise the test as follows, to
more accurately reflect the
Commission’s intent as expressed in the
NOPR: A network customer shall
receive credit for transmission facilities
added subsequent to the effective date
of the Final Rule if such facilities are
integrated into the operations of the
transmission provider’s facilities;
provided however, the customer’s
transmission facilities shall be
presumed to be integrated if the
transmission facilities, if owned by the
transmission provider, would be eligible
for inclusion in the transmission
provider’s annual transmission revenue
requirement as specified in Attachment
H of the pro forma OATT.
754. Under our precedent, a
transmission provider’s facilities are
presumed to provide benefits to the
transmission grid, whereas a
transmission customer must make an
affirmative showing that its facilities
provide benefits in order to qualify for
credits.435 Under the test we adopt in
this Final Rule, a transmission customer
will be required to meet the integration
standard under pro forma OATT section
30.9 in order to receive a credit for its
434 See
NOPR at P 256.
e.g., North East Texas Electric
Cooperative, Inc., 108 FERC ¶ 61,084; East Texas
Electric Cooperative, Inc. v. Central and South West
Services, Inc., 114 FERC ¶ 61,027.
435 See
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12359
facilities.436 Because joint planning will
no longer be required in order to obtain
credits, we find that it is particularly
important in this context to require a
showing that a network customer’s
facilities provide benefits to the
transmission provider’s grid, i.e., a
transmission customer should not be
eligible for credits for facilities that the
network customer may use to provide
service for itself but that the
transmission provider does not need to
use to provide transmission service to
any other customer. However, to ensure
comparability, a presumption of
integration will be afforded to
transmission customer facilities if it is
shown that, if owned by the
transmission provider, such facilities
would be eligible for inclusion in the
transmission provider’s rate base.
c. Application of the New Test to
Existing Facilities
Comments
755. Several commenters object to the
Commission’s proposal to apply the
new comparability test in section 30.9 to
new facilities, and not to existing
facilities.437 If the Commission requires
the same integration standard for both
existing and new facilities, East Texas
Cooperatives ask us to specify which
integration standard—the pre-existing
integration standard, or the new
standard that applies the integration
standard comparably—applies and
explain the difference and the basis for
that choice. MDEA, FMPA and TAPS
argue that no distinction is warranted
between the treatment of new and
436 The integration standard, in brief, requires that
to be eligible for credits under pro forma OATT
section 30.9, the customer must demonstrate that its
facilities not only are integrated with the
transmission provider’s system, but also provide
additional benefits to the transmission grid in terms
of capability and reliability and can be relied on by
the transmission provider for the coordinated
operation of the grid. Southwest Power Pool, Inc.,
108 FERC ¶ 61,078 at P 17 (2004) (citing Order No.
888–A at 30,271), reh’g denied, 114 FERC ¶ 61,028
(2006). This policy is premised on the principle that
‘‘just as the transmission provider cannot charge the
customer for facilities not used to provide
transmission service, the customer cannot get
credits for facilities not used by the transmission
provider to provide service.’’ Id. at P 20 (citing
Order No. 888–A at 30,271 & n. 277); accord East
Texas Coop., Inc. v. Central & South West Services,
Inc., 108 FERC ¶ 61,079 at P 28 (2004), reh’g denied,
114 FERC ¶ 61,027 (2006); Southern California
Edison Co., 108 FERC ¶ 61,085 at P 10 (2004);
Northern States Power Co., 87 FERC ¶ 61,121 at
61,488 (1999); Florida Municipal Power Agency v.
Florida Power & Light Co., 74 FERC ¶ 61,006 at
61,010 (1996), reh’g denied, 96 FERC ¶ 61,130 at
61,544–45 (2001), aff’d sub nom. Florida Municipal
Power Agency v. FERC, 315 F.3d 362 (D.C. Cir.
2003).
437 E.g., APPA, FMPA, MDEA, NRECA, and
TAPS.
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existing facilities and that the same
standard should apply.
756. TAPS clarifies that it is not
suggesting that the standard be applied
retroactively to past uses, but rather
prospectively to existing facilities, with
the key consideration being when the
claim for credits is brought and not
when the facilities are constructed.
TAPS argues that it cannot be claimed
that the revised standard should apply
only to new facilities because the
comparability requirement is new. To
the contrary, TAPS contends that
comparability has been the theme and
bedrock foundation of the Commission’s
transmission open-access requirement
since its inception.
757. APPA argues that the
Commission effectively acknowledges
in the NOPR that transmission providers
have failed to plan new facilities jointly
with their transmission customers for
the last ten years under the current
section 30.9, but offers no redress for
this past discrimination.
Commission Determination
758. We conclude that the new test for
determining credits will apply only to
transmission facilities added subsequent
to the effective date of this Final Rule.
A number of customer-owned
transmission facilities have been
developed, and resulting credits
negotiated and litigated, under the prior
test which the Commission determined
to be just and reasonable at the time.438
We find no basis for revisiting the
Commission’s determinations in those
cases in this Final Rule. On a
prospective basis, however, given the
increased planning and coordination we
require in the Final Rule, we believe it
appropriate to apply the new test for
determining credits.
d. Cost of Customer Facilities
Automatically Included in Transmission
Provider Cost of Service Without a Rate
Filing
sroberts on PROD1PC70 with RULES
Comments
759. Several transmission providers
argue that, contrary to the Commission’s
proposal, credits should be added
automatically to the transmission
provider’s cost of service.439
760. MidAmerican argues that
requiring the transmission provider to
defer including the cost of the
transmission credit until its next filed
transmission rate case penalizes the
transmission provider’s shareholders
438 See East Texas Electric Cooperative v. Central
and South West Services, Inc., 114 FERC ¶ 61,027
(2006).
439 E.g., Allegheny, EEI, MidAmerican, and
Nevada Companies.
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who must unfairly bear the cost of
providing the credit until the next rate
case. If the Commission does not allow
automatic rate recovery of the
incremental cost of credits,
MidAmerican continues, the
Commission should clarify that the
customer will not be allowed
transmission facility credits until the
rate adjustments are filed and accepted
by the Commission. MidAmerican
explains that such filings would
examine only the new revenue
requirements to be added and should
not require a general rate case for the
transmission provider’s entire revenue
requirement. Nevada Companies
likewise argues that credits should not
be granted to network customers if the
recovery of those credits is not provided
for in the revenue requirement.
761. TAPS agrees with the
Commission’s conclusion that it would
not be appropriate in this rulemaking to
allow transmission providers to
automatically add costs of credits to
their cost of service, and that such costs
should continue to be evaluated as part
of a regular transmission rate case (or
recovered through an approved formula
rate). APPA expresses concern that
transmission providers may attempt to
use the Commission’s decision not to
allow them to add the costs of credits
associated with customer-owned
transmission facilities automatically to
their costs of service as a pretext for not
granting such credits in the first
instance (at least until they decide to
file a new rate case). APPA continues
that a transmission provider’s decision
not to exercise the option to file under
FPA section 205 a new rate case or an
automatic adjustment clause should not
serve as a reason to allow it to decline
to provide credits.
762. EEI explains that the customary
basis for not allowing single-issue rate
adjustments for new transmission
facilities is that while one aspect of the
transmission provider’s costs may have
increased, others may have decreased or
load may have increased. This is not the
case with respect to the inclusion of the
transmission costs related to customerowned facilities, EEI continues, since
the existence of customer-owned
facilities does not have any impact on
the transmission provider’s own cost of
service. EEI concludes that a
transmission provider should not be
forced into what is essentially rejustifying its transmission cost of service
simply because a customer receives a
credit for the integration of its own
facilities.
763. Some commenters also address
the option currently open to
transmission providers to add an
PO 00000
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Fmt 4701
Sfmt 4700
automatic adjustment clause to their
rates through a rate filing with the
Commission.440 EEI argues that if the
concept of an automatic adjustment
clause is just and reasonable for one
transmission provider, it is equally just
and reasonable for all transmission
providers, and there is no need to adopt
a case-by-case approach. EEI further
requests that the Commission clarify
that its policy is to accept rate
adjustments that incorporate the costs
that transmission providers incur to
provide credits related to customerowned facilities, provided that the rate
adjustment methodology is just and
reasonable. MidAmerican contends that
the revenue requirement of the
transmission provider and those of
transmission customers should not be
co-mingled, rather, consistent with
Commission precedent, the burden is on
the transmission-owning customer to
demonstrate to the Commission that its
cost of service and revenue requirement
used to establish the amount of the
credit are just and reasonable before it
can receive credits. As for
nonjurisdictional entities, MidAmerican
explains that they may file for a
declaratory ruling from the Commission
regarding their revenue requirement.
764. Allegheny argues that if the
Commission continues to deny
transmission providers an automatic
adjustment clause for these credits, it
should, at a minimum, assure
transmission providers that
transmission credits will be recognized
as a cost of service in FPA section 205
rate proceedings.
765. Entergy argues that the
Commission should recognize that any
filed agreement providing for payments
of credits would be subject to the filedrate doctrine.
Commission Determination
766. We are not persuaded to
generically allow automatic recovery of
the costs of credits associated with
integrated transmission facilities to the
transmission provider’s cost of service.
These costs typically are considered and
evaluated as part of a regular cost of
service review process. Automatic
recovery of the costs of credits would be
contrary to our long-standing policy
concerning single-issue rate
adjustments, a policy we decline to
modify here.441 Nevertheless,
transmission providers continue to have
the option to propose an automatic
adjustment clause in their rates under
440 E.g., Allegheny, EEI, Exelon, and
MidAmerican.
441 See, e.g., City of Westerville, Ohio v. Columbus
Southern Power Co., 111 FERC ¶ 61,307 (2005).
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FPA section 205 to address the time lag
between incurring costs associated with
credits and the transmission provider’s
next rate case.
767. Contrary to EEI’s assertions,
customer credits do not warrant an
exception to the Commission’s general
policy regarding single-issue rate
adjustments. EEI argues that customer
credits should be treated differently
because the existence of customer
owned facilities, in EEI’s view, does not
have any impact on the transmission
providers’ own cost of service. Even if
true, this fact would not obviate the
Commission’s policy. Regardless of
whether the customer credit is deemed
to impact the transmission provider’s
own cost of service, the costs it imposes
may be offset by cost decreases in other
areas, by load growth, or both. Allowing
single-issue rate adjustments would
enable a utility to increase the total rate
charged by focusing solely on a single
cost element, while avoiding scrutiny of
all other determinants of the rate. The
Commission has an obligation to ensure
the justness and reasonableness of the
total rate and it would be improper to
allow a utility to raise rates by
selectively focusing only on particular
elements of its costs, while avoiding
scrutiny of other rate inputs. The
Commission has refused to allow such
rate treatment except in the most
limited of circumstances and we find no
basis for deviating from that policy in
this context. As explained above, a
transmission provider that wishes to
add an automatic adjustment clause to
its rates may seek Commission approval
for its methodology in a filing submitted
under FPA section 205.
sroberts on PROD1PC70 with RULES
e. Point-to-Point Customers Not Eligible
for Credits on Generic Basis
Comments
768. Several commenters support the
Commission proposal to not make
credits generically available to point-topoint customers that own transmission
facilities.442 APPA argues that if the
frequency of cases seeking credits for
facilities owned by point-to-point
customers is high, then the Commission
should reconsider its decision to use a
case-by-case approach.
769. Some commenters encourage the
Commission to clarify that point-topoint transmission customers that pay
for upgrades should be compensated if
such upgrades benefit the system.443
PGP argues that customers be given
credits if they meet the same conditions
as network customers who would
442 E.g., APPA, Bonneville, EEI, Exelon,
FirstEnergy, Nevada Companies, and TAPS.
443 E.g., FirstEnergy, Seattle, and Suez Energy NA.
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qualify. Additionally, Entegra contends
that denying credits for upgrades
funded by point-to-point customers
would overlook the Commission’s past
warnings that a customer funding any
new facilities integrated with the grid
should be entitled to credits because a
transmission system ‘‘cannot be
dismembered’’ or examined
piecemeal.444
Commission Determination
770. The Commission adopts the
NOPR proposal not to make credits
generically available for point-to-point
customers that own transmission
facilities. As the Commission explained
in the NOPR, a network customer takes
a usage-based service which integrates
its resources and loads and pays on the
basis of its total load on an ongoing
basis. The transmission provider
includes the network customer’s
resources and loads in its long-term
planning horizon and the two parties
coordinate operations of their facilities
through a network operating agreement.
In this way, network service is
comparable to the service that the
transmission provider uses to serve its
own retail native load, and credits for
certain integrated network facilities are
appropriate. The point-to-point
customer, however, does not purchase
integration service, nor does it sign a
network operating agreement with the
transmission provider. Because of the
inherent differences between point-topoint and network service, we therefore
decline to require that transmission
providers make credits generically
available to point-to-point customers
that own transmission facilities. If a
particular facility owned by a point-topoint customer meets all the criteria for
credits, we will continue to address
such situations on a fact-specific, caseby-case basis consistent with the
Commission’s statement in Order No.
888.445
12361
cannot be integrated into CAISO’s
operations unless they are under
CAISO’s operational control, consistent
with the Commission’s prior rulings.
772. In Xcel’s view, an RTO has no
incentive to refuse to jointly plan to
avoid paying a credit and there is thus
good cause to allow an RTO to deviate
from the language in the pro forma
OATT relating to joint planning of new
facilities in order to be considered for a
facility credit. Xcel and International
Transmission argue that RTOs should be
allowed to incorporate network
customer-owned facilities into RTO
rates in the same manner as if they were
constructed by a transmission owner,
while ensuring against double recovery
of both revenue requirements and
network credits.
Commission Determination
773. The Commission concludes that
it would not be appropriate at this time
to generically exempt all ISOs and RTOs
from the Final Rule requirements
regarding credits for network
transmission customers. We will
address issues relating to network
transmission customers credits in the
RTO and ISO context in orders
addressing OATT reform compliance
filings submitted by each RTO and ISO.
The Commission determined previously
that the existing tariffs of certain RTOs
and ISOs provide opportunities for
transmission customers to receive credit
or the equivalent (e.g., Transmission
Congestion Contracts, Firm
Transmission Rights or Auction
Revenue Rights) for building facilities or
upgrades that are consistent with or
superior to Order No. 888
requirements.447 Each RTO and ISO will
have the opportunity to show on
compliance that this continues to be the
case given the reforms adopted in this
Final Rule.
f. RTO and ISO Issues
Comments
771. Several RTOs or ISOs assert that
they should not be required to comply
with the crediting provisions because
their respective planning processes and
procedures are superior to or obviate the
need for those set forth in the NOPR.446
CAISO states that it does not oppose the
Commission’s proposal, provided that
the Commission confirms that facilities
444 Citing Nevada Power Co., 101 FERC ¶ 61,036
at P 8 (2002).
445 Order No. 888 at 31,742; Order No. 888-A at
30,271.
446 E.g., Indicated New York Transmission
Owners, ISO New England, PJM, and SPP.
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447 For example, NYISO’s tariff provides that a
facilities study will contain a non-binding estimate
as to the feasible Transmission Congestion
Contracts (TCCs) resulting from the construction of
new facilities. There, upon completion of the
transmission upgrade and the first subsequent
centralized TCC auction, the NYISO will determine
the incremental TCCs associated with the upgrade.
See section 19.4 ‘‘Facilities Study Procedures’’ of
NYISO’s tariff. Similarly, PJM’s tariff provides that
an interconnection customer that undertakes
responsibility for constructing or completing
network upgrades and/or local upgrades to
accommodate its interconnection request will be
entitled to receive the incremental Auction Revenue
Rights associated with such facilities and upgrades
subject to conditions. See section 46.1 ‘‘Right of
Interconnection Customer to Incremental Auction
Revenue Rights’’ of PJM’s tariff.
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Other issues
sroberts on PROD1PC70 with RULES
Comments
774. East Texas Cooperatives argue
that the Commission should clarify that
a network customer is entitled to
transmission credits for its own
transmission facilities and the facilities
of member utilities for which the
network customer arranges and pays for
network transmission services. East
Texas Cooperatives explain that a recent
Commission decision 448 allows
transmission credits only for facilities
owned by the generation and
transmission cooperative (G&T) and not
for its individual members, which in its
view is contrary to past Commission
precedent.
775. FMPA asks that the Commission
affirmatively state that it will exercise
its jurisdiction to ensure that public
power entities are compensated for
transmission investment (including
joint transmission projects) in the event
of dispute with jurisdictional
transmission providers. FMPA explains
that the proposed revisions to section
30.9 may be insufficient to address all
problems that may arise, especially in
regions without an RTO or an existing
compensation method. NRECA asks the
Commission to prohibit RTOs and ISOs
from using a non-public utility’s
transmission facilities without
compensating the entity simply because
it has not joined the RTO or ISO.
NRECA argues that comparable
treatment requires compensation for use
of a transmission owner’s facilities,
whether the owner is subject to
Commission jurisdiction or not, and the
Commission should not consider a
transmission tariff to be just and
reasonable if it allows unlawful trespass
and conversion.
776. TAPS asks the Commission to
include language in section 30.9 of the
pro forma OATT that affirmatively
states customers’ eligibility for rate
incentives for new facilities under
recently established Commission policy.
TAPS further requests that the
Commission guard against a
transmission provider blocking such
incentive based credits by refusing to
engage in joint development of
transmission projects with its
customers.
Commission Determination
777. The Commission finds that there
is not enough evidence on the record to
make a generic determination on these
448 East Texas Electric Cooperative, Inc. v. Central
and Southwest Services, Inc., 108 FERC ¶ 61,077 at
P 21–23 (2004), reh’g denied, 114 FERC ¶ 61,027
at P 43–44 (2006), appeal docketed, No. 06–1090
(D.C. Cir. Mar. 10, 2006)
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issues and, instead, will address them
on a case-by-case basis in response to
appropriate filings under FPA sections
205 and 206. With regard to incentives
for new facilities, the Commission has
already addressed incentives for
transmission infrastructure investment
in Order No. 679.449 There the
Commission identified specific
incentives that it will allow when
justified in the context of individual
proceedings. With regard to FMPA’s
concerns regarding potential disputes
over compensation for transmission
investment by non-public utilities, we
note that section 12 of the existing pro
forma OATT contains dispute
resolution procedures. This Final Rule
also requires transmission providers to
propose a dispute resolution process as
part of the coordinated planning
process. Additionally, the Commission’s
Dispute Resolution Service is available
to assist in developing a dispute
resolution process, as well as the
Commission via a formal complaint
filed pursuant to section 206 of the FPA.
4. Capacity Reassignment
778. In Order No. 888, the
Commission concluded that a
transmission provider’s pro forma
OATT must explicitly permit the
voluntary reassignment of all or part of
a holder’s firm point-to-point capacity
rights to any eligible customer.450 With
respect to the rate for capacity
reassignment, the Commission
concluded it could not permit
reassignments at market-based rates
because it was unable to determine that
the market for reassigned capacity was
sufficiently competitive so that
assignors would not be able to exert
market power. Instead, the Commission
capped the rate at the highest of (1) The
original transmission rate charged to the
purchaser (assignor), (2) the
transmission provider’s maximum
stated firm transmission rate in effect at
the time of the reassignment, or (3) the
assignor’s own opportunity costs
capped at the cost of expansion (price
cap). The Commission further explained
that opportunity cost pricing had been
permitted at ‘‘the higher of embedded
costs or legitimate and verifiable
opportunity costs, but not the sum of
the two (i.e., ‘or’ pricing is permitted;
‘and’ pricing is not).’’ 451 In Order No.
888–A, the Commission explained that
449 Promoting Transmission Investment through
Pricing Reform, Order No. 679, 71 FR 43294 (Jul.
31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006), order
on reh’g, Order No. 679–A, 72 FR 1152 (Jan. 10,
2007), FERC Stats. & Regs. ¶ 31,236 (2007).
450 See Order No. 888 at 31,696; pro forma OATT
section 23.1.
451 Id. at 31,740.
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opportunity costs for capacity
reassigned by a customer should be
measured in a manner analogous to that
used to measure the transmission
provider’s opportunity cost.452
NOPR Proposal
779. In the NOPR, the Commission
noted that capacity reassignment does
not appear to have developed into a
competitive alternative to primary
capacity since the issuance of Order No.
888. To facilitate development of this
market, the Commission proposed to
remove the price cap on capacity
reassignment and allow negotiated rates
for transmission capacity reassigned by
transmission customers. The
Commission explained that, because the
price cap appears to have reduced
customers’ transmission options,
removal of the cap may be warranted
without a market-by-market analysis.
Due to market power concerns,
however, the Commission proposed to
retain the price cap for capacity
reassigned by the transmission
provider’s merchant function or its
affiliates.
780. The Commission proposed to
monitor the market for reassigned
capacity by requiring regular OASIS
postings and quarterly reports from
transmission providers using
information submitted by reassigning
customers. First, the Commission
proposed retaining the existing posting
and filing requirements for reassigned
capacity transactions to ensure that
capacity is equally available to all
customers and to protect against undue
discrimination and the potential
exercise of market power.453 Second,
the Commission asked several questions
regarding OASIS postings and the data
that should be required in quarterly
reports related to capacity
reassignments: (1) What information
should be required in the quarterly
reports and OASIS postings, i.e.,
information about the capacity released,
the original rate paid for that capacity,
the price charged to the assignee for the
capacity, and the term of the
assignment; (2) whether other
information was necessary for
operational and reliability purposes; (3)
whether additional reports by assignors
to the transmission provider are
necessary and, if so, what information
should be reported by assignors; (4)
452 Order
No. 888–A at 30,224.
existing OASIS posting requirements for
reassigned capacity already require, if selling on
OASIS, for sellers to include data elements such as
the path name, point of receipt, point of delivery,
source, sink, capacity requested, capacity granted,
start time, stop time, and offer price. See 18 CFR
37.6(c)(5).
453 The
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should the Commission establish a new
quarterly reporting process with a new
form, or use the existing Electric
Quarterly Report procedures; and (5)
how frequently should OASIS postings
be made.
Comments
sroberts on PROD1PC70 with RULES
Lifting the Price Cap for All
Transmission Customers
781. Some commenters support
eliminating the price cap for
reassignment of transmission capacity
in the secondary market.454 For
example, EPSA states that the
Commission is correct to recognize that
negotiated rates are dynamic and
provide a market discipline on the price
for reassigned capacity. Entegra argues
that the Commission’s removal of rate
caps on releases of natural gas pipeline
capacity increased available peak
capacity and facilitated the movement
of capacity into the hands of those that
value it most highly, proving that an
uncapped capacity release market can
be both competitive and result in just
and reasonable rates for customers.455
Exelon supports eliminating the price
cap, but asserts that, since the
transmission customer is seeking to
reassign the capacity, it is likely the
capacity is not useful in gaining access
to load and therefore is not very
valuable. BP Energy contends that
transparent competition between the
transmission provider (marketing
primary and subscribed but unutilized
capacity) and transmission customers,
with monitoring by the Commission and
prospective capacity purchasers, will
moderate if not eliminate the potential
exercise of market power and encourage
the release of capacity that is not
otherwise used or useful. As a result, BP
Energy urges the Commission to require
transmission providers to facilitate a
competitive capacity reassignment
process, similar to that used for capacity
release on natural gas pipelines.
782. Some commenters support the
proposal to retain the price cap for
transmission providers and their
affiliates.456 Seattle states that the
Commission is correct to continue to
cap prices for the transmission provider
since the transmission provider is a
regulated monopoly. In its reply,
Entegra states that the Commission has
found that having a pro forma OATT
mitigates but does not eliminate a
454 E.g., Allegheny, AWEA, Constellation, EEI,
Entegra, EPSA, Exelon, Morgan Stanley, PPL,
Seattle, Suez Energy NA, and TranServ.
455 Citing Natural Gas Pipeline Negotiated Rate
Policies and Practices, 114 FERC ¶ 61,034 (2006)
(Brownell, Comm’r concurring).
456 E.g., APPA, AWEA, NRECA, Seattle, TAPS,
and TDU Systems.
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12363
transmission provider’s ability to
leverage its monopoly power in
transmission into market power in
generation markets.457 Entegra further
contends that Southern, Entergy, and
other transmission providers have
monopoly power in transmission
markets in their service territories and
without a cap would exploit that market
power in the secondary market.
Moreover, Entegra argues that allowing
transmission providers and their
affiliates to charge market-based rates
for transmission capacity in the primary
or secondary market would exacerbate
the skewed incentives that already
operate to discourage construction of
much needed transmission facilities in
many markets.
783. Many commenters contend that
lifting the price cap for reassignment of
transmission capacity only for
unaffiliated transmission customers
would be unreasonable.458 For example,
Entergy argues that for the wholesale
markets to work all wholesale market
participants, including the transmission
provider’s affiliated marketers, must be
treated comparably under the pro forma
OATT. EEI contends that lifting the
price cap can result in a more robust
secondary market for transmission
capacity and will reduce any risks that
transmission customers may associate
with being required to purchase
transmission service for five-year terms
in order to obtain rollover-rights. In
addition, Manitoba Hydro asserts that
changing the current one-year minimum
term creates additional risks for
transmission customers and therefore
having the ability to re-sell the
transmission capacity at market-based
rates would assist transmission
customers to better manage the financial
risks involved with holding longer term
contracts.
784. Some commenters support lifting
the price cap for affiliates if caps are
removed for non-affiliates, but are only
generally supportive of lifting the price
cap.459 If the Commission does lift the
price cap, Southern argues that it should
also lift the price caps for the
transmission provider and its affiliates
as well in order to counter efforts to
corner the market and other related
unforeseen consequences. MidAmerican
agrees, asking the Commission to retain
the cap for all transmission customers if
the transmission provider and its
affiliates are not allowed to resell
capacity at market-based rates.
785. Several commenters argue that
the Commission’s justification for
eliminating the price cap—namely,
reducing the ability of non-affiliated
customers to exercise market power in
the secondary market through
competition among releasing customers,
monitoring the market via quarterly
reports, and continuing rate regulation
of primary capacity—applies to energy
and marketing affiliates as well.460 First,
several commenters argue that the
Standards of Conduct and existing pro
forma OATT rules ensure that
transmission provider affiliates have no
more ability to obtain information about
the transmission system or to reserve
point-to-point transmission capacity
than unaffiliated customers. 461
Entergy contends that, although the
Commission correctly concludes
elsewhere in the NOPR that functional
unbundling and Standards of Conduct
requirements, if properly enforced are
sufficient to address affiliate abuse
concerns, the Commission seems to
assume that those same protections
cannot be effective where the
reassignment of transmission capacity is
concerned.
786. Second, some commenters
question the Commission’s assertion
that permitting transmission provider’s
energy and marketing affiliates to resell
or reassign transmission capacity would
give them the ability to favor their own
generation.462 For example, EEI
contends that transmission providers
have no control over the reassignment
process, and transmission customers
have complete freedom to reassign
transmission capacity to any customer
they choose. Entergy points out that
under Order No. 888 the assignor of
capacity may deal directly with an
assignee and without involvement of the
transmission provider.463
787. Third, some commenters
disagree with the Commission’s
statement that lifting the price cap for
affiliates may dampen transmission
investment.464 These same commenters
argue that there is no relationship
between the transmission provider’s
obligation to build transmission
457 Citing Public Service Electric & Gas Company,
78 FERC ¶ 61,119 at 61,455 (1997) (granting marketbased rate authority based in part on the adequate
‘‘mitigation of market power’’ as evidenced by a pro
forma OATT).
458 E.g., Community Power Alliance, EEI, Entergy,
FirstEnergy, Imperial, Manitoba Hydro,
MidAmerican, Progress Energy, and Salt River.
459 E.g., MidAmerican, PNM–TNMP and South
Carolina E&G.
460 E.g., EEI, Entergy, MidAmerican, PNM–TNMP,
Progress Energy, Southern, and South Carolina
E&G.
461 E.g., Community Power Alliance, Entergy,
Imperial, Manitoba Hydro, Salt River, South
Carolina E&G, and Southern.
462 E.g., EEI, Entergy, MidAmerican, and Progress
Energy.
463 See Order No. 888 at 31,697.
464 E.g., EEI, MidAmerican, and Progress Energy.
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facilities to accommodate third party
requests for transmission service and
the ability of marketing and energy
affiliates to resell unused transmission
capacity at market-based rates. For
example, Progress Energy and others
contend that the transmission provider
is obligated under the pro forma OATT
to construct transmission facilities to
meet all requests for transmission
service.465 Progress Energy and EEI
contend that the transmission customer
will decide to purchase secondary
market transmission capacity if it meets
the reasonable needs of customers so
long as the capacity is priced below the
higher of the embedded cost of
transmission service or the cost of
expansion. EEI argues that the customer
can require the transmission provider to
construct additional capacity to
accommodate the customer’s request for
service if secondary market service—
whether offered by the transmission
provider’s marketing and energy
affiliates or by a third party customer—
is priced above the cost of expansion. In
such situations, EEI and Progress Energy
contend that the cost of expansion
serves as a cap on the price at which
both third party customers and the
transmission provider’s marketing and
energy affiliates can resell transmission
capacity. Moreover, Entergy argues that
this is the same justification that the
Commission relies upon to conclude
that transmission customers would not
hoard secondary capacity, and it is
arbitrary for the Commission to ignore
that principle in concluding that a
transmission provider would hoard
capacity.
788. Additionally, some commenters
argue that lifting the price cap for
affiliates will encourage transmission
investment.466 NorthWestern contends
that allowing transmission providers to
collect more than their ceiling price
when the market is willing to pay a
higher price could further the
Commission’s goal of encouraging
transmission investment to maintain
reliability and keep pace with load
growth. NorthWestern suggests that the
Commission could place restrictions on
the proceeds in excess of the ceiling
price such that, within some specified
period, the dollars must be reinvested
into transmission facilities or be
refunded back to customers.
789. Several commenters contend that
lifting the price cap only for nonaffiliates could dampen participation in
the secondary market and place
affiliates at a competitive
465 E.g.,
466 E.g.,
EEI, Entergy and MidAmerican.
Entegra and NorthWestern.
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disadvantage.467 Community Power
Alliance argues it is unfair for the
Commission to now say that their
separated marketing affiliates, which
have abided by Commission rules like
any other market participant, cannot
now compete on an equal footing with
other participants in the secondary
market for transmission capacity. Rather
than prohibit transmission providers’
affiliates from reselling capacity,
Manitoba Hydro suggests that a more
equitable approach would be for the
Commission to lift the price cap for all
resold transmission capacity, except for
transmission capacity administered by
an affiliate’s transmission provider.
790. To the extent the Commission
adopts the proposed restriction on
affiliate reassignments, MidAmerican
seeks guidance on whether the
transmission provider is expected to
assure that the assignee is a valid
eligible customer under the pro forma
OATT. Similarly, Southern encourages
the Commission to carefully identify
and evaluate the possible adverse effects
of lifting any reassignment price caps.
Southern asserts that such effects could
include expanded involvement and
influence by financial players driven
exclusively by profit motives and who
may not be subject to Commission
regulation.
791. Several commenters contend that
the Commission should retain the price
cap for the reassignment of transmission
capacity for all customers, not just
affiliates of the transmission
provider.468 APPA argues that allowing
the resale of such a scarce and valuable
service to those who value the capacity
more highly is a recipe for undue
discrimination and unjust and
unreasonable transmission rates, at the
expense of end-use customers. While
NRECA opposes the Commission
proposal to remove the price cap,
NRECA would support the proposal to
retain the price caps for affiliates.
Similarly, TAPS supports the decision
not to lift the price caps for affiliates;
however, TAPS urges the Commission
to rethink the NOPR’s proposal to
otherwise lift the price cap for nonaffiliates.
792. Several commenters argue that
lifting the cap for any transmission
customers would encourage the exercise
of market power, including hoarding,
and discourage transmission
467 E.g., Community Power Alliance, EEI,
FirstEnergy, Imperial, Northwest IOUs, Southern,
and TVA.
468 E.g., Alcoa, APPA, International Transmission,
Nevada Companies, NRECA, PJM, Public Power
Council, TAPS, and WAPA.
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investment.469 If removal of the cap
were effective in making reassignment
more profitable, TAPS contends it
would encourage hoarding of capacity
on key paths that would run afoul of the
directive in FPA section 217(b)(4) to
ensure the ability of LSEs to secure
long-term rights for their long-term
power supply arrangements. Northwest
IOUs argue that lifting the price cap
would encourage non-affiliated
transmission customers to buy
transmission capacity at cost and resell
it at market, in an effort to reduce the
amount of transmission capacity
available for resource development and
other long-term uses. PJM argues that
the final rule should include a
requirement that appropriate hoarding
mitigation procedures be implemented
should the price cap be removed. APPA
argues that, if no transmission capacity
is available in the short run from the
transmission provider, and an LSE
needs additional capacity to serve load
within the next day or week, the fact
that the transmission provider could
build capacity in future years at an
incremental rate has little if any bearing
on the price that LSE is willing to pay
for the next day, week, or month to avert
a looming supply problem. TVA asserts
that transportation prices rose
drastically during periods of high
demand or constraint after the price cap
for resale of gas transmission capacity
was removed in Order No. 637 for
everyone except pipelines and their
affiliates. TVA states that this benefited
entities that could afford to hold
capacity, but harmed those that had to
buy additional capacity on a short-term
basis.
793. Alcoa and Nevada Companies
argue that there is a significant potential
for abuse in connection with the
removal of the cap, particularly in load
pockets. Alcoa argues that it is not clear
at this point that there are sufficient
safeguards in place to prevent and
monitor the exercise of market power,
something that must be assured before
the cap is lifted on transmission
capacity resale. Nevada Companies
contend the proposal to remove the cap
may actually reduce utilization of the
grid, contrary to its intended purpose.
For example, Nevada Companies state
that transmission customers who have
locked up capacity in constrained
markets will likely wait to the very last
minute to make that capacity available
in order to drive up the price, which
will often result in the capacity not
being utilized if transactions cannot
occur quickly enough. Some
469 E.g., APPA, Nevada Companies, Northwest
IOUs, NRECA, PJM, TAPS, and WAPA.
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commenters contend that, like LMP in
organized markets, allowing price
signals via lifting the cap may not
encourage transmission investment, but
rather create entrenched interests that
profit from the existence of congestion
and oppose efforts to eliminate such
congestion through transmission
expansion.470 If transmission providers
are forced to purchase capacity at higher
prices on the secondary market,
Imperial argues that their native load
customers be harmed by such higher
prices, which may in turn hamper
transmission expansion contrary to the
Commission’s stated goals for promoting
transmission investment.
794. In addition, some commenters
are skeptical of the Commission’s
assertion that existing market
mechanisms are a sufficient deterrent to
anticompetitive behavior.471 WAPA and
TAPS argue that, while eliminating the
price cap might increase customers’
transmission options, the Commission
still needs to conduct case-by-case
market power analyses prior to lifting
the cap.472 As a result, WAPA argues, it
is critical for the Commission to identify
and aggressively mitigate all
transmission market power on an ex
ante basis, rather than utilizing an ex
post monitoring scheme as proposed in
the NOPR. If the Commission lifts the
price cap, certain commenters argue that
the Commission should establish
competitive bidding transaction
standards.473 For example, Seattle
asserts that a standards organization
such as NAESB will need to establish
bid/ask transaction standards and
reporting formats and the Commission
must periodically validate the
assumption that the secondary market is
workably competitive.
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Application of the Price Cap to
Members of ISOs/RTOs
795. Some commenters request
clarification that, if the Commission
retains the price cap for capacity
reassigned by affiliates, that it not apply
to entities that have turned over control
and operation of their transmission
facilities to an RTO, ISO or independent
entities.474 For example, Constellation
470 E.g., APPA, International Transmission,
NRECA, Public Power Council, and Seattle.
471 E.g., Alcoa, APPA, Bonneville, TAPS, and
WAPA.
472 Citing Farmers Union Cent. Exch., Inc. v.
FERC, 734 F.2d 1486, 1508–10 (D.C. Cir. 1984)
(concluding that ‘‘undocumented reliance on
market forces is insufficient to satisfy the
Commission’s regulatory responsibilities.’’);
California ex. Rel. Lockyer v. FERC, 383 F.3d 1006,
1013 (9th Cir. 2004).
473 E.g., BP Energy, Seattle, and TranServ.
474 E.g., Ameren, Constellation, SPP, and
TranServ. ISO New England and PJM argue that, as
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requests that the Commission clarify
that the revised pro forma OATT does
not impose the cap on affiliates of
transmission owners that have turned
their transmission facilities over to an
RTO/ISO when they reassign
transmission capacity on facilities
operated by the RTO/ISO. While MISO
takes no position on whether the
Commission should retain its cap for
stand-alone transmission providers and
their affiliated customers, it argues that
the cap makes no sense in the context
of capacity reassignments administered
by RTOs and ISOs. MISO observes that
the NOPR cites affiliate preference and
market power concerns as the basis for
retaining the cap on reassignments by
transmission providers and their
affiliated customers, which MISO argues
are not applicable in the RTO/ISO
context. Further, MISO argues that the
ownership of transmission assets in an
RTO/ISO is divorced from the provision
of transmission service, and RTO
transmission owners are transmission
customers no different from any other
customer class.
796. On the contrary, APPA notes that
the issue is whether the transmission
customer holding transmission rights
over a constrained path has the ability
to exercise market power and charge
unjust and unreasonable rates if the cap
is lifted. APPA argues that the issue is
the same in both RTO and non-RTO
regions. In APPA’s view, whether the
public utility transmission provider has
joined an RTO, does not affect the
ability of its merchant affiliate to extract
unjust and reasonable rents for the
resale of scarce transmission rights.
Alternative Price Cap Proposals
797. Some commenters propose
alternatives to negotiated pricing of
transmission capacity in the secondary
market.475 While APPA supports
retaining the current rate cap, it
contends that firm point-to-point
customers should be allowed to collect
demonstrable out-of-pocket costs in
addition to the maximum capped rate.
Alcoa suggests that the Commission
could stimulate the secondary market
for transmission capacity by increasing
the cap and allowing parties to charge
a percentage over the original price
paid. Seattle contends that the existing
Commission policy could be
incrementally modified to permit
recovery of remarketing costs and
recognize that, for many customers, the
transmission right is held at a much
providers of transmission service, they have no
affiliates and likewise are not bound by the
Commission’s reassignment proposal.
475 E.g., Alcoa, APPA, Manitoba Hydro, PGP,
Sacramento, and Seattle.
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12365
higher per unit cost than the primary
rate stated in the transmission
provider’s pro forma OATT (due in part
to the fact that a customer may not use
all of the capacity for which it has
contracted).
798. Sacramento proposes that prices
for released capacity be capped at the
amortized and rate-based cost of a
transmission upgrade. Seattle states that
costly redirect processes, including
system impact studies, may be needed
to create a reassignment product that
has value to other customers, given that
the point of receipt, point of delivery or
both typically change in a reassignment.
While the current pro forma OATT
pricing model differentiates
transmission rates based on term and
time of day (monthly, weekly, daily,
hourly), Seattle asserts that seasonal
variations in the value of transmission
rights offered for short-term
reassignment are also worthy of
consideration, especially in a region like
the Northwest, where power production
varies seasonally.
799. MISO states that it believes the
Commission should further strengthen
its pro-competitive policy by permitting
RTO/ISO transmission providers to offer
firm point-to-point transmission service
for drive-out/drive-through transactions
at market-based rates, including
‘‘rollover’’ transactions. MISO states that
the principles for allocating firm
capacity on such interfaces should be
the same as for reassigning capacity
within an RTO: i.e., permitting
customers that value the capacity more
highly to benefit from it. MISO asserts
that allowing market participants to
compete based strictly on price on
external interfaces would resolve many
inefficiencies stemming from the
cumbersome queue administration
procedures currently used on such
facilities. MISO states that the final rule
should encourage RTOs and ISOs to
introduce such competitive practices in
their footprints.
800. PGP proposes two alternative
approaches. First, PGP proposes that the
Commission could wait until a regional
approach for pricing reassignments is
developed in those areas of the country
that still rely on reassignments of pointto-point capacity to create a secondary
market in transmission service. Second,
PGP proposes that any decision to
remove the price cap could be made on
a case-by-case basis after a filing by a
point-to-point customer at the
Commission, in which the applicant
must meet standards developed by the
Commission that demonstrate the lack
of market power in relevant
transmission or generator markets.
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801. South Carolina E&G requests that
the Commission clarify how the cap is
calculated if the Commission chooses to
retain the price cap. International
Transmission asserts that the
Commission should lift the price cap,
on an experimental basis, similar to the
approach followed in the natural gas
industry. Similarly, WAPA recommends
that the Commission either retain the
price cap or institute a separate
rulemaking proceeding for the purpose
of establishing detailed market analysis
criteria for eliminating the price cap for
specific transmission segments or paths.
Posting and Filing Requirements
802. Some commenters support the
proposal to require transmission
providers to submit quarterly reports
and make OASIS postings regarding
reassignments of transmission
capacity.476 Bonneville asserts that, at a
minimum, transmission customers
should be required to provide a
downloadable file to the transmission
provider for posting on the transmission
provider’s OASIS that identifies the
assignee, the amount of capacity
assigned or transferred, the date of the
offer of assignment, and the rate and
duration of the assignment. Other
commenters argue that transmission
customers should be given greater
reporting responsibility.477 Southern
contends that transmission providers
should not be burdened with submitting
quarterly reports and making OASIS
postings based on assignment
information provided to them by other
assignors/assignees. Rather, Southern
and EEI argue that assignment
information should be filed by the
respective assignors and assignees in
connection with their Electric Quarterly
Report filings and not by the
transmission provider. PNM–TNMP
contend that the Commission should
prescribe specific reporting obligations
and associated deadlines to the
assignors and reporting obligations
should also include appropriate
consequences for non-compliance on
the part of the assignor. Nevada
Companies ask that a system be put in
place to charge relevant transmission
customers for the additional reporting if
the transmission provider is required to
do the reporting, either on the OASIS or
through some other mechanism.
803. Some commenters argue that
more information should be posted on
OASIS beyond what was proposed in
the NOPR.478 EEI asserts that the details
Bonneville, FirstEnergy, and PJM.
EEI, Entergy, Nevada Companies, PNM–
TNMP, South Carolina E&G, Southern, and TVA.
478 E.g., EEI, PJM, and Seattle.
the transmission customers should
report on the OASIS and in the
quarterly reports include: The identity
of the primary market seller; the
identities of the secondary market seller
and purchaser; the points of receipt and
delivery; the term of reassigned service;
the quantity of the reassigned service;
and the charge for the reassignment,
expressed in dollars per MW-month,
week, day, or hour as appropriate. Other
commenters contend that the existing
quarterly report is appropriate and a
new report should not be instituted.479
TranServ argues that the existing OASIS
posting template query and audit
functions are sufficient and no new
obligations should be required. As to
frequency of OASIS postings, Seattle
suggests seven days after a transaction
and NorthWestern proposes that the
OASIS postings be no more frequent
than monthly.
804. Other commenters raise
confidentiality concerns or state that
business practice standards for capacity
reassignment posting requirements
would be required.480 Because these
negotiated rates will be market
sensitive, Allegheny asks the
Commission not to require reporting
and OASIS posting until the term of the
reassignment has expired. NAESB states
that capacity reassignment, including
removing the price cap and allowing
negotiated rates, could require posting
standards for OASIS sites and the
addition of significant functions to
support such postings.
805. NAESB states that capacity
reassignment including removing the
price cap and allowing negotiated rates
could require posting standards for the
OASIS site, and significant functions
added to support such postings. NAESB
asserts that this will require a more
comprehensive standards solution,
which may include data aggregation by
the transmission provider, reports
prepared and posted quarterly including
how the information is communicated
between the transmission provider and
marketer for collection, submittals of
quarterly reports from the transmission
provider to the Commission, changes to
the OASIS S&CP, and determination of
informational content and design of
templates. NAESB states that posting is
more complicated if the transmission
provider is required to post information
given to it by a marketer on its nonstandard products and requests
Commission guidance regarding posting
requirements.
Other Issues
806. Some commenters argue that
price caps are not limiting capacity
reassignment under the current pro
forma OATT.481 Williams contends that
other non-price limitations on capacity
reassignment, such as the requirement
that the assignee utilize the same source
and sink as the original customers, are
the real reasons there has not been more
capacity reassignment. Williams
acknowledges that this bars network
customers from reassigning
transmission capacity and requests that
Commission clarify that classification of
a transmission customer as a network or
point-to-point customer does not restrict
the purchase or reassignment of
transmission capacity. Sacramento
similarly complains that one of the chief
impediments to capacity reassignment
is that network integration service
customers are not permitted either to
assign their capacity or to utilize it to
make off-system sales. Sacramento
contends that a point-to-point customer
may utilize otherwise unused capacity
to make sales ‘‘off-system’’ to third
parties, while network customers cannot
make full use of the transmission
capacity for which they are paying.
807. Some commenters contend that
timelines for the release of capacity
should be clearly stated.482 APPA
argues that section 13.8 of the pro forma
OATT provides too little time for LSEs
attempting to make firm power supply
arrangements to obtain even daily firm
point-to-point service using the capacity
left unscheduled by other firm point-topoint customers. Powerex and SPP also
ask the Commission to set out clear
rules, including timelines, for releasing
unused transmission capacity for nonfirm use to better encourage full and
economically efficient use of the
existing transmission grid.
Commission Determination
808. To foster the development of a
more robust secondary market for
transmission capacity, the Commission
concludes that it is appropriate to lift
the price cap for all transmission
customers reassigning transmission
capacity. In Order No. 888, the
Commission found that allowing
holders of firm transmission capacity
rights to reassign capacity would help
parties manage the financial risks
associated with their long-term
commitments, reduce the market power
of transmission providers by enabling
customers to compete, and foster
476 E.g.,
477 E.g.,
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479 E.g.,
PJM, PNM–TNMP, and TranServ.
Allegheny, Morgan Stanley, NAESB,
Seattle, and TranServ.
480 E.g.,
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481 E.g., Powerex, Sacramento, TAPS, and
Williams.
482 E.g., APPA, Powerex, and SPP.
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efficient capacity allocation.483 Over the
past ten years, however, it has become
clear that capacity reassignment has
failed to develop into a competitive
alternative to primary capacity. In
particular, the price cap has served to
reduce customers’ transmission options
and impaired the development of a
secondary market for transmission
capacity. In order to achieve the goals
originally stated in Order No. 888, we
therefore lift the price cap for reassigned
capacity. We believe this will allow
capacity to be allocated to those entities
that value it most, thereby sending more
accurate price signals to identify the
appropriate location for construction of
new transmission facilities to reduce
congestion.
809. We decline to adopt the NOPR
proposal to retain price caps for
capacity resold by a transmission
provider’s merchant function or its
affiliates.484 After reviewing the
comments submitted in response to the
NOPR, and further considering our ten
years of experience regulating capacity
reassignments, we conclude that
retaining the price caps for this portion
of the market would continue to impair
development of the secondary market
and is not otherwise necessary to ensure
just and reasonable rates. We find there
are no significant market power
concerns to justify retaining the price
caps for any transmission customer.
Indeed, the Commission did not
distinguish between affiliated and nonaffiliated transmission customers when
it initially found in Order Nos. 888 and
888–A that excess capacity reserved
could be reassigned.485 The Commission
instead placed a price cap on all
reassignments of capacity out of a
concern that the entire market for
reassigned capacity was not sufficiently
competitive.486 We now find that
market forces, combined with the
requirements of the pro forma OATT as
modified in this Final Rule, will limit
the ability of assignors to exert market
power, including affiliates of the
transmission provider. First,
competition among reassigning
customers will restrict the exercise of
market power. Second, the continued
regulation of rates for primary capacity
will act as a further check to ensure
rates for reassigned capacity remain just
483 Order
No. 888 at 31,696.
Order Nos. 888 and 888–A require a
separation of a public utility’s transmission
function and its wholesale generating marketing
(merchant) function, a transmission provider will
take service under its OATT through its merchant
function or affiliate.
485 Order No. 888 at 31,696–97; Order No. 888–
A at 30,219–25.
486 Order No. 888 at 31,697.
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484 Because
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and reasonable. Finally, the amended
rules we adopt below to govern the
reassignment of capacity will increase
our regulatory oversight of the
secondary capacity market, allowing us
to effectively monitor the secondary
capacity market. There is thus no need
to retain the existing price caps on
reassigned capacity for any market
participant.
810. Our decision to lift the price caps
for capacity reassignments by all
transmission customers is motivated by
growing concerns regarding the decrease
in transmission investment and the
corresponding increase in congestion
costs, as described more fully in section
III.C of this Final Rule. The Commission
believes it is important to take every
opportunity to explore more efficient
use of the grid by industry participants,
whether they are affiliates of the
transmission provider or not.
Eliminating the price cap for reassigned
capacity will provide greater flexibility
to respond to changing system
conditions and alternatives for
customers that value the capacity more
highly. As commenters suggest, lifting
the price cap will enhance the ability of
customers that reserve long-term
capacity for five-year terms in order to
obtain rollover rights to resell that
capacity if their needs change.487 Other
customers may determine that it is more
economic to acquire reassigned capacity
reflecting market rates than reserve
long-term capacity. In either case, lifting
the price cap will help ensure that,
during peak demand periods,
transmission capacity will be used by
those that value it the most. Establishing
a competitive market for secondary
transmission capacity will thus send
more accurate price signals that promote
efficient use of the transmission system
by fostering the reassignment of unused
capacity.
811. While some commenters argue
that lifting the cap encourages the
exercise of market power, including
hoarding, and discourages transmission
investment, we find that competition
among reassigning customers,
continuing rate regulation of the
transmission provider’s primary
capacity, and reforms to the secondary
capacity market adopted below,
combined with enforcement
proceedings, audits, and other
regulatory controls, will assure just and
reasonable rates. The Commission
discussed the possibility of transmission
capacity hoarding in Order No. 888. The
Commission noted that unscheduled
487 As explained in section V.D.3, the Final Rule
extends from one year to five years the minimum
term required to obtain a rollover right.
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12367
firm capacity is available on a non-firm
basis to other customers and, thus, there
is little practical possibility of hoarding.
Instead, the capacity reassignment
provisions of the pro forma OATT
provide an economic incentive to make
that capacity available to third
parties.488 This applies even when the
entity obtaining transmission capacity
under the pro forma OATT is the
transmission provider.489 It is equally in
the corporate interests of a transmission
provider and its affiliates not to overreserve or ‘‘hoard’’ transmission
capacity. Under the pro forma OATT,
the affiliate—and therefore the upstream
corporate parent of the affiliate and the
transmission provider—bears the cost
responsibility for transmission capacity
that it reserves but does not use to make
wholesale sales. If the affiliate attempts
to hoard transmission capacity, its
upstream corporate parent loses
revenues just like the non-affiliate. Like
any other customer, an affiliate of the
transmission provider should find it in
its overall corporate interest to reassign
transmission capacity to others with
higher valued uses at negotiated
rates.490
812. We reject the suggestion in the
NOPR that lifting the price caps for the
transmission providers’ merchant
function or affiliates will provide
disincentives to build or expand the
transmission system. Without
congestion, the transmission provider’s
rate on file will serve as the de facto
price cap and, if congestion exists, the
‘‘incremental rate’’ reflecting the
transmission provider’s cost of
expanding the system should act as a
price ceiling for long-term transactions.
It would be unreasonable to expect a
transmission customer to pay a rate for
reassigned capacity that is higher than
the cost of expansion when it could
simply exercise its rights under the pro
forma OATT as a cheaper alternative.
To the extent there is a lag-time between
the request for new transmission service
488 Order
No. 888 at 31,693.
Southwestern Public Service Company, 80
FERC ¶ 61,245 at 61,905 (1997).
490 Moreover, Order No. 889 required that all
public utilities establish or participate in an OASIS
that meets certain specifications and comply with
Standards of Conduct designed to prevent
employees of a public utility (or any employees of
its affiliates) engaged in wholesale power marketing
functions from obtaining preferential access to
pertinent transmission system information. The
Standards of Conduct mitigate the ability of an
affiliate to hoard capacity or collect rates that are
inconsistent with market conditions. As a result, we
are less concerned in this instance about affiliates
competing on the same terms as non-affiliates. To
the extent problems arise from affiliate participation
in the secondary capacity market, we will revisit
our decision here to lift the price caps for
transmission providers and their affiliates.
489 See
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and the date on which new facilities
would be available, the adoption of
conditional firm service and
modifications to redispatch service
elsewhere in this Final Rule will
mitigate the exercise of market power
during the interim period. We believe
that the reforms to rules governing
reassignments of capacity discussed
below, along with associated reporting
obligations, will adequately limit the
ability of capacity holders to exercise
market power in the limited
circumstances when neither primary
transmission capacity nor these
additional services are available.
813. Several commenters raise
concerns that lifting of the price ceiling
could lead to speculative pricing. If high
prices occur during periods of peak
demand it is a legitimate reaction to
supply and demand forces. As we
explained in Order No. 637–A, ‘‘[a]
surge in the price of candles during a
power outage is not evidence of
monopoly in the candle market.’’ 491 To
the extent that capacity is not being
anticompetitively withheld from the
market, high prices are the competitive
responses to market conditions and
should result in a more efficient
allocation of capacity to those customers
valuing it the most and a resulting
expansion of transmission facilities.
814. We emphasize that we are not
deregulating or otherwise adopting
market-based rates for the provision of
transmission service under the pro
forma OATT. Transmission providers
will continue to be obligated to make
ATC available to customers, including
ATC associated with purchased but
unused capacity. Transmission
providers also will continue to be
obligated to construct new facilities to
satisfy a request for service if that
request cannot be satisfied using
existing capacity. The pro forma OATT
therefore does not, and will not, permit
the withholding of transmission
capacity in an effort to exercise market
power. Furthermore, the rates for
transmission service provided under the
pro forma OATT will continue to be
determined on a cost-of-service basis
unless the transmission provider can
demonstrate, on a case-specific basis,
that it lacks market power. Nothing in
this Final Rule affects the obligations of
transmission providers to offer service
under the pro forma OATT at cost-based
rates. The only reform being adopted
concerns the resale of capacity by
transmission customers. Given that
traditional regulation will continue to
govern the sale of primary capacity
under the pro forma OATT, we no
491 Order
No. 637–A at 31,595.
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longer believe that cost-of-service
regulation is necessary or appropriate
for secondary capacity.492
815. As with any innovative rate
program, however, the Commission will
monitor the secondary capacity market
to ensure that participants are not
exercising market power. To enhance
oversight and monitoring by the
Commission, we adopt reforms to the
underlying rules governing capacity
reassignments. First, we require that all
sales or assignments of capacity be
conducted through or otherwise posted
on the transmission provider’s OASIS
on or before the date the reassigned
service commences. The Commission
thus eliminates the current ability of
transmission customers to assign the
transmission rights to another party
with subsequent notification to the
transmission provider.493 The
mechanisms for negotiating a
reassignment remain the same. The
transmission customer may either
request that the transmission provider
make the capacity available on its
OASIS or the transmission customer
may negotiate the terms of an
assignment bilaterally. In either
instance, however, the resulting sale or
assignment must be posted by the
transmission provider on its OASIS
prior to the date the reassigned service
commences. We require transmission
providers working through NAESB to
develop appropriate OASIS
functionality to allow such postings.
Transmission providers need not
implement this new OASIS
functionality and any related business
practices until NAESB develops
appropriate standards.
816. Second, we require that assignees
of transmission capacity execute a
service agreement prior to the date on
which the reassigned service
commences. Under the current pro
forma OATT, transmission customers
that have executed service agreements
may negotiate and implement
assignments of capacity without
involving the transmission provider,
subject to after-the-fact reporting and
posting, provided the transmission
customer has a market-based rate tariff
on file.494 In order to increase our
oversight of reassigned capacity, we find
492 Our findings here address the particular
circumstances associated with the electric utility
industry and are not intended to suggest that
corresponding changes should be made to the rates
for capacity release by customers of natural gas
transportation capacity. Any such changes would
be considered only after notice and comment and
based on a record applicable to the natural gas
industry.
493 See Order No. 888 at 31,697.
494 See Order No. 888 at 31,697 n.394; Order No.
888–A at 30,224 n.151.
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that all reassignments must instead be
accomplished by the assignee executing
a service agreement with the
transmission provider that will govern
the provision of reassigned service.495
This will effectively return the specified
capacity to the transmission provider for
the purpose of reassignment to the
assignee.496 The assignment shall be
only to the specified assignee, without
any obligation that the capacity be made
available to third parties, and shall not
be subject to any queuing by the
transmission provider since the assignee
is merely accepting the assignor’s
already-approved service for a specified
period.497 All of the non-rate terms and
conditions that otherwise would apply
to the transmission provider’s sale of
transmission capacity continue to apply
in the case of a reassignment.498
817. Third, in addition to existing
OASIS posting requirements, we require
transmission providers to aggregate and
summarize in an electronic quarterly
report the data contained in these
service agreements. As proposed in the
NOPR, the use of quarterly reports will
assist the Commission in gathering data
to ensure the effectiveness of market
forces and regulatory requirements to
mitigate the exercise of market power.
The Commission directs that this
quarterly report be submitted
electronically in spreadsheet format
495 The pro forma Form of Service Agreement for
the Resale, Reassignment or Transfer of Long-Term
Firm Point-to-Point Transmission Service is set
forth in a new Attachment A–1 to the pro forma
OATT.
496 As reformed in this Final Rule, the structural
mechanism for reassigning transmission capacity
will be similar to the mechanism for releasing
pipeline capacity. While parties may be able to
negotiate the prices applicable to assigned capacity,
the assignee will execute a service agreement
directly with the transmission provider and, thus,
there will no longer be a need for the assigning
party to have on file with the Commission a rate
schedule governing reassigned capacity. See Order
No. 888 at 31,697 n. 324. The transmission
provider’s OATT will govern the reassigned service.
The assignee will pay the transmission provider for
service at the negotiated rate and the transmission
provider will bill or credit the assignor with any the
difference between the negotiated rate and the
assignor’s original rate. As noted above, however,
there will be no requirement for the transmission
provider to create an auction for reassigned
transmission capacity similar to the pipeline
capacity reassignment program, since the
underlying price caps are being removed for electric
transmission capacity.
497 To the extent the assignee desires to change
its points of receipt or delivery, the limitations set
forth in section 23.2 shall apply.
498 See Commonwealth Edison Co., 78 FERC ¶
61,312 at 62,336 (1997); Boston Edison Co., 81
FERC ¶ 61,372 at 62,768 (1997); Southwestern
Public Service Co., 80 FERC ¶ 61,245 at 61,905
(1997). The non-rate terms and conditions of
reassigned service will therefore conform to the pro
forma OATT. As a result, there is no requirement
to file with the Commission service agreements for
reassigned transmission service.
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consistent with the electronic filing
system used for Electric Quarterly
Reports so that it is readily accessible to
the Commission and the public.499
818. Taken together, these reforms to
the rules governing reassigned capacity
will increase transparency and facilitate
our monitoring of the secondary market
for transmission capacity. We do not
believe it is necessary to require a
market power analysis as a condition to
exercising the right to reassign
transmission capacity. Although market
power analyses are one method for
ensuring that market-based rates remain
just and reasonable, they are not the
only method.500 To achieve the
Commission’s original goals for capacity
reassignment expressed in Order No.
888, we adopt a more flexible approach
in this area and rely on posting
requirements and other regulatory
controls to ensure that rates for
reassigned transmission capacity remain
just and reasonable. As noted above, we
find that a market power analysis is not
required because transmission providers
continue to be obligated to satisfy
requests for service—whether out of
existing capacity or new facilities—at
cost-based rates. Transmission capacity
therefore cannot be withheld in an effort
to exercise market power. Moreover, the
posting and filing requirements adopted
herein provide the Commission the
necessary information to ensure that,
even if an entity sought to exercise
market power in the secondary market,
such an attempt could be effectively
detected.
819. We therefore disagree with
commenters who assert that lifting the
cap on reassignment contradicts judicial
and Commission precedent. In Order
No. 637–A, the Commission explained
at length why Farmers Union 501 and
other precedent did not prevent the
Commission from adopting negotiated
499 The transmission provider should identify
capacity reassignments in the Contracts tab of the
EQR using the Product Type Name ‘‘CAPACITY
REASSIGNMENT.’’ All terms must be fully
described and rates provided. If no Product Name
adequately captures the nature of a given aspect of
the capacity reassignment, the assignor may use the
Product Name ‘‘OTHER,’’ but that aspect must be
fully described in the Rate Description field. If that
description is over 150 characters, the transmission
provider may use multiple Contract Product lines
to describe it. General instructions on how to file
the EQR may be found at https://www.ferc.gov/docsfiling/eqr.asp.
500 See Alternatives to Traditional Cost-of-Service
Ratemaking for Natural Gas Pipelines and
Regulation of Negotiated Transportation Services of
Natural Gas Pipelines, 74 FERC ¶ 61,076 (1996).
501 Farmers Union Central Exchange v. FERC, 734
F.2d 1486, 1501 (D.C. Cir. 1984) (Farmers Union)
(finding that Commission failed to justify relaxation
of cost-based regulation of oil pipeline companies
because it did not ensure rates would remain within
the zone of reasonableness).
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rates for secondary capacity as part of a
regulatory scheme that provides
safeguards to ensure that rates remain
just and reasonable.502 The court
affirmed the Commission’s removal of
price ceilings for short-term capacity
release shippers in the natural gas
market established in Order Nos. 637
and 637–A, recognizing that non-cost
factors such as the need to lift price
ceilings to facilitate movement of
capacity into the hands of those who
value it most and the negotiated rates
only to the secondary market
distinguished the case from Farmers
Union.503 The same is true here, given
the non-cost factor advantages of lifting
the price cap and the use of monitoring
and enforcement of remedies to mitigate
the exercise of market power.
820. The Commission directs staff to
closely monitor the reassignmentrelated data submitted by transmission
providers in their quarterly reports to
identify any problems in the
development of the secondary market
for transmission capacity and, in
particular, the potential exercise of
market power. We direct staff to
prepare, within six months of receipt of
two years of quarterly reports, a report
summarizing its findings. To inform our
analysis, we encourage market
participants to provide feedback
regarding the development of the
secondary capacity market and, in
particular, to contact the Commission’s
Enforcement Hotline 504 with any
particular concerns as this market
develops.
821. Although several commenters
argue that additional posting and filing
requirements could be too burdensome
and costly, the Commission does not
believe this burden will be great. All
capacity reassignments must be
conducted or otherwise posted on
OASIS and each assignee will be
required to submit an executed service
agreement for reassigned service. The
transmission provider thus will have
ready access to data necessary for the
OASIS postings and electronic quarterly
transaction reports. In any event, the
Commission’s access to this data is vital
to ensure effective monitoring and
oversight and, thus, we find that any
burden on the transmission provider is
outweighed by the need for
transparency. To the extent the
transmission provider incurs costs to
502 Order
No. 637–A at 31,558–72.
Natural Gas Association of America
v. FERC, 285 F.3d 18 (D.C. Cir. 2002).
504 Market participants may contact the
Commission’s Enforcement Hotline via telephone
(202) 502–8390, toll-free 1–888–889–8030, fax (202)
208–0057, or at https://www.ferc.gov/cust-protect/
enforce-hot.asp.
503 Interstate
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maintain or report this information,
Order No. 889 made clear that all OASIS
users, including the transmission
provider, pay all of the fixed costs of
OASIS-related activities in wholesale
rates and pay usage-related variable
costs and fees.505
822. With regard to confidentiality
concerns, the Commission finds that the
disclosure of reassigned capacity
information is necessary for the
Commission and market participants to
effectively monitor transactions for
undue discrimination and preference.
Consistent with our determination in
Order No. 2001, where similar concerns
were raised regarding disclosure of
information, we believe that disclosure
will promote competition and make the
market operate more efficiently.506
Moreover, public reports will provide
customers with a certain level of price
transparency to help them make
informed decisions regarding the
relative value of capacity on a particular
path.
823. We decline requests to require
implementation of electronic auctions
for reassigned capacity. While such
mechanisms are in place in RTO and
ISO markets, we conclude that it would
be too great a burden to impose
electronic auctions on other
transmission providers simply to
facilitate capacity reassignments. The
continued use of OASIS, combined with
the posting and service agreement
requirements adopted here, should be
sufficient to facilitate more efficient use
of the grid and mitigate the exercise of
market power.
824. With regard to the requests that
the Commission institute alternative
specific timelines and other rules for the
reassignment of capacity rights to
ensure efficient use of the grid, we will
not revise the rules set forth in the pro
forma OATT. We do not have sufficient
evidence in this proceeding to suggest
that public utilities’ existing scheduling
timelines generally hinder customers
from reselling unused transmission
capacity or lead to capacity
withholding.
825. With regard to requests for
network customers to reassign
transmission capacity, we affirm our
finding in Order Nos. 888 and 888–A
that capacity reassignments are
available only to point-to-point
customers.507 Point-to-point service
under the pro forma OATT clearly sets
forth defined capacity rights and is
therefore reassignable. In comparison,
505 Order
No. 889 at 31,625.
Order No. 2001 at P 94–129.
507 Order No. 888 at 31,696; Order No. 888–A at
30, 223.
506 See
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there are no specific capacity rights
associated with network service and,
thus, that service is not reassignable.
Network service provides a network
customer with a right to integrate its
designated resources with its designated
loads, in a generation pattern primarily
determined by the customer. As a result,
it would be difficult to determine at any
moment in time exactly what portion of
network service could be resold,
because the network customer does not
have a discrete capacity reservation and
its usage of the transmission system
varies as it attempts to most
economically use its resources to meet
its loads. To the extent an entity elects
network service, it does so with the
understanding that the service is not
reassignable because there are no
specific capacity rights to reassign.
5. ‘‘Operational’’ Penalties
a. Unreserved Use Penalties
NOPR Proposal
sroberts on PROD1PC70 with RULES
826. In the NOPR, the Commission
proposed to clarify that unreserved use
penalties apply to any circumstance
where a transmission customer uses
transmission service that it has not
reserved.508 Specifically, the
transmission customer would be subject
to an unreserved use penalty in
circumstances where the transmission
customer has a transmission service
reservation, but uses transmission
service in excess of its reserved
capacity. A transmission customer also
would be subject to an unreserved use
penalty if the transmission customer
uses transmission service where it does
not have a transmission service
reservation. The Commission also
proposed that a transmission customer
would not be subject to an unreserved
use penalty in circumstances where the
transmission customer inappropriately
uses a network service reservation to
support an off-system sale.
827. The Commission sought
comment on whether the current policy
that limits unreserved use penalties to
twice the standard rate for the entire
service period has resulted in penalties
that are not just and reasonable and, if
so, it sought further comment regarding
provisions that would yield unreserved
use penalties that are just and
reasonable.
508 In the NOPR, we referred to an unreserved use
penalty as an ‘‘unauthorized use penalty.’’ For the
purpose of the Final Rule, we adopt the term
‘‘unreserved use penalty’’ as it more clearly
articulates the nature of the penalty.
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(1) Unreserved Use of Transmission
Service
Comments
828. Several commenters express
general support for the Commission’s
proposed clarification that unreserved
use penalties apply to any circumstance
where a transmission customer uses
transmission service that it has not
reserved.509 Several commenters
support the Commission’s proposed
clarification, but suggest that the
transmission provider should only
assess unreserved use penalties when a
transmission customer repeatedly uses
transmission service that it has not
reserved.510 For instance, PNM–TNMP
believes penalty assessment should be
optional and should be imposed on
transmission customers that do not
change their practices regarding
transmission use and OATT compliance
after being advised of their noncompliance.
829. Several commenters argue that
transmission customers with special
circumstances should not be subject to
unreserved use penalties in the same
manner as other transmission
customers. For instance, Seattle believes
unreserved use penalties can result in
charges that are unjust and reasonable
for intermittent resources, such as wind
generators, that can not precisely
schedule power in future periods, but
are capable of controlling output. Seattle
believes that unreserved use penalties
should not apply if the transmission
provider is able to operate the
transmission system reliably. Seattle
argues that an unreserved use penalty
should only apply if scheduling parties
have failed to respond to dispatchers’
orders stating that system conditions
necessitate curtailment of output.
Southern disagrees with Seattle and
states that, as a general principle,
unreserved use penalties should not be
based on whether reliability is
threatened. TDU Systems recommend
that the Commission consider treating
inadvertent use of point-to-point
transmission service in excess of
reservations by an entity serving native
load in multiple control areas as an
energy imbalance in the control area in
which the energy imbalance occurs,
rather than an unreserved use of pointto-point service. In their reply
comments, EEI and PNM–TNMP
disagree with TDU Systems. EEI argues
that energy imbalance charges
compensate generators for the
additional expense they incur to
509 E.g.,
510 E.g.,
APPA and Bonneville.
MidAmerican, Southern, and PNM–
TNMP.
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compensate for the customer’s failure to
schedule sufficient energy to serve its
load and do not compensate the
transmission provider for the use of the
transmission system. EEI asserts that
customers that use more transmission
service than they schedule should be
required to pay for that transmission
service just like any other user of the
system.
830. Duke opposes the Commission’s
proposed clarification and suggests that
an effective means of deterring and
punishing unreserved use of
transmission service is to charge the
customer for the point-to-point service
necessary to support the transaction
and, additionally, to make the customer
subject to a civil penalty in cases of
intentional or repeated unreserved use.
TDU Systems argue on reply that a
transmission provider should not be
allowed to charge unreserved use
penalties unless it employs software
technology designed to identify
unreserved use prior to operation.
831. Several commenters suggest
modifications to the manner by which
transmission providers determine when
unreserved use penalties should be
assessed. TDU Systems believes
unreserved use penalties should only be
applied with prior Commission
approval after notice and opportunity
for hearing in order to limit the
transmission provider’s discretion in
applying such penalties. To encourage
regulatory certainty, Seattle suggests
that the Commission implement tariff
provisions that state a clear basis for
application of unreserved use penalties.
832. Several commenters ask that the
Commission delete the proposed
language added to section 30.4 of the
proposed revised pro forma OATT
regarding the unreserved use of a
network resource beyond its designated
capacity.511 In the event the
Commission elects to retain this
language, these commenters ask the
Commission to clarify the language to
expressly permit use of the
undesignated portion of a remote
network resource under secondary nonfirm service (as a non-network resource)
and to preserve the customer’s right to
use the undesignated portion of the
resource for other purposes (e.g., to
serve its load on systems other than the
host transmission provider or to make
off-system sales). In its reply comments,
Duke notes that the fact that a generator
is designated as a network resource for
a network load on one system does not
prohibit a network load on a second
system from obtaining non-firm energy
511 E.g., APPA, TAPS, TDU Systems, and EEI
Reply.
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from that same generator using point-topoint and secondary network resource.
Duke points out that the proposed
revised section 30.4 prohibits a network
customer from using its firm network
service to schedule power in excess of
the DNR amount. Finally, TAPS asks the
Commission to modify the language
added to section 30.4 so that its terms
are consistent with the terms used in the
rest of the pro forma OATT.
833. EEI recommends that a customer
that takes unreserved transmission
service, but that does not have a service
agreement with the transmission
provider, be deemed to have consented
to the transmission provider’s filing of
a service agreement, so that the
transmission provider has a basis for
imposing both the prevailing OATT rate
and the penalty charge on the customer.
EEI also recommends that the
Commission clarify that a customer that
uses more transmission service than it
has reserved also is subject to charges
for ancillary services.
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Commission Determination
834. The Commission adopts the
NOPR proposal that a transmission
customer will be subject to unreserved
use penalties in any circumstance where
the transmission customer uses
transmission service that it has not
reserved. Specifically, a transmission
customer will be subject to an
unreserved use penalty in
circumstances where a transmission
customer has a transmission service
reservation, but uses transmission
service in excess of its reserved
capacity. A transmission customer also
will be subject to an unreserved use
penalty if the transmission customer
uses transmission service where it does
not have a transmission service
reservation, including the situations
described in the Arizona Public Service
Company (APS) audit report.512 We note
that the transmission provider is subject
to the same penalties when it takes
transmission service under its OATT.
835. Our decision to clarify the
application of unreserved use penalties
will eliminate a potential source of
discretion in the implementation of the
512 Arizona Public Service Co., 109 FERC ¶ 61,271
at P 6 (2004) (APS). APS contained two findings
that Commission audit staff characterized as
unauthorized use of transmission service. In the
first finding, APS’s wholesale merchant function
did not request and pay for point-to-point service
to support some of the off-system power sales it
made at trading hubs where APS system resources
were directly connected. In the second finding, APS
incorrectly treated the Phoenix Valley 230kV
system as a single node on its transmission system.
As a result, off-system sales made by generators
connected to the Phoenix Valley system should
have been, but were not, supported by point-topoint service.
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pro forma OATT and will assist the
Commission in its enforcement of the
OATT obligations. The unreserved use
penalty itself will help discourage
disorderly use of transmission service.
Charging a transmission customer for
just the unreserved transmission service
used, as suggested by Duke, would not
provide a sufficient incentive to procure
adequate transmission service, even
with the threat of possible civil
penalties. In addition, an operational
penalty rather than a civil penalty is a
more appropriate default remedy, even
though certain circumstances may
warrant a civil penalty in addition to an
operational penalty. In most instances,
an unreserved use penalty can be
applied in a relatively mechanical
manner. As a result, an operational
penalty has a relatively low
administrative burden and still provides
a clear signal to transmission customers
regarding the cost of non-compliance.513
We do not agree with TDU Systems’
proposal that a transmission provider be
required to employ software designed to
identify unreserved use if the
transmission provider wants to charge
unreserved use penalties. As we explain
below, we adopt reforms in this Final
Rule that will reduce the level of
unreserved use penalties for instances of
inadvertent unreserved use. For
instance, we reduce the period over
which a one-time inadvertent use will
be penalized from one month to one
day. We believe that this and other
reforms are sufficient to address TDU
Systems’ concerns.
836. We will not adopt Seattle’s
suggestion to add provisions to the pro
forma OATT that specify all
circumstances that constitute use of
transmission service without a
transmission service reservation. Any
list of transmission customer actions
that would be deemed to constitute use
of transmission service without a
transmission service reservation will
necessarily be incomplete and out-ofdate given the dynamic manner by
which trading patterns and practices
evolve. We believe that Commission
actions, such as in APS, will provide a
sufficient guide to circumstances that
constitute use of transmission system
without a transmission service
reservation. We also reject TDU
Systems’ suggestion that unreserved use
penalties be applied only after
Commission approval. As mentioned
above, an unreserved use penalty can be
513 The unreserved use penalties thus work in
conjunction with imbalance penalties described in
section V.C.2 of this Final Rule to reduce incentives
to take actions that impair the reliability of the
transmission system.
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12371
assessed in a relatively straightforward
manner in most cases. As a result, there
will typically be little need for the
Commission to become involved. That
said, a transmission customer can
always file a complaint with the
Commission protesting an unreserved
use penalty.
837. We will not exempt any class of
transmission customer from the
potential assessment of unreserved use
penalties. We do not agree with Seattle’s
assertion that unreserved use penalties
can result in charges that are unjust and
reasonable for intermittent resources,
such as wind generators, that can not
precisely schedule power in future
periods. Unreserved use penalties are
based on the transmission capacity
reserved rather than the transmission
service scheduled, so an intermittent
resource’s inability to precisely
schedule power in future periods is
irrelevant, as long as the resource has
reserved sufficient transmission
capacity to deliver the resource’s full
output. We also do not agree with TDU
Systems’ suggestion that unreserved use
of transmission service by an entity
serving native load in multiple control
areas should be treated as an energy
imbalance in the control area in which
the energy imbalance occurs, rather than
an unreserved use of point-to-point
service. In this regard, we agree with EEI
that energy imbalance charges
compensate the transmission provider
for the additional expense it incurs to
compensate for a transmission
customer’s failure to schedule sufficient
energy to serve its load and do not
compensate the transmission provider
for the use of the transmission system.
838. We will not limit unreserved use
penalties to instances where the
unreserved use jeopardizes the reliable
operation of the transmission system.
Unreserved use penalties are intended,
in part, to give transmission customers
an incentive to reserve and pay for the
appropriate level of transmission service
so that transmission service is allocated
in an orderly fashion. A transmission
customer that uses unreserved
transmission service requires the
transmission provider to take some
action to accommodate the additional
use of the system. Some penalty is
warranted even in those instances when
the transmission provider’s
accommodations are sufficient to avoid
curtailment of transmission service to
other transmission customers. Absent a
penalty in all instances, transmission
customers would have an increased
incentive to under-reserve transmission
service, which would lead to an
increase in the likelihood that system
reliability would be impaired. In
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addition, a transmission customer that
uses more transmission service than it
has reserved, even in periods when
system reliability has not been
impaired, has nonetheless disturbed the
orderly allocation of transmission
service.
839. In response to comments
requesting that we remove the language
added to section 30.4 of the proposed
revised pro forma OATT regarding the
unreserved use of a network resource
beyond its designated capacity, we
clarify our intent in modifying section
30.4. The Commission has identified
instances when a transmission provider
has scheduled delivery of off-system
non-designated short-term purchases
using transmission capacity reserved for
designated network resources.514 The
intent of the language added to section
30.4 of the pro forma OATT was to
clarify that network customers are
subject to unreserved use penalties
when they schedule delivery of offsystem non-designated purchases using
transmission capacity reserved for
designated network resources. We
clarify, however, that a network
customer may use the undesignated
portion of a remote network resource to
serve network load using secondary
network service and may use the
undesignated portion of the resource for
other non-network service purposes,
such as third-party sales, as long as the
network customer acquires the
appropriate point-to-point transmission
service. Moreover, because a
transmission provider does not have to
‘‘take service’’ under its own OATT for
the transmission of power that is
purchased on behalf of bundled retail
customers, it is free to use the
undesignated portion of a remote
network resource to serve its bundled
retail customers.515 If the transmission
provider desires to use a remote
network resource for non-native load
purposes, such as third-party sales, it
must acquire the appropriate point-topoint transmission service.516
840. In order to ensure that the
transmission provider has a basis for
charging an unreserved use penalty, we
modify section 13.4 of the pro forma
OATT to provide that a customer that
takes unreserved point-to-point
transmission service and does not have
a service agreement with the
transmission provider is deemed to have
executed the transmission provider’s
form of service agreement for point-to514 See MidAmerican Energy Co., 112 FERC
¶ 61,346 (2005); PacifiCorp, 118 FERC ¶ 61,026
(2007).
515 See Order No. 888–A at 30,216–17.
516 See id. at 30,217.
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point service. In addition, we clarify
that a customer that uses more
transmission service than it has reserved
is also subject to charges for ancillary
services. The ancillary service charges
will be based on just the period of
unreserved use. For instance, if a
transmission customer has unreserved
use during two hours on the same day,
the customer must pay the ancillary
service charges for those two hours,
rather than for the entire day. This
modification is appropriate, as the
transmission provider is entitled to
compensation for the ancillary services
it provides when it provides
transmission service. We also will
modify section 3 of the pro forma OATT
to reflect this rule.
(2) Treatment of Inappropriate Use of
Network Service as an Unreserved Use
of Point-to-Point Transmission Service
Comments
841. A few commenters argue that a
transmission customer that
inappropriately uses a network service
reservation to support an off-system sale
should be subject to unreserved use
penalties.517 Other commenters request
clarification or modifications to the
Commission’s proposal regarding the
treatment of transmission customers
that inappropriately use a network
service reservation to support an offsystem sale. TAPS asks the Commission
to clarify that a transmission provider
that inappropriately uses network
service to support an off-system sale is
required to pay for point-to-point
service to support the off-system sale
and potentially is liable for civil
penalties, as the Commission proposed
in the NOPR. Suez Energy NA suggests
that an affiliate of the transmission
provider that violates network tariff
provisions by making unauthorized
sales should also disgorge unjust profits
from such sales. TDU Systems urges the
Commission not to impose civil
penalties for inadvertent use of network
service by an LSE when it serves its own
native load on a neighboring system.
Commission Determination
842. The Commission declines to
adopt the NOPR proposal to exempt a
network customer or transmission
provider that inappropriately uses
network transmission service to support
off-system sales from unreserved use
penalties. As mentioned above, one of
the purposes of unreserved use
penalties is to encourage orderly use
and acquisition of transmission service.
A network customer or transmission
517 E.g.,
PO 00000
APPA and PNM–TNMP.
Frm 00108
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provider that inappropriately uses
network transmission service to support
off-system sales potentially uses or
acquires transmission service that
should be allocated to other
transmission customers. In addition, the
network customer or transmission
provider has not paid for transmission
service as required. Therefore, we
conclude that a network customer or
transmission provider inappropriately
using network transmission service to
support off-system sales should be
subject to unreserved use penalties. We
will evaluate the appropriateness of
civil penalties in addition to unreserved
use penalties on a case-by-case basis
and will not exempt, as a matter of
general policy, inadvertent use of
network service by an LSE when it
serves its own native load on a
neighboring system as suggested by
TDU Systems. A network customer or
transmission provider that
inappropriately uses network
transmission service to support offsystem sales also may be required to
disgorge unjust profits from such sales,
as the Commission may determine on a
case-by-case basis.
(3) Penalty Rate for Unreserved Use of
Transmission Service
Comments
843. Transmission providers generally
assert that the Commission’s current
policy of limiting unreserved use
penalties to twice the standard rate for
the entire service period has yielded just
and reasonable rates.518 EEI contends
that if the customer is required to pay
an unreserved use charge only for the
period of unreserved use, the customer
would have an incentive to reserve
service for less than its maximum
expected use and simply pay
unreserved use charges in the hours in
which it exceeds that usage. EEI
concedes, however, that the maximum
period for which the unreserved use
charge should be assessed is one month.
For example, EEI acknowledges that it
would be unreasonable to charge a
customer that takes yearly service a
penalty for an entire year because of, for
instance, a single hour of unreserved
use. In addition, EEI suggests several
modifications to the current unreserved
use penalty policy. EEI suggests the
Commission include, in the pro forma
OATT, provisions stating that the
penalty charge for unreserved use of
transmission service is equal to twice
the standard rate for transmission
service. EEI recommends that the
Commission establish a policy that a
518 E.g., EEI, Bonneville, MidAmerican, Nevada
Companies, and PNM–TNMP Reply.
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customer that uses transmission service
without a reservation must pay a
penalty equal to twice the rate for
transmission service for the greater of
the period of unreserved use or one
month.
844. Transmission customers
generally assert that unreserved use
penalties should be limited to twice the
standard rate for the period of
unreserved use.519 Transmission
customers who take this position argue
that using the service period rather than
the period of unreserved use as the basis
for the penalty charge discriminates
against transmission customers with
longer term transmission service
reservations.520 For instance, AWEA
believes that applying an unreserved
use penalty based on the reservation
period rather than the period of
unreserved use has resulted in charges
that are not just and reasonable. AWEA
asserts that such a policy would also be
discriminatory because, if the customer
causing the unreserved use had made a
shorter reservation, its penalty would be
much lower. TDU Systems argue in its
reply comments that there is little to be
gained from charging inadvertent
unreserved use more than twice the
standard rate for the period of
unreserved use.
845. Several commenters suggest that
unreserved use penalty charges greater
than twice the standard rate for the
entire service period should be limited
to instances of intentional unreserved
use.521 Nevada Companies note that
there are some marketing entities that
are consistently abusing the current
policy and recommends that the
Commission consider more severe
penalties for continuous carelessness in
tagging or a repeated pattern of
unreserved use of the transmission
system. Southern believes the
transmission provider should be
permitted to charge increased
unreserved use penalties if a
transmission customer consistently uses
transmission services it has not
reserved. TDU Systems disagree on
reply comments, arguing that a penalty
equal to twice the applicable charge is
sufficient to deter unreserved use of
transmission service.
Commission Determination
sroberts on PROD1PC70 with RULES
846. We will continue giving
transmission providers discretion in
setting their unreserved use penalty
rates, although those rates will need to
519 E.g.,
520 E.g.,
APPA, AWEA, TAPS, and TDU Systems.
APPA, AWEA, TAPS, and TDU Systems
Reply.
521 E.g., NRECA, Nevada Companies, and
Southern.
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be consistent with this Final Rule.
Penalty charges must be based on the
period of unreserved use rather than the
period for which service is reserved,
subject to the following principles. First,
the unreserved use penalty for a single
hour of unreserved use will be based on
the rate for daily firm point-to-point
service, even if the transmission
provider has a rate for hourly firm
point-to-point transmission service on
file. Second, as a general rule, more than
one assessment for a given duration
(e.g., daily) will increase the penalty
period to the next longest duration (e.g.,
weekly). The unreserved penalty charge
for multiple instances of unreserved use
(i.e., more than one hour) within a day
will be based on the rate for daily firm
point-to-point service. The unreserved
penalty charge for multiple instances of
unreserved use isolated to one calendar
week would result in a penalty based on
the charge for weekly firm point-topoint. The unreserved use penalty
charge for multiple instances of
unreserved use during more than one
week during a calendar month will be
based on the charge for monthly firm
point-to-point.522
847. Our determination is based, in
part, on agreement with those
commenters arguing that using the
period for which a transmission
customer has reserved service rather
than the period of unreserved use as the
basis for the penalty charge
discriminates against transmission
customers with longer term
transmission service reservations. We
are mindful, however, that basing
unreserved use penalties on only the
period of unreserved use could give the
transmission customer an incentive to
reserve service for less than its
maximum expected use and simply pay
unreserved use charges in the hours in
which it exceeds that usage. We believe
the unreserved penalty regime we
articulate in this Final Rule will provide
522 There are a number of possible permutations
of these principles. For instance, a transmission
customer that has 25 MW of unreserved use in two
hours on one day during the first week of the month
and 50 MW of unreserved use in two hours on one
day during the last week of the month will pay an
unreserved use penalty based on the rate for 25 MW
of daily firm point-to-point service and 50 MW of
daily firm point-to-point service. A transmission
customer that has 25 MW of unreserved use on two
separate days during the first week of the month
and 50 MW of unreserved use in two hours on one
day during the last week of the month will pay an
unreserved use penalty based on the rate for 25 MW
of weekly firm point-to-point service and 50 MW
of daily firm point-to-point service. A transmission
customer that has 25 MW of unreserved use on two
separate days during the first week of the month
and 50 MW of unreserved use on two separate days
during the last week of the month will pay an
unreserved use penalty on 50 MWs of monthly firm
point-to-point service.
PO 00000
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12373
a reasonable incentive to ensure that
transmission customers reserve the
appropriate level of transmission service
without unduly charging a transmission
customer for inadvertent unreserved
use. In addition, transmission customers
will continue to be subject to civil
penalties on a case-by-case basis, so
attempts to game this penalty regime
could result in additional penalties
depending on the specific facts at issue.
We reject the suggestion in some
comments that the transmission
provider should only assess unreserved
use penalties where a transmission
customer repeatedly uses transmission
service that it has not reserved. Rather,
we find that penalties are appropriate
for all unreserved uses of the system.
Because we are allowing penalties to be
based on the period of unreserved use,
not the reservation period, such
penalties do not unduly charge a
transmission customer for inadvertent
unreserved use. This penalty regime
will apply to all instances where a
transmission customer has an
unreserved use of transmission service,
regardless of whether the transmission
customer had an existing relevant
transmission service reservation but for
a lesser amount of service.
848. A transmission provider that
wants to charge unreserved use
penalties must explicitly state the
penalty rate in its tariff. The
Commission retains the current policy
established in Allegheny that the
unreserved use penalty rate may not be
greater than twice the firm point-topoint rate for the period of unreserved
use, as defined above.523 We continue to
believe that penalties up to twice the
relevant firm point-to-point rate are just
and reasonable, given the new
definition for the penalty period. As a
result, we establish a rebuttable
presumption that unreserved use
penalties no greater than twice the firm
point-to-point rate for the penalty
period defined above are just and
reasonable. As we discuss above, the
transmission customer must face a
penalty in excess of the firm point-topoint transmission service charge it
avoids through unreserved use of
transmission service or the transmission
customer will have no incentive to
reserve the appropriate amount of
service.
849. The Commission thus concludes
that a penalty of twice the standard rate
is not excessively punitive, particularly
given the definition of the penalty
period established in this Final Rule.
Without evidence to the contrary, we
523 Allegheny Power System, Inc., 80 FERC
¶ 61,143 at 61,545–46 (1997) (Allegheny).
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believe an unreserved use penalty equal
to twice the applicable rate should
create the appropriate incentive to
transmission customers to purchase the
correct amount of transmission service.
Nonetheless, we will allow transmission
providers to make a filing under section
205 of the FPA to propose an
unreserved use penalty in excess of
twice the relevant firm point-to-point
rate for pervasive unreserved use.
Transmission providers that propose
such a rate must establish that a higher
penalty rate is required to combat
pervasive unreserved use of
transmission. In arguing for such a
higher penalty rate, the transmission
provider must address why the standard
penalty rate that penalizes repeated
unreserved use is not adequate to
discourage repeated instances of
unreserved use of transmission service.
b. Distribution of Operational Penalties
NOPR Proposal
sroberts on PROD1PC70 with RULES
850. In the NOPR, the Commission
proposed to have the transmission
provider distribute to non-offending,
unaffiliated transmission customers
operational penalties incurred by the
transmission provider’s merchant
function or its affiliates.524 For those
transmission providers subject to
operational penalties, the Commission
proposed to require the transmission
provider to make an annual compliance
filing to notify the Commission of the
amounts of such operational penalties
incurred during the year and to propose
a method to identify non-offending,
unaffiliated transmission customers to
which the transmission provider would
distribute penalty amounts. In addition,
the Commission also proposed to allow
a transmission provider to avoid an
annual compliance filing by making a
one-time filing to propose a mechanism
through which it would identify nonoffending, unaffiliated transmission
customers and a method by which it
would distribute the operational
penalties it or its affiliates have incurred
to the identified transmission
customers. Finally, the Commission
proposed to prohibit transmission
providers from recovering for
ratemaking purposes or through any
service or facility under the
Commission’s jurisdiction any cost it
incurs when it or an affiliate pays an
operational penalty.
524 An
operational penalty explicitly defines the
charge associated with a set of pre-defined activities
(e.g., unreserved use of transmission service,
completing request studies outside of the 60-day
due diligence deadline) that are not in compliance
with specific provisions of the OATT.
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Comments
851. Transmission customers along
with several other commenters support
the Commission’s proposal to distribute
operational penalties paid by the
transmission provider’s merchant
function to non-offending, unaffiliated
transmission customers.525 Entegra and
Morgan Stanley advocate extending the
proposal so that the transmission
provider distributes operational
penalties paid by all transmission
customers to non-offending unaffiliated
transmission customers. Entegra also
notes that the Commission’s policy in
the natural gas setting is that pipelines
must credit all penalty revenues back to
non-offending shippers. Entegra argues
that the precedent the Commission cited
in proposing that operational penalties
paid by the transmission provider be
distributed to non-offending,
unaffiliated transmission customers
applies equally to penalties paid by
affiliated and unaffiliated transmission
customers.526
852. With regard to unreserved use
penalties, NRECA and TDU Systems
argue that the Commission should
encourage transmission providers to
supervise inadvertent unreserved use
and notify the customer of such
occurrence rather than rely on large
unreserved use penalties. They argue it
is better to prevent unnecessary costs
than to approve post hoc penalties for
unintentional unreserved use that could
have been prevented.
853. A number of transmission
providers oppose the portion of the
Commission’s proposal that would
prohibit their non-offending affiliates
from receiving a portion of the
operational penalties the transmission
provider incurs.527 For instance, PNM–
TNMP asserts that the Commission
should allow the transmission
provider’s non-offending affiliates,
which are abiding by the same rules as
other transmission customers in
accordance with Standards of Conduct,
to be eligible to receive a portion of the
operational penalties the transmission
provider incurs. In the specific case of
unreserved use penalties, Southern does
not support distributing penalties
imposed on a transmission provider’s
affiliate to other OATT customers.
Southern argues that such a proposal is
predicated upon the false assumption
that such penalties are not of true
525 E.g., APPA, ELCON, Entegra, TAPS, TDU
Systems, Sacramento, and Seattle.
526 Entegra cites Carolina Power & Light Co. and
Florida Power Corp., 103 FERC 61,209 at P 24
(2003) (Carolina Power & Light).
527 E.g., EEI, MidAmerican, Nevada Companies,
and PNM–TNMP.
PO 00000
Frm 00110
Fmt 4701
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financial consequence. Southern asserts
that penalties paid by an affiliate do, in
fact, represent a real cost to the
wholesale business of that affiliated
entity. In its reply comments, TDU
Systems disagrees with comments that
suggest that non-offending affiliates
should be allowed to receive a load ratio
share of penalty revenues when a
transmission provider or one of its
affiliates incurs an operational penalty.
TDU Systems argue that allowing any
member of the corporate family to retain
any portion of the penalty revenues
incurred by another member of the
corporate family will dilute the
incentive inherent in the Commission’s
proposal.
854. Seattle suggests that compliance
monitoring and enforcement to ensure
that the transmission provider
appropriately assesses penalties to its
affiliates will be as important as
correctly accounting for and distributing
the revenues from penalties collected
from affiliates.
855. Most commenters were
supportive of the Commission’s
proposal to have transmission providers
notify the Commission of the amounts
of all operational penalties they
incurred during the year through either
an annual compliance filing or a onetime filing.528 Several commenters
expressed a preference for a one-time
filing by transmission providers.529 For
instance, Ameren states that it prefers
the use of a one-time filing to propose
a mechanism through which the
transmission provider would identify
non-offending, unaffiliated transmission
customers and a method by which the
transmission provider would distribute
the operational penalties it or its
affiliates have incurred to the identified
transmission customers. Ameren
believes this would be less burdensome
than an annual repeated compliance
filing. TDU Systems, on the other hand,
prefer the Commission’s proposal to
require an annual reporting of penalties
levied and penalty revenues credited in
order to foster greater transparency on
this matter. TDU Systems believe greater
transparency through improved
reporting requirements would provide
greater opportunities for detecting
abuses by transmission providers or
their affiliates, either in imposing
inappropriate penalties on transmission
customers or in failing to penalize their
own or their affiliates’ transgressions. In
addition, TDU Systems suggest that this
reporting requirement should include
details on the amount of penalties
528 E.g., EEI, Suez Energy NA, Sacramento, TAPS,
and Wisconsin Electric.
529 E.g., Ameren and PNM–TNMP.
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levied, whether on customers or the
transmission provider or its affiliates,
for all violations. With regard to the
annual reporting requirements (for those
companies that do not propose a
standard mechanism to handle the
distribution of penalties), Nevada
Companies suggest that a standard
template be proposed so that all
companies are following the same
reporting format.
856. Several commenters make
recommendations that they argue will
ease the administrative burden of
distributing operational penalties paid
by the transmission provider to nonoffending, unaffiliated transmission
customers. MidAmerican suggests that
excluding short-term firm and non-firm
transactions from the distribution
methodology would avoid the need to
develop a costly and administratively
difficult program. TVA suggests that the
amount of any such operational
penalties should simply be a credit
against the transmission provider’s
transmission revenue requirement,
thereby more efficiently reducing the
cost of transmission service to
transmission customers.
857. Several commenters argue that
the transmission provider must be made
whole before it distributes any penalty
revenues. For instance, EEI supports the
Commission’s proposal to the extent
penalty revenues exceed the cost of
transmission service. Nevada
Companies assert that it is the
transmission provider’s native load that
incurs the cost of correcting for the
offending customer’s intentional
deviation from schedule or for a
transmission customer’s self-provided
reserves being unavailable. Therefore,
Nevada Companies contend that any
penalties should be returned to the
native load to offset its cost of
generation.
858. Sacramento and WPS
Companies’ reply comments support the
Commission’s proposal to prohibit a
transmission provider from recovering
any cost it incurs when it or an affiliate
pays an operational penalty through
jurisdictional rates or services.
Commission Determination
859. The Commission agrees with
those commenters recommending that
we broaden the NOPR proposal, which
required transmission providers to
distribute to non-offending, unaffiliated
transmission customers only the
unreserved use penalties the
transmission provider’s merchant
function incurs. Consistent with our
conclusion regarding imbalance
penalties, we conclude that it would be
more appropriate for transmission
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providers to be required to distribute all
unreserved use penalties they collect,
whether from the transmission
provider’s merchant function or other
transmission customers. The penalties
the transmission provider pays for late
studies are penalties that, by their
nature, are fully distributed only to nonaffiliated transmission customers.
Requiring the transmission provider to
distribute the unreserved use penalty
charges that its merchant function
incurs will ensure that the transmission
provider faces a meaningful financial
consequence when its merchant
function incurs an operational penalty.
Extending the NOPR proposal to all
unreserved use penalty revenues the
transmission provider collects
maintains the incentive structure of the
unreserved use penalty and prevents the
transmission provider from retaining
revenues above those it should
reasonably be allowed to earn.530 This
determination is consistent with the
Final Rule for imbalance penalties and
the Commission’s decision in Order
Nos. 637 and 637–A.531
860. We agree with those commenters
that suggest that non-offending affiliates
of the transmission provider, including
the transmission provider’s native load
customers, should be eligible to receive
a portion of the unreserved use
penalties that the transmission provider
collects. Unreserved use penalties are
assessed against transmission customers
and should, therefore, be distributed to
all non-offending transmission
customers, whether affiliated with the
transmission provider or not. Given the
distribution of unreserved penalties
articulated above, the transmission
provider’s corporate profit is reduced if
one of the transmission provider’s
wholly-owned marketing affiliates pays
an operational penalty to the
transmission provider. This is so
because the corporate shareholders
ultimately pay the marketing affiliate’s
530 As we explain further below, the transmission
provider will be allowed to retain the base firm
point-to-point transmission service charge when it
assesses an unreserved use penalty.
531 Regulation of Short-Term Natural Gas
Transportation Services, and Regulation of
Interstate Natural Gas Transportation Services,
Order No. 637, 65 FR 10156 (Feb. 25, 2000), FERC
Stats. & Regs. ¶ 31,091 at 31,309 (2000) (‘‘* * *to
effectively shift pipelines to the use of the nonpenalty mechanisms described above to solve and
prevent operational problems, it will be necessary
to eliminate the pipelines’ financial incentive to
impose penalties and OFOs. Thus, the Commission
is requiring pipelines to credit the revenues from
penalties and OFOs to shippers.’’); order on reh’g,
Order No. 637–A, 65 FR 35706 (Jun. 5, 2000), FERC
Stats. & Regs. ¶ 31,099 at 31,609 (2000) (‘‘The goal
of the Commission’s new policy on penalties is to
encourage pipelines to rely less on penalties and
more on non-penalty mechanisms to manage their
systems* * *.’’).
PO 00000
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12375
penalty, while the transmission
provider distributes the revenues to
non-offending transmission customers.
861. The Commission requires the
transmission provider to make an
annual compliance filing and to propose
in that filing a mechanism through
which it will identify non-offending,
transmission customers and a method
by which it will distribute the
unreserved use penalties revenue it
receives to the identified transmission
customers. This rule is consistent with
our determination regarding the
distribution of imbalance penalties. The
transmission provider must also
indicate in its compliance filing how it
will distribute late study penalties to
unaffiliated transmission customers. In
addition, the transmission provider is
required to make an annual filing with
the Commission, described further
below, that provides information
regarding the penalty revenue the
transmission provider has received and
distributed. We will not allow the
transmission provider to make an
annual filing to propose a distribution
method for unreserved use and late
study penalties, as proposed in the
NOPR. We agree with Ameren that
restricting the transmission provider to
proposing a distribution method
through the transmission provider’s
compliance filing will reduce the
administrative burden of distributing
operational penalties. We believe that
we can accomplish the goals underlying
a mandatory annual filing to propose a
distribution method—to detect
inappropriate penalties and failure to
penalize the transmission provider’s
affiliates—by requiring an annual
informational filing. As suggested by
Seattle, compliance monitoring and
enforcement by Commission staff will
provide a measure of assurance that the
transmission provider appropriately
assesses penalties.
862. All point-to-point and network
transmission customers, including the
transmission provider’s native load, will
be eligible to receive a portion of the
penalty revenues distributed by the
transmission provider. As a result, we
will not adopt MidAmerican’s proposal
that we exclude short-term firm and
non-firm transmission customers to
reduce the burden to the transmission
provider. Given the steps we have taken
to manage the transmission provider’s
burden of distributing penalty revenues,
we believe it more equitable to allow all
transmission customers subject to
operational penalties to be eligible to
receive a portion of the distributed
penalty revenues. In response to TVA’s
suggestion that the amount of any such
operational penalties be credited against
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the transmission provider’s
transmission revenue requirement, we
note that the transmission provider is
free to propose this mechanism, with
assurances that offending customers
will not benefit, and we will decide the
appropriateness of the proposal on a
case-by-case basis.
863. We agree with those commenters
that assert that the transmission
provider must be made whole before it
distributes any penalty revenues. With
regard to unreserved use penalties, we
will allow the transmission provider to
retain the base firm point-to-point
transmission service charge, but require
it to distribute any revenue collected
above the base firm point-to-point
transmission service charge. For
instance, if a transmission customer has
unreserved use that results in a penalty
equal to twice the rate for firm weekly
point-to-point service, then the
transmission provider can retain an
amount equal to the rate for firm weekly
point-to-point transmissions service. A
transmission provider will be required
to distribute the entire amount it pays
for completing service request studies
on an untimely basis.
864. We will not require transmission
providers that make an annual
compliance filing to use a standard
template, as suggested by Nevada
Companies. Transmission providers are
in the best position to determine the
least burdensome way to present the
information required. We will provide
guidance, however, on the information
that transmission providers must
provide in their annual informational
filings. Transmission providers must
provide: (1) A summary of penalty
revenue credits by transmission
customer, (2) total penalty revenues
collected from affiliates, (3) total penalty
revenues collected from non-affiliates,
(4) a description of the costs incurred as
a result of the offending behavior, and
(5) a summary of the portion of the
unreserved penalty revenue retained by
the transmission provider.
865. Transmission providers are
prohibited from recovering for
ratemaking purposes or through any
service under the Commission’s
jurisdiction any amount it or an affiliate
pays as an operational penalty. This will
ensure that the transmission provider
faces a true financial consequence when
it or an affiliate incurs an operational
penalty.
c. Applicability of Operational Penalties
Proposal to RTOs and Other
Independent or Non-Profit Entities
866. The Commission did not address
the degree to which RTOs and other
independent entities would be subject
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to operational penalties in section V.C.4
(Operational Penalties) of the NOPR. For
the most part, the discussion in that
section of the final rule addressed how
a transmission provider should
distribute operational penalties it incurs
when it takes transmission service
under its own tariff. In the section V.D.5
(Acquisition of Transmission Service) of
the NOPR, the Commission separately
addressed whether RTOs should pay
operational penalties for failure to
complete request studies on a timely
basis.
Comments
867. Several RTOs and RTO members
asked that the Commission clarify that
RTOs are not subject to any operational
penalties.532 Entergy opposes the
Commission’s proposal to assess
operational penalties against non-RTO
transmission providers, but not RTOs.
However, if the Commission maintains
this distinction, Entergy asks that it
clarify that independent entities—such
as Entergy’s Independent Coordinator of
Transmission—and the transmission
providers that allow independent
entities to process transmission service
requests will have the same protection
from operational penalties as RTOs. PGP
argues that, in the case of non-profit
transmission providers, requiring the
transmission provider to pay ‘‘nonoffending’’ customers when the provider
incurs operational penalties is selfdefeating, because there is no one other
than the customers to bear the cost of
the penalty. PGP cites Bonneville as an
example and notes that Bonneville must
recover all costs from its customers.
Commission Determination
868. This section of the Final Rule
primarily addresses how transmission
providers should distribute operational
penalties they incur when taking
transmission service under their own
tariff. RTOs and independent
transmission coordinators do not take
transmission service, so most of the
discussion in this section of the Final
Rule is simply not applicable to either
RTOs or independent transmission
coordinators. RTOs and independent
transmission coordinators are bound
however by the requirement to
distribute revenues they receive when
they assess operational penalties. We
address whether RTOs or independent
transmission coordinators are subject to
operational penalties due to processing
transmission service request studies on
an untimely basis in section V.C.5.a of
this Final Rule. We address whether
532 E.g., ISO New England, PJM, MISO, SPP, and
Ameren.
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RTOs are subject to civil penalties in
section 0 of this Final Rule.
869. We do not agree with those
arguing that a non-profit transmission
provider should be exempt from the
requirement to distribute unreserved
use penalties it pays when taking
service under its own tariff. To the
extent that a not-for-profit transmission
provider incurs an operational penalty
as a result of its activities as a
transmission customer, it is still
required to distribute penalties to nonoffending customers. A non-profit
transmission provider would only incur
an operational penalty as the result of
its wholesale marketing operations. As
such, a non-profit transmission provider
would pay for any operational penalty
it incurs by using the profit it has
earned through its wholesale marketing
operations.
6. ‘‘Higher of’’ Pricing Policy
870. As noted in the NOPR, the
Commission is concerned that some
transmission providers may not be
applying our existing pricing policies
consistently and, as a result, customers
may be quoted prices that are not
consistent with the ‘‘higher of’’
policy.533 The practice of quoting
customers an incremental rate as a lump
sum payment is inconsistent with our
ratemaking policy and has the potential
to discourage customers from
proceeding with service requests.534
Under the Commission’s ‘‘higher of’’
pricing policy, when the requested
transmission service requires network
upgrades, the transmission provider
should calculate a monthly incremental
cost transmission rate using the revenue
requirement associated with the
required upgrades and compare this to
the monthly embedded cost
transmission rate, including the
expansion costs.535 This incremental
rate should be established by amortizing
the cost of the upgrades over the life of
the contract.536
533 In Order No. 888, the Commission stated that
system expansions should be priced at the higher
of the embedded cost rate (including the expansion
costs) or the incremental cost rate, consistent with
the Transmission Pricing Policy Statement. See
Inquiry Concerning the Commission’s Pricing Policy
for Transmission Services Provided by Public
Utilities Under the Federal Power Act, Policy
Statement, 59 FR 55031 at 55037 (Nov. 3, 1994),
FERC Stats. & Regs. ¶ 31,005 at 31,146 (1994), order
on reconsideration, 71 FERC ¶ 61,195 (1995)
(Transmission Pricing Policy Statement).
534 Southwest Power Pool, Inc., 100 FERC
¶ 61,096 (2002) (designing a rate to include a
balloon payment is not a substitute for a properly
designed rate).
535 Southwest Power Pool, Inc., 112 FERC
¶ 61,319 at P 33 (2005).
536 See Southwest Power Pool, Inc., 98 FERC
¶ 61,256 at 62,026, reh’g denied in pertinent part,
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NOPR Proposal
871. As a result of the Commission’s
concerns regarding application of the
‘‘higher of’’ pricing policy, the
Commission sought comments in the
NOPR on whether changes to the pro
forma OATT are necessary to ensure
that incremental cost transmission rates
are presented as monthly rates for
service.
Comments
sroberts on PROD1PC70 with RULES
872. Several commenters agree that
incremental cost rates must be
expressed as monthly rates, but do not
believe that imposing this requirement
requires changes to the pro forma
OATT.537 To ensure transparency,
Bonneville recommends that
transmission providers post on their
OASIS the methodology used to
calculate incremental rates. APPA
suggests that the Commission simply
state in the preamble to the Final Rule
that the transmission provider must
include a proposed incremental rate in
its offer of service.
873. Other commenters see no need
for clarification at this time. Southern
states that it is not aware of problems
regarding the calculation of incremental
rates. Southern requests that the
Commission consider allowing
deviations to the Commission’s ‘‘higher
of’’ pricing policies and to allow all
transmission providers, not just RTOs,
to utilize participant funding.
MidAmerican suggests the Commission
defer consideration of possible changes
to the pro forma OATT regarding this
issue until the Commission undertakes
comprehensive transmission pricing
reform.
874. Other commenters support
changes to the pro forma OATT that
will ensure that incremental costs are
presented as monthly rates for
service.538 EPSA suggests that the Final
Rule include an example of an
appropriate monthly revenue
requirement calculation and the
upgrade costs included in the monthly
rate. Suez Energy NA supports this
proposed change but requests that the
transmission provider be required to
provide in a clear format the existing
transmission rate, the lump sum cost of
the upgrades, and the incremental rate.
100 FERC ¶ 61,096 (2002) (‘‘We agree with SPP that
the amortization period for upgrade costs should
match the contract period * * * As the customer
is only obligated to take service for the term of the
contract, it is reasonable that the costs only be
amortized over the term of the contract.’’).
537 E.g., APPA, Bonneville, and Public Power
Council.
538 E.g., ELCON, Constellation, FirstEnergy,
NorthWestern, PGP, TDU Systems.
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875. Some commenters ask the
Commission to further clarify, or
establish additional requirements,
regarding incremental rates. Entegra
states that the incremental rate should
be stated as both a monthly unit rate
and a lump sum representing the net
present value of the upgrade costs with
all inputs and assumptions in the
calculation disclosed. Entegra further
contends that the customer should be
allowed to choose between paying the
incremental rate, the lump sum, or some
combination of the two (e.g., to pay an
incremental rate over some period of
time and then to pay the balance of the
upgrade costs as a lump sum). While
Morgan Stanley supports the
Commission’s clarification that the
transmission provider may not demand
a lump sum payment as a condition of
providing the requested service, it asks
that transmission providers not be
precluded from offering a lump sum
payment option, or any other mutually
agreeable approach, to customers.
876. MidAmerican, EEI and
Allegheny recommend that the
Commission clarify that the
transmission provider is not currently
limited to charging the customer the rate
per MW-month specified in the facilities
study for the entire term of service if the
customer pays the incremental cost of
the network upgrades. These
commenters explain that the
transmission provider’s revenue
requirement with respect to the
incremental cost of network upgrades
will vary over the customer’s term of
service in the same way as its embedded
cost of service will vary, including the
cost of capital, operations and
maintenance expense and
administrative and general expense. EEI
argues that the transmission provider
should have the same right to modify a
rate based on incremental costs
pursuant to section 205 that it has to
modify embedded cost rates and that the
transmission provider should be
permitted to present an incremental cost
rate as a formula rate.
877. Seattle states that incremental
costs may require more rigorous
treatment than simply stating a monthly
rate, since the cost of expansion is very
path specific and often the expansion
will affect multiple beneficiaries.
According to Seattle, the ‘‘higher of’’
pricing policy will often hinge on
contestable assumptions regarding the
beneficiaries of discrete expansion
projects and the grey area that separates
reliability related aspects of new
transmission projects from projects
intended to provide commercial
benefits.
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12377
878. Great Northern requests that the
Commission clarify that a transmission
customer may adjust the term of its
requested transmission service contract
to provide a longer period for
amortizing the cost of necessary system
upgrades once the incremental cost of
expansion is disclosed by the
transmission provider, as the
Commission seems to suggest in the
NOPR.539 In contrast, Allegheny states
that the amortization period for the cost
of an upgrade should not exceed the
requested term of the contract, even if
exercise of the rollover option by the
customer is anticipated because
transmission providers must have
assurances of cost recovery for upgrades
necessitated by customer decisions.
879. TAPS and EEI recommend that
the Commission modify sections 19.3
and 19.4 of the pro forma OATT to
specify that the transmission provider
must present the incremental costs of
transmission service on a $/MW month
basis contemporaneous with providing
the facilities study to the customer.
TAPS further states that similar changes
should be made to sections 32.3 and
32.4 of the pro forma OATT, to ensure
that network customers are not scared
off by inappropriate presentations of
network upgrade costs. TAPS explains
that, while more complex, it believes
that ‘‘higher of’’ pricing can work in the
context of network service if applied in
a comparable manner to the
transmission provider’s treatment of the
upgrades needed for service to its retail
native load.540
880. ISO New England and PJM state
that the Commission’s pricing concerns
are not present for their respective
markets and, therefore, any rule
promulgated in this proceeding should
not apply to these RTOs.
881. TAPS argues that
creditworthiness or security
requirements associated with network
upgrades for a transmission customer
(in sections 19.4 and 32.4 of the pro
forma OATT) must be distinguished
from the incremental cost or pricing of
the upgrade. Otherwise, the customer
may mistake a demand for security for
a request for upfront payment of the
entire cost of the upgrade.
882. In reply comments, EEI states
that it continues to support the
Commission’s proposed modification to
the way in which the transmission
539 See NOPR at P 285 (‘‘Presenting the
incremental charge in the form of a monthly rate
allows a customer seeking a lower rate to choose to
request a longer transaction term.’’).
540 Citing Midwest Indep. Transmission Sys.
Operator, Inc., 109 FERC ¶ 61,085, P 57 (2004)
(applying Order 2003 crediting mechanism to
network customers).
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provider presents information on the
incremental cost of network upgrades
and asserts that nothing in the initial
comments justifies a change in the
Commission’s policies with respect to
the pricing of transmission service. EEI
states that changes in transmission
pricing policy, such as NRECA’s
proposal to require rolled-in pricing for
network customers and TAPS’s proposal
to exempt network customers from
security for the payment of costs related
to network upgrades, are outside the
scope of this proceeding.
sroberts on PROD1PC70 with RULES
Commission Determination
883. In the NOPR, the Commission
sought comments on the narrow issue of
whether changes to the pro forma OATT
are necessary to ensure that, consistent
with our ‘‘higher of’’ policy, incremental
cost transmission rates are presented as
monthly rates for service. The
Commission did not propose any
changes to the underlying pricing
policy. Commenters’ proposals to
change or clarify the Commission’s
transmission pricing policy are therefore
outside the scope of this proceeding.541
Other comments are directed toward the
application of our ‘‘higher of’’ policy in
individual cases. These include the
comments of Seattle (on the need to
accurately identify the beneficiaries of
the network upgrades), TAPS (on the
use of ‘‘higher of’’ pricing in the context
of network service), and EPSA (asking
the Commission to present an example
calculation of costs and rates). We will
not address those comments here
because they involve issues that are
largely fact-specific that are best
addressed on a case-by-case basis.
884. Based on the remaining
comments received, the Commission
concludes that changes to the language
of the pro forma OATT to address this
matter are not needed at this time. We
believe that the existing pricing policy
provides sufficient information for
transmission customers to make an
informed decision regarding a request
for service.542 Transmission providers
must continue to include a proposed
monthly incremental rate with their
offer of service whenever the
transmission provider proposes to
charge the customer an incremental rate,
541 Comments that fall into this category include
those of Entegra, Suez Energy NA, Morgan Stanley,
MidAmerican, EEI (regarding the right to modify
incremental rates) and Allegheny.
542 Because the Commission declines to adopt
changes to the pro forma OATT regarding the
‘‘higher of’’ pricing policy, the requests of ISO New
England and PJM to exempt ISOs and RTOs from
tariff changes related to that policy are moot.
Procedures regarding implementation of the Final
Rule by ISOs and RTOs are otherwise discussed in
section IV.C.
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as well as cost support indicating the
derivation of the rate calculation
consistent with the cost support that the
transmission provider would provide to
the Commission in a section 205 rate
filing. Because transmission providers
are required to explain the calculation
of their incremental rate, we conclude
that the transmission provider need not
post on its OASIS the calculation
methodology, as recommended by
Bonneville. Similarly, in response to
TAPS’s concern about security
payments, the transmission provider’s
explanation should allow the customer
to clearly distinguish between any
security requirements associated with
the service and the incremental cost of
the service.
885. We will not adopt Great
Northern’s recommendation to require
the transmission provider to permit the
customer to opt for a longer contract
term (to obtain a longer amortization
period and a lower rate) once the
incremental cost of the upgrades has
been determined. The specific upgrades
required to provide transmission service
may depend on the time period over
which the service is provided; therefore,
allowing the customer to opt for a longer
contract term may trigger a need for
additional, or different, upgrades.
7. Other Ancillary Services
886. Other than the pricing of
imbalances, the NOPR did not address
pricing issues related to ancillary
services required under the pro forma
OATT. A few commenters nonetheless
proposed revisions to the pro forma
OATT regarding the pricing and
procurement of, and other issues related
to, ancillary services.
a. Demand Response
Comments
887. Alcoa submits that load
resources (i.e., demand response)
should be permitted to self-supply and,
under certain circumstances, sell
ancillary services to third parties. Alcoa
states that large customers such as
aluminum smelters are capable of
providing, for themselves and third
parties, some ancillary services so long
as they are not required to subrogate
their aluminum business functions to
the needs of the ancillary service
markets. In Alcoa’s view, demand
resources such as Alcoa’s smelter loads
should be appropriately compensated as
providers of ancillary services,
recognizing their ability to contribute
significantly to the operational
flexibility of energy markets and the
stability of the grid. Alcoa asserts that
industrial loads’ contribution to the
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reliability of the grid was demonstrated
during the August 2003 Blackout, when
Alcoa’s smelters remained in operation
and facilitated the restoration of the
system. Accordingly, Alcoa asks the
Commission to require transmission
providers to recognize that demand
response resources can be a substitute
for ancillary services such as Energy
Imbalance, Operating Reserve and
Spinning Reserve.
Commission Determination
888. With respect to Alcoa’s concern
regarding a transmission customer’s
own use of ancillary service, we note
that the existing pro forma OATT
requires transmission providers to
permit transmission customers to
purchase ancillary services from third
parties or make alternative comparable
arrangements for the provision of all
ancillary services except for scheduling,
system control and dispatch service and
reactive supply and voltage control
service. Regarding the sale of other
ancillary services including energy
imbalance, operating reserve and
spinning reserve by load resources, we
agree that such sales should be
permitted where appropriate on a
comparable basis to service provided by
generation resources. Comparable
treatment of load resources is consistent
with Staff’s August 2006 Assessment of
Demand Response & Advanced
Metering Report 543 as well as
provisions of EPAct 2005.544 We note
that some RTOs and ISOs already allow
demand response resources to
participate in certain ancillary services
markets, while participation of such
resources in other ancillary services
markets is being studied. We therefore
modify Schedules 2, 3, 4, 5, 6, and 9 of
the pro forma OATT to indicate that
Reactive Supply and Voltage Control,
Regulation and Frequency Response,
Energy Imbalance, Spinning Reserves,
Supplemental Reserves and Generator
Imbalance Services, respectively, may
be provided by generating units as well
543 In the Demand Response Report, staff
recommended that federal and state regulators
consider whether to allow appropriately designed
demand response resources to provide all ancillary
services including spinning reserve, regulation, and
any new frequency responsive reserves. Demand
Response Report at 97–100.
544 Section 1252 (f) of EPAct 2005 states: ‘‘It is the
policy of the United States that time-based pricing
and other forms of demand response, whereby
electricity customers are provided with electricity
price signals and the ability to benefit by
responding to them, shall be encouraged, the
deployment of such technology and devices that
enable electricity customers to participate in such
pricing and demand response systems shall be
facilitated, and unnecessary barriers to demand
response participation in energy, capacity and
ancillary service markets shall be eliminated.’’
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as other non-generation resources such
as demand resources where appropriate.
b. Procurement and Pricing of Ancillary
Services Generally
sroberts on PROD1PC70 with RULES
Comments
889. Steel Manufacturers Association
contends that the pro forma OATT’s
approach to other generation-based
ancillary services should recognize that
regional ancillary services markets do a
better job of ensuring system reliability
and holding down ancillary services
costs than ancillary services provided
on a control area by control area basis.
Steel Manufacturers Association cites to
MISO and SPP reports that provide
evidence that ancillary services
provided across large geographical
regions are more effective and
economical than when those services
are provided by single utilities. For
example, Steel Manufacturers
Association notes that the SPP report
concluded that, if a single Area Control
Error were used for SPP, energy used for
regulation service could be reduced by
approximately 30 percent. Steel
Manufacturers Association contends
that, although ancillary services markets
in the organized markets have proven
successful at ensuring reliability and at
keeping ancillary services costs low and
predictable, utilities outside of the RTO
and ISO markets continue to provide
ancillary services primarily from their
own limited pools of generation
resources.
890. Occidental and Steel
Manufacturers Association propose that
transmission providers should be
required, if feasible, to competitively
procure ancillary service products if
there are suppliers of such services
other than the vertically integrated
merchant function. Occidental argues
that such procurement will result in just
and reasonable rates for these
generation-related ancillary services that
reflect their cost-effective market-based
competitive supply. In Occidental’s
view, competitive procurement of
ancillary services will also help assure
non-discriminatory treatment of
transmission customers since
transmission providers will have less
incentive to favor their merchant
function in the provision of generationrelated ancillary services. Occidental
notes that such procurement should be
conducted in a manner consistent with
reliability.
891. Alcoa argues that the
transmission provider’s costs of
providing ancillary services for the
network as a whole should not be
socialized on a MWh basis without
regard to the relative cost burden that
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specific customers impose on the
transmission system. Alcoa contends
that, while a particular consumer may
use a considerable quantity of energy,
the cost of serving that customer beyond
the per-unit energy cost may be much
less than it would be for other
individual customers or groups of
customers.
Commission Determination
892. The Commission recognizes that
there can be possible economic and
reliability benefits to larger geographic
markets for ancillary services, as
suggested by Steel Manufacturers
Association. However, as stated in the
NOPR and repeated above the purpose
of this rulemaking is to strengthen the
pro forma OATT to ensure that it
achieves its original purpose—
remedying undue discrimination—not
to create new market structures or, as
proposed here, to modify existing
market structures. We do not believe
that altering the scope of the current
ancillary services markets is needed to
remedy undue discrimination at this
time.
893. Similarly, we conclude that a
fundamental overhaul of the current
procurement and pricing of ancillary
services, as proposed by Occidental and
Steel Manufacturers Association, is
beyond the scope of this proceeding.545
The pro forma OATT already permits
transmission customers to make
alternative arrangements to satisfy
certain of their ancillary services
obligations. Therefore, transmission
customers are free to seek out
competitive providers for those
ancillary services other than scheduling,
system control and dispatch service and
reactive supply and voltage control
service from third party suppliers. We
also find Alcoa’s contention that the
transmission provider’s costs of
providing ancillary services for the
network as a whole should not be
socialized on a MWh basis without
regard to the relative cost burden that
specific customers impose on the
transmission system, to be beyond the
scope of this Final Rule.
c. Pricing and Procurement of Reactive
Power
Comments
894. Several commenters 546 suggest
that the Commission consider the need
545 We note, however, that the rates charged for
these ancillary services must be just and reasonable
under the Commissions standard of review. Thus,
if less expensive options to supply ancillary
services (including from demand side resources) are
available, we would expect the transmission
provider to examine such options.
546 E.g., SPP, Alcoa, and Occidental.
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12379
for reform of the methods of
compensation for the provision of
reactive power.
895. Alcoa argues that ancillary
services pricing should recognize the
efficiency contributions made by load as
a result of their demand response
capabilities and the contribution that
load located near generators makes to
the provision of reactive power in
particular. Alcoa states that the
localized supply of reactive power near
load centers can alleviate transmission
constraints and allow cheaper real
power to be delivered into a load center,
as the provision of such reactive power
increases the available flow for real
power between two points. Alcoa argues
that the pro forma OATT should
recognize and credit the manner in
which certain loads’ location and load
profile allows for the provision of
reactive power and contributes to real
power transfer capability.
896. Occidental objects to the existing
requirement that transmission
customers purchase reactive power
service from the transmission provider,
arguing that numerous independent
generators provide reactive supply and
voltage control to support transmission
service in competitive wholesale
markets. Occidental states that the
Commission should formalize the policy
of compensating generators on a
comparable, non-discriminatory basis
for several ancillary services,
particularly providing reactive power
capability, by requiring changes to the
pro forma OATT to mirror the changes
accepted by the Commission to the PJM
and MISO tariffs. Occidental contends
that amending the pro forma OATT to
formalize this policy would be
consistent with the FPA and achieving
non-discriminatory access to
transmission. Occidental notes that PJM
and MISO amended their tariffs to
provide equal compensation to affiliated
and non-affiliated generators based on
the generation owner’s monthly revenue
requirement for reactive supply and
voltage control as accepted by the
Commission. Occidental also notes that,
when addressing generator
interconnection agreements in Order
No. 2003–A, the Commission stated that
‘‘if the Transmission Provider pays its
own or its affiliated generators for
reactive power within the established
[power factor] range, it must also pay
[the interconnecting, independent
generator].’’ 547
897. SPP requests that the
Commission reform its reactive power
pricing methodology, which has grown
547 See
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out of AEP Serv. Corp.548 SPP contends
that the Commission can reduce
uncertainty and litigation surrounding
the pricing of reactive power by acting
generically in a rulemaking rather than
causing the industry to litigate reactive
power pricing issues on a case-by-case
basis. SPP argues that, based on its
studies, it does not expect to call upon
IPPs to provide reactive power; and
therefore, it should not be required to
pay for reactive power. SPP questions
whether paying all IPPs a reservation
charge, regardless of any determination
of need or of the location of the plant
and the locational need for reactive
power, provides the appropriate siting
incentives. SPP contends that the
Commission can reduce the uncertainty
and litigation by acting generically
rather than causing the industry to fully
litigate these issues in numerous cases
before various courts. In addition, SPP
challenges whether the AEP pricing
method for reactive power continues to
be appropriate. SPP suggests the
Commission consider alternative pricing
options, such as: Tying compensation to
the actual provision of reactive power;
eliminating compensation for the
ninety-five percent leading/lagging band
contained in most interconnection
agreements, as such costs may be
considered as a cost of interconnection
and included in the power sales price;
or, allowing compensation only outside
of the band or perhaps when a sale is
displaced.
sroberts on PROD1PC70 with RULES
Commission Determination
898. In Order No. 2003 et al., the
Commission found that interconnection
customers must be treated comparably
with the transmission provider and its
affiliates in terms of reactive power
compensation. The Commission
required the transmission provider to
pay interconnecting generators for
providing reactive power within the
specified range if the transmission
provider so pays its own generators or
those of its affiliates.549 Commenters
seeking reform of the methods of
compensation for the provision of
reactive power have not demonstrated
that such reforms are needed at this
time to remedy undue discrimination or
that the current compensation method
does not provide a comparable result.
Accordingly, we do not believe that
acting generically on pricing reactive
power is needed at this time and we
will continue to resolve compensation
issues for reactive power to qualifying
548 Opinion
549 See
No. 440, 88 FERC ¶ 61,141 (1999).
Order No. 2003–B at P 119.
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generators on a case-by-case basis based
on the circumstances presented.
899. In response to SPP’s specific
proposals for the treatment of reactive
power, we note that the Commission
recently found that it is unduly
discriminatory and non-comparable for
SPP to apply a ‘‘needs’’ test to reactive
power capability for independent power
producers to receive compensation that
is not also applied to all other
generating plants in its vicinity.550 The
Commission also found that parties may
make a separate FPA section 205 filing
with the Commission with criteria,
applied comparably and prospectively,
that would determine which generators
would receive reactive power
compensation.
900. Finally, Alcoa’s assertion that
certain loads’ location and load profile
allows for the provision of reactive
power to the transmission system is
consistent with Staff’s February 2005
report, Principles for Efficient and
Reliable Reactive Power Supply and
Consumption,551 as well as the abovecited provisions of EPAct 2005. As
previously discussed, we have modified
Schedule 2 of the pro forma OATT to
allow for the provision of Reactive
Supply and Voltage Control from
demand resources where appropriate.
D. Non-Rate Terms and Conditions
1. Modifications to Long-Term Firm
Point-to-Point Service
a. Planning Redispatch and Conditional
Firm Options
901. The current pro forma OATT
requires the transmission provider to
provide two types of redispatch service:
Planning redispatch and reliability
redispatch.552 Planning redispatch is a
product that Order No. 888 required
550 See Calpine Oneta Power, L.P., 116 FERC
¶ 61,282 (2006).
551 See Staff Report: Principles of Efficient and
Reliable Reactive Power Supply and Consumption
(Docket No. AD05–1–000), available at https://
www.ferc.gov/EventCalendar/Files/
20050310144430–02–04–05-reactive-power.pdf.
Staff noted that in many cases load response and
load-side investment could reduce the need for
reactive power capability in the system and that
increasing reactive power at certain locations
(usually near a load center) can sometimes alleviate
transmission constraints and allow cheaper real
power to be delivered into a load pocket. See id.
at 4, 108. The report also noted that distributed
generators have the same reactive power
characteristics as large generators, with both
producing dynamic reactive power, and that the
amount of reactive power does not necessarily
decrease when voltage decreases. Id. at 27.
552 In Order No. 888, the Commission referred to
planning redispatch as economic redispatch. Here
we avoid the term economic redispatch because in
the last ten years it has taken a different meaning
in the industry and because we will no longer
require that planning redispatch be capped at the
cost of expansion.
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transmission providers to use, in certain
circumstances, to create additional
transmission capacity to accommodate a
request for firm transmission service.
Specifically, the existing pro forma
OATT requires the transmission
provider to expand or upgrade its
transmission system or, if it is more
economical, plan to redispatch its
resources to provide requested firm
point-to-point service, provided
redispatch does not (1) degrade or
impair the reliability of service to native
load customers, network customers and
other transmission customers taking
firm point-to-point service or (2)
interfere with the transmission
provider’s ability to meet prior firm
contractual commitments to others.553
The transmission provider must first
identify planning redispatch options in
the system impact study in conjunction
with identifying relevant system
constraints that impact the service
request.554 When a system impact study
and facilities study identify planning
redispatch as a more economical means
of relieving a transmission constraint
than a transmission upgrade, the
customer is obligated to pay the costs of
redispatch consistent with Commission
policy.
902. Reliability redispatch is required,
when feasible, to relieve system
constraints that would otherwise cause
curtailment of the network customer or
transmission provider loads. To provide
reliability redispatch, the transmission
provider redispatches all network
resources and transmission provider
resources on a least-cost basis. The
transmission provider and network
customers each pay a load ratio share of
these redispatch costs.555
NOPR Proposal
903. In the NOPR, the Commission
stated its belief that current practices for
evaluating long-term firm point-to-point
service may not be comparable to the
manner in which transmission service is
planned for bundled retail native load
and may no longer be just, reasonable
and not unduly discriminatory. The
Commission described two potential
solutions: modifications to the planning
redispatch provisions and conditional
firm point-to-point service.556 The
Commission proposed to modify the
existing planning redispatch option by
(1) accelerating the study of planning
553 See
pro forma OATT section 13.5.
pro forma OATT section 19.3.
555 See pro forma OATT sections 33.2–33.3.
556 Conditional firm point-to-point service
(hereinafter conditional firm service) and planning
redispatch point-to-point service (hereinafter
planning redispatch service) are options available
under long-term firm point-to-point service.
554 See
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redispatch in the transmission request
study process, (2) requiring an estimate
of the number of hours of redispatch
that may be required to accommodate
the requested service, (3) requiring a
preliminary estimate of the cost of
planning redispatch, and (4) pricing
planning redispatch services to facilitate
increased availability of the service.557
The Commission suggested that
conditional firm service could also be
used to accommodate additional
transactions, defining the service as a
form of firm point-to-point service that
includes less-than-firm service in a
defined number of hours of the year
when firm point-to-point service is
unavailable. The Commission sought
comment on its preliminary view that
planning redispatch is the superior
option because, in part, it is comparable
to the way the transmission provider
plans for bundled retail native load.
904. The Commission’s October 12
Technical Conference focused, among
other things, on issues related to the
planning redispatch and conditional
firm proposals in the NOPR. On
November 15, 2006, the Commission
issued a notice (November 15 Notice)
requesting supplemental comments on a
transparent redispatch proposal
submitted by Transparent Dispatch
Advocates (TDA proposal) and certain
aspects of the conditional firm
option.558 The Commission also
requested comments regarding the
conditional firm option, including
whether it is a complementary service to
planning redispatch, whether it should
be available for all long-term requests or
limited to a request where the customer
agrees to pay for upgrades, potential
modeling problems, and requirements
for defining the conditions under which
the service would be curtailable.559
sroberts on PROD1PC70 with RULES
Comments
905. Some commenters agree with the
Commission’s preference for
modifications to planning redispatch
over development of conditional firm
service.560 They state that the attributes
of conditional firm service are not
clearly defined and key implementation
557 The Commission did not propose to modify
the reliability redispatch provisions that exist in the
network integration transmission sections of the pro
forma OATT.
558 The following summary reflects comments
received as initial and reply comments to the
NOPR, as well as supplemental comments received
in response to the November 15 Notice. Some
commenters have changed their positions over time
and these summaries reflect the most recent
position expressed by commenters.
559 Questions relating to the TDA proposal are
discussed later in this section.
560 E.g., Exelon, FirstEnergy, ELCON,
MidAmerican, Arkansas Commission, MISO, and
East Texas Cooperatives.
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issues are unresolved. They state that
using planning redispatch to the
maximum degree feasible, while not
interfering with reliability, is inherent
in maximizing the efficient use of the
transmission system and should be fully
evaluated before undertaking expensive
expansion of the transmission system.
Other commenters state that conditional
firm service will create significant
complications for transmission
providers and disincentives to build
transmission in exchange for limited
and questionable benefits for new pointto-point customers or LSEs.561 EEI,
Indianapolis Power and Ameren express
doubt that customers would agree to be
curtailed during peak usage periods. In
response, AWEA contends that existing
resources serving load would be able to
manage curtailment risks so long as they
could reasonably predict the curtailed
hours.
906. Most independent power
producers and a few other entities
support the inclusion of both services in
the pro forma OATT, stating that the
services are required to remedy undue
discrimination and provide for
comparable transmission service.562
Western Governors believe that the
planning redispatch and conditional
firm options are important to fully use
the existing transmission grid and to
enable new intermittent generation
resources to reach markets. To build the
case for transmission expansion, the
Western Governors argue, it is important
to demonstrate that the existing grid is
being effectively utilized; approval of
both options will help make this
necessary demonstration. EPSA and
AWEA state that, while they believe
transmission providers should be
required to offer both services,
conditional firm service may be simpler
and less costly to implement because it
involves the transmission provider
directing the customer to turn off its
resources during a contingency.
Similarly, Bonneville suggests that
conditional firm service is a reasonable
alternative to planning redispatch where
a transmission provider cannot provide
both options. Commenters state that the
Commission should require
transmission providers to offer
conditional firm service and planning
redispatch and allow customers to
choose the option that best suits the
561 E.g., EEI, Indianapolis Power, Ameren, and
Northwest IOUs.
562 E.g., EPSA, AWEA, Entegra, BP Energy,
Newmont Mining, Sempra Global, Suez Energy NA,
PPM, Utah Municipals, Williams, Morgan Stanley,
PPL, Project for Sustainable FERC Energy Policy,
California Commission, CREPC, TranServ, South
Carolina E&G, Constellation, Barrick Supplemental,
Xcel Supplemental, and Bonneville Supplemental.
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12381
physical, commercial and economic
circumstances of the request.563
907. On the other hand, many
commenters argue that the Commission
should not require either option because
the services are unnecessary,
operationally unworkable, and legally
unjustified, or because they would harm
reliability and the quality of existing
network service and provide
disincentives for transmission
investment.564 Several commenters state
that these services would make
curtailments of existing firm service
more likely and limit opportunities for
use of secondary network service,
thereby harming native load protections
and reducing reliability, contrary to FPA
sections 215 and 217 respectively.565
Others opposing both options put forth
primarily reliability, cost causation and
comparability arguments. For example,
Duke states that the two options are
antithetical to reliable grid operation
because they would require a
transmission provider to grant a longterm request with the prior knowledge
that it cannot be accommodated.
International Transmission states that
the grid is already operating at capacity
and that requiring the transmission
provider to accommodate additional
megawatt-hours of service during
periods of system stress would increase
the likelihood of system failure. While
it recognizes that conditional firm
service has been successful in parts of
the Western Interconnection, NRECA
contends a mandate would undermine
responsible planning and expansion of
the transmission grid by harnessing the
transmission provider’s planning and
dispatch functions to frame more and
more elaborate service conditions for
conditional firm service. APPA,
Southern and Progress Energy argue that
both services may require adoption of a
form of organized LMP market, an
action that raises significant political
opposition and would be contrary to the
Commission’s commitment in the NOPR
to avoid such restructuring. Similarly,
other commenters contend that the
planning redispatch option is only
appropriate for transmission providers
who are members of an RTO, ISO or
563 E.g., California Commission Supplemental,
Williams Supplemental, Constellation
Supplemental, and Barrick Supplemental.
564 E.g., Ameren, Duke, Entergy, Imperial,
International Transmission, LPPC, Progress Energy,
Santee Cooper, Salt River, Southern, Tacoma, TDU
Systems, Community Power Alliance, Northwest
IOUs, NorthWestern, NPPD, NRECA, Public Power
Council, TVA, SPP Reply, South Carolina E&G
Supplemental, E.ON Supplemental, MISO
Supplemental, and APPA Supplemental.
565 E.g., Duke, EEI, LPPC, NRECA, NPPD, Progress
Energy, Southern, Utah Municipals Reply, and
Duke Reply.
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who have an independent administrator
of their transmission system.566 Some of
the commenters that urge rejection of
both options state that a properly
structured conditional firm service is
preferable to the modified planning
redispatch service should the
Commission implement one of the
services.567
908. Several commenters prefer the
development of conditional firm service
over the modifications to the planning
redispatch service because of the
complexities surrounding redispatch
costs and protocols.568 For example, in
supplemental comments, EEI and
Community Power Alliance state that,
while not ideal, conditional firm service
would provide an opportunity to meet
customers’ transmission needs and is
preferable to Transparent Dispatch
Advocates’ redispatch proposal.569 They
also contend that the conditional firm
option would provide faster provision of
service and relative certainty of timing
and costs for a new customer and its
lenders, while ensuring reliability and
promoting infrastructure expansion, so
long as transmission providers are
permitted to work with their customers
to devise appropriate service
parameters. Entergy believes conditional
firm service can provide benefits to
transmission customers without unfairly
socializing costs to native load and
network customers of the transmission
provider. Overall, a majority of
commenters express support for some
form of conditional firm service.570
909. Several commenters argue that, if
the services are required, the
Commission should add to the services
the following requirements: The
services should not adversely affect
reliability and service to firm customers
or provide unduly preferential service to
point-to-point customers; the services
566 E.g., CREPC, TVA, and East Texas
Cooperatives.
567 E.g., EEI, Entergy, Ameren, Progress Energy,
Santee Cooper, TAPS, E.ON Supplemental, TDU
Systems Supplemental, LPPC Supplemental,
Tacoma Supplemental, and PNM–TNMP
Supplemental.
568 E.g., Manitoba Hydro, Nevada Companies,
Sacramento, Pinnacle, East Texas Cooperatives,
Barrick Reply, APPA Supplemental, Community
Power Alliance Supplemental, Entergy
Supplemental, and TAPS Supplemental.
569 Section V.D.1.b contains a summary and indepth discussion of the TDA proposal.
570 The following entities expressed some level of
support for conditional firm service: EPSA, AWEA,
Entegra, BP Energy, Newmont Mining, Sempra
Global, Suez Energy NA, PPM, Utah Municipals,
Williams, Morgan Stanley, PPL, Project for
Sustainable FERC Energy Policy, California
Commission, Western Governors, CREPC, TranServ,
Constellation, Manitoba Hydro, Nevada Companies,
Sacramento, Pinnacle, PNM–TNMP, Bonneville,
EEI, Entergy, Ameren, Progress Energy, Southern,
Santee Cooper, Seattle, LPPC, Salt River, and TAPS.
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should be an interim option until
transmission upgrades are in place to
provide firm service; and, planning
redispatch and conditional firm
customers should bear the actual costs
of the services received, including costs
associated with system operational
changes needed to accommodate the
services.571
910. A few commenters believe that
the Commission should allow for
regional differences in development of
the new services.572
Commission Determination
911. The Commission has determined
that modifications to the current
planning redispatch requirement and
creation of a conditional firm option are
both necessary for provision of reliable
and non-discriminatory point-to-point
transmission service. The planning
redispatch and conditional firm options
represent different ways of addressing
similar problems. They can be used to
remedy a system condition that occurs
infrequently and prevents the granting
of a long-term firm point-to-point
service. These options also can be used
to provide service until transmission
upgrades are completed to provide fully
firm service. Planning redispatch
involves an ex ante determination of
whether out-of-merit order generation
resources can be used to maintain firm
service. Conditional firm involves an ex
ante determination of whether there are
limited conditions or hours under
which firm service can be curtailed to
allow firm service to be provided in all
other conditions or hours. As we
explain below, both techniques are
currently used under certain conditions
by transmission providers to serve
native load and, hence, it is necessary
to make comparable services available
to transmission customers in order to
avoid undue discrimination.
912. We therefore find these options
are complementary services that can
remedy undue discrimination, facilitate
the provision of long-term transmission
service and provide customers with
greater flexibility in choosing resources
to meet their needs. There is support in
the comments for development of some
type of conditional firm service that
would allow for a longer-term use of the
grid when transmission is projected to
be unavailable for a small portion of the
year. Additionally, we note that both
options could help integrate new
571 E.g., EEI, Southern, TAPS, Seattle, APPA,
LPPC Supplemental, Tacoma Supplemental and
E.ON Supplemental. Issues related to pricing of
planning redispatch service are addressed in
paragraphs V.D.1.a.3.c below.
572 E.g., California Commission, PGP, Pinnacle,
and Imperial.
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generation more quickly. For example,
when there is a lag between the time
that a new generation resource becomes
operational and the time that
transmission upgrades can be built to
accommodate the resource, these
options allow power to reach customer
loads at an earlier date. This can be
particularly beneficial to renewable
resources, such as wind, that can be
constructed more quickly than the
transmission upgrades necessary to
deliver their power on a firm basis over
the long-run.
913. We recognize, however, that both
options raise reliability concerns. The
proposal in the NOPR for planning
redispatch service would require the
transmission provider to predict system
conditions for the term of the service
request, a task that becomes more
difficult, and hence less accurate, with
longer-term requests. This poses several
related problems. Because longer-term
forecasts are inherently uncertain and
the further into the future the forecasts,
the less accurate they are, the provision
of planning redispatch service can
threaten the reliability of service to
native load unless very conservative
assumptions are used. This incentive to
use conservative assumptions to protect
native load, in turn, increases the
likelihood that planning redispatch
service will be denied. This, in turn,
will increase the number of disputes as
to whether the denials were
discriminatory. Such disputes would
pose enforcement problems because
they will turn on long-term projections
regarding load growth, generation
resource additions, etc., that by
definition involve some degree of
subjectivity. Moreover, as we discuss
below, there is evidence suggesting that,
while transmission providers use
planning redispatch to serve native
load, they do not use it as a long-term
tool to avoid future upgrades
indefinitely.
914. In balancing the foregoing
considerations, the Commission will
modify the approach proposed in the
NOPR in two principal respects. First,
given the ability of both services to
address similar problems, we have
reconsidered the proposal that only one
of the options should be required. We
find that availability of both planning
redispatch and conditional firm in the
short-run is necessary to ensure that
competitive power suppliers have
comparable access to the grid. As
discussed below, we will continue to
require that transmission providers offer
to provide planning redispatch under
certain circumstances in which the
transmission providers determine that
there is insufficient ATC. If customers
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request study of planning redispatch,
transmission providers have an
obligation to seriously evaluate the
provision of planning redispatch from
their own resources and provide
customers with information on the
capabilities of other generators to
provide planning redispatch. If planning
redispatch is unavailable from the
transmission provider’s resources or
inadequate to meet customers’ needs,
transmission providers have an
independent obligation to offer
conditional firm, if available, as part of
the firm point-to-point service.573
Customers will have the choice of
whether to request study of the planning
redispatch option, the conditional firm
option or both.
915. Second, we will not impose a
planning redispatch or conditional firm
obligation over the long run. Such an
obligation is not, as described below,
necessary to remedy undue
discrimination and would otherwise
pose reliability problems, put the
transmission provider at risk for
estimating the costs of long-term
redispatch, and undermine incentives to
upgrade the transmission grid.
Therefore, we will limit the availability
of both service options so that their
duration is for a time period over which
service can be reasonably provided
without impairing reliability.574 This
limitation scales back the existing
planning redispatch requirement in
section 13.5 of the pro forma OATT that
could, in practice, allow for an openended obligation to provide planning
redispatch in lieu of upgrading the
transmission system (e.g., involving
forecasts up to 30 years).
916. We discuss in detail the
comparability and reliability findings
that support these decisions below.
(1) Comparability
sroberts on PROD1PC70 with RULES
NOPR Proposal
917. In the NOPR, the Commission
expressed its preliminary view that
current practices for evaluating longterm firm point-to-point service may not
573 Application of planning redispatch and
conditional firm service obligations to RTO and ISO
transmission providers is discussed in section
V.D.1.a.3.B.i below.
574 As explained in more detail below, we adopt
limitations that are tailored to the two types of
customers that may request the options. First, for
customers that agree to support the construction of
new transmission facilities, redispatch and
conditional firm point-to-point service will be
available as a bridge until such time as those
facilities are constructed and the relevant
conditions must be specified in the initial service
agreement and are not subject to change. Second,
for customers that do not agree to support the
construction of new facilities, the transmission
provider will be able to re-evaluate the conditions
under which services are provided every two years.
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be comparable to the manner in which
transmission service is planned for
bundled retail native load and may no
longer be just, reasonable and not
unduly discriminatory.575
Comments
918. Some commenters challenge the
Commission’s authority to order
planning redispatch or conditional firm
service as a remedy for potential undue
discrimination. EEI and others argue
that planning redispatch is not
necessary to eliminate actual or
perceived undue discrimination because
many transmission providers do not rely
on redispatch in planning to serve
native load.576 However, EEI also states
that when transmission providers do
incorporate redispatch into their system
planning, they do so generally only
when the cost of redispatch is lower
than the cost of network upgrades and
system reliability is not impacted. Some
transmission providers state that they
do not currently use planning
redispatch in lieu of transmission
construction in order to designate their
network resources.577 On the other
hand, Entergy and Southern state that
they currently use or have used
planning redispatch of their own
resources on the same basis that they
allow any network customer to
redispatch from the network customer’s
resources. For example, Southern states
that it has used the redispatch potential
of its generators during off-peak/
shoulder periods on an interim basis
until completion of transmission
upgrades to designate network resources
that otherwise might be
undeliverable.578 Entergy disagrees that
there is undue discrimination because
this service is not available to point-topoint customers, stating that network
and point-to-point service are not
similarly situated services. TDU
Systems state that conditional firm
service does not ensure comparability
among types of transmission service or
between transmission providers and
transmission customers. NRECA and
others argue that the Commission
requires a better understanding of the
575 The Commission did not propose to modify
the reliability redispatch provisions that exist in the
network integration transmission sections of the pro
forma OATT.
576 E.g., EEI, TDU Systems, NRECA, Southern,
and Duke Reply.
577 E.g., Southern, Duke, and Progress. Duke
suggests that the Commission exempt transmission
providers from the obligation to provide redispatch
if they commit not to use redispatch as a planning
tool for native load, network customers or merchant
functions.
578 Southern states that it offered this service on
a comparable basis to a non-affiliated transmission
customer.
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degree to which comparability is a
problem in providing point-to-point
service before the Commission makes
changes to point-to-point service.579 In
supplemental comments, EEI contends
that the record in this proceeding does
not demonstrate that conditional firm
service is necessary to remedy undue
discrimination.
919. Others assert that it is not within
the Commission’s jurisdiction to order
planning redispatch for point-to-point
customers because this type of
redispatch requires use of the
transmission provider’s generation
resources.580 LPPC states that the
comparability principle is wrongly
applied to the use of generation by a
transmission provider. In Salt River’s
view, the Commission proposal sets up
its own form of discrimination by
making redispatch of the transmission
provider’s resources mandatory while
making redispatch of generation using
firm point-to-point reservations and
generation in other control areas
voluntary.
920. Those that support development
of both services support the
Commission’s statement in the NOPR
that ‘‘transmission owners may evaluate
transmission availability to serve longterm transmission service requests in a
manner that is not comparable with the
method they use to evaluate
transmission needs for bundled retail
native load.’’ 581 They argue that this
divergent treatment of internal
transmission needs versus external
transmission requests is unduly
discriminatory and violates the FPA.
EPSA states that the fact that point-topoint service requests can be rejected
due to a few hours of predicted
reliability problems in a year is
‘‘evidence of a poor use of existing
transmission capacity and display clear
discrimination against non-affiliated
generation and its customers.’’ 582
TransAlta states that its actual
experience with planning redispatch in
the Pacific Northwest demonstrates that
planning redispatch is used
discriminatorily to the benefit of some
customers and the detriment of others.
921. In support of conditional firm
service, Manitoba Hydro and Tacoma
reiterate their experience that long-term
transmission service requests are being
denied due to constraints occurring
during a small percentage of the time
within the requested period of service.
579 E.g.,
580 E.g.,
TDU Systems and EEI Reply.
LPPC, NPPD, Progress Energy, and Salt
River.
581 E.g., AWEA, Utah Municipals, Project for
Sustainable FERC Energy Policy, EPSA, and Barrick
Reply citing NOPR at P 300.
582 EPSA Reply.
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sroberts on PROD1PC70 with RULES
EPSA and AWEA similarly state that a
transmission provider will reject a longterm firm service request unless it can
satisfy every element of the request.
Manitoba Hydro and others state that, in
an era of transmission underinvestment, optimizing the capacity
usage is paramount to system
reliability.583 EPSA and AWEA further
explain that the concept of turning off
a generator to avoid system upgrades is
not new; Maine Independence Station
avoided expensive system upgrades by
installing automatic switching devices
to take it offline during certain system
conditions. Seattle states that, according
to the Seams Steering Committee of the
Western Interconnection, utilization on
most constrained paths is limited to
only a few hundred hours per year and,
therefore, it is highly likely that service
under a conditional firm product could
be offered for even a baseload plant
without significantly impacting the
capacity factor. Santee Cooper states
that, unlike the planning redispatch
option, conditional firm service is
presumptively within the subject matter
jurisdiction of the Commission.
922. Entergy states that the most
comparable service for long-term pointto-point transmission customers is not a
requirement that a transmission
provider redispatch its own or network
customers’ resources to grant long-term
firm point-to-point transmission service.
The most comparable service instead is
a service that allows the transmission
provider to curtail the service granted,
while permitting the point-to-point
customer to obtain alternative,
deliverable resources if and when such
curtailments occur in real-time.
Commission Determination
923. We reject arguments that
planning redispatch service is
unnecessary to remedy undue
discrimination as a collateral attack on
Order No. 888. The obligation to
provide planning redispatch was
established in Order No. 888. The
modifications proposed in the NOPR
did not increase the obligation placed
on transmission providers to use their
generation resources to provide
planning redispatch to point-to-point
customers. Rather, the proposed
modifications merely added specificity
to the redispatch information already
required in a system impact study and
adjusted the timing of when the
transmission provider must study
planning redispatch options.584
Therefore, many of the arguments
583 E.g., EPSA, AWEA, and Project for Sustainable
FERC Energy Policy.
584 See pro forma OATT section 19.3.
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raised, including arguments pertaining
to the Commission’s jurisdiction over
transmission provider generation
resources, are impermissible collateral
attacks on the current planning
redispatch obligation in Order No. 888.
Entergy’s argument that planning
redispatch should not be available to
point-to-point customers because they
are not similarly situated to be able to
provide redispatch from their own units
thus ignores the current obligation for
each transmission provider to provide
redispatch from the transmission
provider’s resources, if available, in
evaluating a request for long-term pointto-point service.585
924. Additionally, information in the
comments counters the assertion that
transmission providers do not use
planning redispatch or service
analogous to the conditional firm option
for their own loads. Entergy and
Southern volunteer that they have
planned for redispatch of their own
resources in order to designate network
resources when ATC was
unavailable.586 As a caveat, Southern
states that it has planned for the use of
redispatch only for an interim period
until upgrades could be constructed to
make the transmission service from the
designated resource fully firm. Entergy
states that it offers planning redispatch
service to network customers that plan
to use their own resources to provide
redispatch in real time. Contrary to EEI’s
assertion about the record in this
proceeding, commenters, such as EPSA
and AWEA, explain that some
transmission providers already employ
automatic devices, such as special
protection systems (SPS), to take
resources offline during certain system
conditions. In a way that is analogous to
the proposed conditional firm service,
these protection schemes are used to
increase native loads’ firm uses of the
transmission system until a contingency
occurs that reduces available
transmission.587 This information, taken
together, provides ample evidence to
support our finding that transmission
585 See
pro forma OATT section 13.5.
and Southern. EEI’s comments also
indicate that at least a few transmission providers
do rely on redispatch in planning to serve their
native loads.
587 SPS, also known as remedial action schemes,
are used to varying degrees in every NERC
reliability region. For example, there are about 65
SPS in the Western Interconnection. See Western
Electricity Coordinating Council Operating
Procedures, Index, V–1 to V–5 (revised July 2,
2002). There are 8 SPS used by Florida Power and
Light in FRCC. See Florida Power and Light Control
Area Readiness Audit Report, 19 (March 10–11,
2004). Two SPS are used in the Southern Subregion
of SERC. Reliability Coordinator Readiness Audit
Report Southern Subregion Reliability Coordinator,
19 (March 27–30, 2006).
586 Entergy
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providers currently evaluate
transmission availability to serve longterm firm point-to-point transmission
service requests in a manner that is not
comparable with the method they use to
evaluate their own transmission needs
and to integrate their resources to serve
bundled retail native load.
925. Furthermore, we wish to
emphasize that, in making these
findings in support of a conditional firm
option, we are not relying on the
findings to create a new service. This
Final Rule retains the two services
adopted in Order No. 888—point-topoint service and network service.
Conditional firm service is not a third
service, but rather represents a
modification to the existing procedures
for granting long-term point-to-point
service and the curtailment priorities for
that service. The primary purpose of
conditional firm is to address the ‘‘all or
nothing’’ problem associated with the
current procedures for requesting longterm point-to-point service. Currently, a
request can be denied because firm
service is unavailable in a very few
hours of the year. For a customer who
needs long-term point-to-point service
to support a long-term transaction, this
leaves the customer in the position of
trying to cobble together a collection of
shorter-term requests to effectuate its
transaction, e.g., arranging firm service
in the periods when it is available and
non-firm service in the other periods.
Such a customer also risks interruption
of the non-firm portion of its service for
economic reasons, e.g., a day of nonfirm service for the customer combining
firm and non-firm service could be
interrupted for another customer
seeking one month of non-firm service.
We do not believe such an approach is
just and reasonable. It makes little sense
to ask the customer to cobble together a
collection of firm and non-firm requests
when the transmission provider has
better information about when the
service may be available or unavailable.
It is therefore appropriate to require the
transmission provider to grant the
service on a conditional basis, as we
explain further below.
926. We are however modifying the
planning redispatch obligation, and
similarly limiting the conditional firm
option, to better reflect the manner in
which redispatch or special protections
schemes are used by transmission
providers, in recognition of certain
legitimate reliability concerns and the
inherent difficulty of long-term
projections in this area. This Final Rule
limits transmission providers’ planning
redispatch obligations by removing the
current obligation to provide planning
redispatch for an indefinite period as
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long as the redispatch is cheaper than
the relevant transmission upgrades. We
also limit the conditional firm option by
linking it to the transmission upgrades
or a biennial assessment of the
conditions.
927. We find such an open-ended
obligation to provide this service is not
necessary to remedy undue
discrimination, nor is it consistent with
the need to maintain system reliability.
As indicated above, transmission
providers temporally limit their use of
planning redispatch and curtailment of
resources and there is no evidence that
transmission providers use these
options on a prolonged basis, e.g., for
more than a few years, without
upgrading their transmission systems.
Rather, over the long run, transmission
providers generally will construct
sufficient transmission to integrate their
resources on a firm basis. This is
consistent with transmission planning
requirements and the emphasis placed
upon transmission expansion in this
Final Rule. The modifications to longterm point-to-point service we adopt are
consistent and comparable to the
existing use of these options by
transmission providers’ bundled retail
native loads. Thus, the planning
redispatch and conditional firm options
will be available primarily as interim
measures until transmission systems are
upgraded to meet the transmission
service request. We believe this
limitation will have the added benefit of
lessening disincentives to provide the
service so that more planning redispatch
is offered to transmission customers by
transmission providers.
928. We disagree with TDU Systems’
statement that conditional firm service
does not ensure comparability among
types of transmission service or between
transmission providers and
transmission customers. TDU Systems’
assertion is unsupported by any
explanation or examples of how the
conditional firm service would degrade
comparability. Nevertheless, we believe
the argument is essentially a collateral
attack on Order No. 888. Order No. 888,
not this rulemaking, created the
distinction between point-to-point
transmission service and network
integration service. We did so to
recognize the different ways in which
transmission providers typically use
their system. The two services are not
precisely the same, nor were they intend
to be identical. Nothing in this Final
Rule changes these distinctions. Indeed,
we are not changing the relative
priorities applicable to firm point-topoint service, network integration
service and service to bundled native
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load.588 These services do, and will
continue to, share the same priority—
the highest priority of firm service on
the transmission provider’s system. The
only change, as it relates to the
conditional firm option, is to allow the
customer to elect to have its long-term
firm transmission service interrupted
under certain defined circumstances.
This does not harm other firm
customers. Indeed, it has precisely the
opposite effect: it permits an
interruption to maintain firm service to
other customers. Moreover, we find, as
indicated above, that conditional firm
service is necessary to remedy undue
discrimination.
929. The addition of conditional firm
service therefore does not significantly
alter the existing balance between the
point-to-point and network service.
Customers of network service retain
flexibility that is not enjoyed by pointto-point customers. Moreover,
conditional firm does not reduce the
availability of secondary network
service or the ability of network
customers to temporarily undesignate
network resources any more than shortterm firm point-to-point service already
reduces the availability of these network
customer options. We therefore reject
TDU Systems’ arguments and find that
the addition of conditional firm service
is necessary to remedy undue
discrimination and will otherwise
increase utilization of the grid without
impairing system reliability.
(2) Reliability
(A) Ability to Predict Redispatch
Opportunities and System Conditions in
the Long Run
Comments
930. Some commenters state that
redispatch, used as a planning tool
rather than as a short-term operational
tool, is overly complex, prone to causing
disputes, reduces reliability and thus
should not be included in the pro forma
OATT.589 Southern asserts that
planning redispatch should not be
required where it reduces reliability by
reducing a utility’s reserve margin,
shifting the operational, reliability and
economic risks from the new customer
to native load, or causing a single
contingency to overload the system.
Additionally, Xcel states that pledging a
network resource to support planning
redispatch carries a risk of penalties for
inadequate resources in some areas.
MISO states that contingency conditions
must be considered and respected when
supra section V.D.5.b.
Duke, Entergy, WAPA, NRECA, NPPD,
LPPC, and Southern.
12385
evaluating planning redispatch options
so that there is no reliance on
curtailment of service. MidAmerican
and Progress Energy conclude that the
customer must accept the risk of
selecting planning redispatch service
over transmission construction.
931. Several commenters request
modification of the existing planning
redispatch provisions of the pro forma
OATT.590 They state that the
Commission should clarify that the
current section 13.5 does not require
planning redispatch when it would
adversely affect system reliability or
service to native load, network
customers and other firm point-to-point
customers or impair other contractual
obligations. Indianapolis Power states
that the Commission should modify
section 13.5 to require all reasonable
redispatch options be examined by the
transmission provider.
932. In its reply comments, Southern
explains that transmission providers fail
to provide the currently required
planning redispatch service to point-topoint customers because the service is
impractical and would harm reliability.
Southern contends that a redispatch
scenario identified in a transmission
plan may not be available in real time
due to outages or loop flow. Southern is
also concerned about the complications
in planning and modeling that would
occur if the transmission provider is
required to redispatch multiple
resources in order to accommodate
multiple planning redispatch customers.
933. Similar to their arguments in
favor of conditional firm, EPSA and
AWEA state that planning redispatch is
necessary because a transmission
provider will reject a long-term firm
service request unless it can satisfy
every element of the request, even if
reliability violations occur in only a few
hours of the year. In its reply comments,
EEI responds that there is no evidence
to support the assertion that a
transmission provider will reject a longterm firm service request unless it can
meet every element of that request. EEI
states that in such a situation the
transmission provider must offer partial
service, offer to perform a system impact
study, and exercise due diligence in
constructing needed upgrades to
accommodate the request. EEI adds that
the potential customer can also request
short-term service. Finally, EEI states
that there is no evidence that
transmission providers are refusing to
redispatch in response to customer
request when redispatching resources
would have no impact on reliability. In
588 See
589 E.g.,
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590 E.g., EEI, Indianapolis Power, Public Power
Council, Southern, Seattle, Sacramento, and LPPC.
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its reply comments, MISO states that
denial of service complained of by
EPSA and AWEA is a consequence of
the customer’s economic decision not to
build upgrades.
934. Many transmission providers
assert that the costs and inequities of
achieving the proposed planning
redispatch outweigh any new benefits
for point-to-point customers.591 They
state that the Commission’s proposal is
based on an erroneous assumption that
redispatch is nearly always feasible;
instead when redispatch is most
desirable, generators operating at peak
would not be available for redispatch.592
Southern also explains that problems of
insufficient transmission capacity
cannot be avoided by redispatching
generation because there is no guarantee
that a redispatch solution will be
available during real-time operations.
Imperial argues that the personnel and
modeling costs to transmission
providers of calculating planning
redispatch costs prior to a facilities
study are too excessive. Xcel concludes
from a NERC experiment on market
redispatch that redispatch involving
non-market-based or bilateral
coordination with third parties to
protect a delivery path is cumbersome,
inefficient, and does not promote
reliability.
935. Xcel states that its estimate of
hours of planning redispatch is unlikely
to be accurate given that it uses a static
power flow that is created for a specific
peak hour and a specific off-peak hour
in a given year. Commenters state that
planning redispatch service should not
be a guaranteed service because
generation or transmission availability,
system loads, loop flows from adjoining
systems, weather, and fuel availability
all entail a component of risk that
should not be pushed back on the
transmission provider or its native
load.593
936. Operators of systems that rely
primarily on hydroelectric resources
argue that planning redispatch should
not be considered a viable option for
their systems and they should be
exempt from OATT planning redispatch
obligations because hydroelectric
operators are unable to make long-term
commitments that a resource will be
available to relieve transmission
constraints.594 Bonneville states that the
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591 E.g.,
Duke, Entergy, Imperial, International
Transmission, Salt River, Seattle, Southern,
Tacoma, Northwest IOUs, Sacramento, Progress
Energy, E.ON, Xcel, TVA, and EEI Reply.
592 E.g., Sacramento and TVA.
593 E.g., Progress Energy, E.ON, WAPA, Entergy,
and MidAmerican.
594 E.g., Bonneville, Seattle, Public Power
Council, and WAPA.
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variability in water flows and the
interdependence of the generating units
contribute to the inability to predict
future redispatch ability. Bonneville,
WAPA and Bureau of Reclamation state
that planning redispatch can conflict
with federal obligations to operate
federal dams and reservoirs in a manner
that does not impact project purposes
and provide preference in the sale of
hydropower to its preference customers.
Tacoma states that planning redispatch
must be linked to market price indexes
to work in a hydro-based system. Seattle
states that in hydro-dominant systems
fuel availability and fuel price risk
undermine the feasibility of providing
long-run redispatch cost estimates that
reasonably reflect future costs. Seattle
adds on reply that planning redispatch
fails to address costs pertaining to fish
species preservation, recreation and
flood control impacts, increased risk of
spill, or replacement power that are
associated with hydroelectricity.
937. Morgan Stanley argues on reply
that the Commission should not exempt
hydroelectric system operators from
providing planning redispatch; instead,
factors unique to hydroelectric systems
should be taken into account in
determining how much planning
redispatch a transmission provider can
provide. In supplemental comments,
PPM agrees with Morgan Stanley and
adds that hydro-based systems, such as
Bonneville’s, are flexible enough for a
transmission provider to use planning
redispatch to create additional firm
capacity.
938. In their reply comments, Utah
Municipals and EPSA state that
planning redispatch would not impair
reliability because the OATT provisions
do not require transmission providers to
permit intentional overloading of lines.
Since transmission providers are
already required to provide planning
redispatch now, Utah Municipals
contend that any change in the sequence
for studying the option cannot have an
impact on reliability. EPSA argues that
claims of adverse reliability impacts
should be dismissed because
transmission providers do not make
these same claims when they redispatch
to enable transmission service to meet
their own load obligations. Utah
Municipals state that reliability would
be most enhanced by completely
restricting access to the grid, a policy
that Utah Municipals do not
recommend because it would be
extraordinarily costly and promote
discrimination. In its reply comments,
Entegra states that customers seeking
planning redispatch are not seeking to
shift a disproportionate share of the
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risks or costs to native load or other
users of the system.
939. In its reply comments, EPSA
further argues that the Commission
should place the burden of showing
unreliability in a particular instance on
the transmission provider. EPSA also
argues that transmission providers
should not be allowed to delay service
through feasibility studies. EPSA
contends that planning redispatch will
not delay needed system upgrades and,
instead, will ensure optimized use of
the existing system that will provide
additional information about the
system’s capabilities to regional
planning initiatives. In its reply
comments, Morgan Stanley states that
the Commission should establish clear
standards as to the degree of expected
reliability that appends to a firm
transmission sale and allow
transmission providers to sell as much
of the system as can be sold on a firm
basis, consistent with maintaining the
reasonable standard.
940. EEI and some transmission
providers add that the conditional firm
product could result in an
oversubscription of a transmission
system in violation of NERC reliability
standards that require the transmission
system to be planned to meet all firm
needs.595 ELCON states that conditional
firm service may not truly support longterm contracts for firm power but may
lead to a greater volume of short-term
trading.
Commission Determination
941. Many commenters are concerned
that the options described in the NOPR
will impair system reliability. We have
taken these comments into account and
have tailored the modifications to longterm point-to-point service so as to not
impair system reliability. There are two
important limitations that provide such
protections. First, we make clear that
transmission providers are not required
to offer planning redispatch or
conditional firm service if doing so
would impair system reliability.596
Second, as explained above and
discussed in further detail below, we are
limiting the time period under which
either option is offered. We do so
because forecasts of potential redispatch
or interruption options become more
595 E.g.,
Ameren, Southern, and EEI.
transmission provider may not be able to
provide conditional firm service without impairing
the reliability of its system if it is required, for
example, to manage many conditional firm pointto-point reservations across the same path. The
ability of system operators to track, tag and manage
curtailment of multiple conditional firm
reservations is necessarily limited by time, human
resources and other reliability-related duties of the
operators.
596 A
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speculative over time and to require a
transmission provider to commit for a
substantial period of time, subject to the
uncertainty inherent in such long-term
projecting, has the potential to degrade
reliability. With these two limiting
conditions, we find that neither the
planning redispatch nor conditional
firm option will degrade reliability and,
as discussed above, that both are
necessary to remedy undue
discrimination.
942. We agree with a majority of
commenters that over the long term,
new resources should be supported by
sufficient transmission capacity to
deliver their output reliably. Imposing a
planning redispatch or conditional firm
obligation over the long-run would not
be consistent with the need to increase
the reliability of the grid or otherwise
necessary to remedy undue
discrimination. Rather, it would tend to
degrade reliability over time, contrary to
the public interest and the underlying
goals of EPAct 2005. Projections of
planning redispatch options and
conditional firm conditions are more
accurate in the near term and, hence,
should facilitate the efficient use of
existing resources without impairing
reliability.
943. We therefore impose limits on
the transmission provider’s current
planning redispatch obligations. We do
so by removing the obligation to provide
planning redispatch for an indefinite
period as long as the redispatch is less
expensive than the relevant
transmission upgrades. Section 13.5 of
the pro forma OATT could, in
conjunction with rollover rights, allow
for an extremely long-term obligation to
provide planning redispatch in lieu of
upgrading the transmission system. We
find that this existing obligation may
unreasonably harm reliability and
provides incorrect incentives to delay
necessary grid expansion. We
emphasize that the obligation to provide
planning redispatch applies only when
the service can be provided reliably.
944. We also limit the time period
over which a transmission provider
must predict the system conditions or
conditional hours that would apply to
customers using the conditional firm
option. We do so in recognition of the
difficulty in attempting to forecast
curtailment options over the long-term
and the fact that there is no evidence
that transmission providers perform
similar forecasts for their native load
customers. We do not, however,
eliminate entirely the risk of predicting
future system conditions or shift it in
whole to the requesting transmission
customer as requested by certain
commenters. We believe that the
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transmission provider should retain
responsibility for incorporating
reasonable assumptions into its
transmission models so that it can
manage this risk, just as it currently
manages the prediction risk in its ATC
models.
945. We will now turn to certain
clarifications and other issues raised by
the commenters. We acknowledge that
planning redispatch to support annual
service may require redispatch of
generation during the peak month or
months. Since transmission providers
plan their generation to meet their peak
native load plus reserves, the
transmission provider’s resources may,
in some cases, be fully employed to
meet the needs of bundled retail native
load and thus may not be available to
provide redispatch during the peak
period.597 In such an instance, the
unavailability of such resources to
provide redispatch service will
constitute a legitimate basis for denying
planning redispatch service. However,
we will not excuse the existing
obligation that requires transmission
providers to study any available
planning redispatch, including
redispatch that might provide some but
not all of the service requested. Given
that some transmission providers have
acknowledged their own use of
planning redispatch for their network
resources,598 the service must continue
to be available to those seeking point-topoint service to ensure comparability.
946. We reiterate that the
transmission provider remains obligated
to provide planning redispatch from its
resources as long as the planning
redispatch does not (1) degrade or
impair the reliability of service to native
load customers, network customers and
other transmission customers taking
firm point-to-point service or (2)
interfere with the transmission
provider’s ability to meet prior firm
contractual commitments to others.599
We continue to believe these are the
appropriate exceptions and will not
adopt a broad and undefined
reasonableness standard as suggested by
Indianapolis Power. We agree with
Southern that the transmission provider
may consider the impact of the planning
redispatch service in reducing its
reserve margin below that necessary to
maintain reliability or causing a single
contingency to overload the system in
597 See, e.g., Arizona Public Service Co. v. Idaho
Power Co., 95 FERC ¶ 61,081 at 61,241 (2001)
(resources projected to be unavailable during
system peak month to provide planning redispatch).
598 E.g., Entergy.
599 See also Order No. 888 at 31,739.
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determining whether the service can be
reliably provided.
947. Further we will not excuse
transmission providers from the
obligation to manage multiple planning
redispatch or conditional curtailment
obligations simply because some
commenters express concerns about
planning and modeling impacts. While
we do not take these concerns lightly,
we believe they can be managed by
transmission providers. The planning
redispatch obligation has existed for ten
years, and with it the potential for
multiple planning redispatch requests.
We have no evidence that transmission
providers have been unable to manage
the process. Moreover, by scaling back
the time period for which transmission
providers must plan for provision of
redispatch, we have greatly reduced any
planning and modeling impacts. We
believe that whatever additional work
the options cause with regard to
planning and modeling, it is small and
more than offset by the considerable
value of the options which allow for
more efficient use of the transmission
system, expansion of long-term uses of
the grid and remedying of undue
discrimination.
948. Finally, we recognize the
difficulty of predicting, over prolonged
periods, whether hydroelectric
resources will be available to provide
redispatch. We agree with Morgan
Stanley that factors unique to
hydroelectric systems should be taken
into account in determining how much
planning redispatch a transmission
provider can provide. For example,
transmission providers operating hydrobased systems must predict both system
load growth and water availability in
order to determine whether resources
will be available in the next few years
to provide redispatch. We acknowledge
that certain circumstances may in fact
limit long-term redispatch on these
systems due to increased prediction
risks. We reiterate, however, that all
transmission providers, including those
operating hydro-based systems, are
required to make a determination,
regarding whether planning redispatch
service can be provided consistent with
system reliability based on the specific
facts of a particular request for service.
The fact that hydro-based systems may
not be able to provide planning
redispatch service under many
circumstances should not necessarily
limit the availability of conditional firm
service on these systems. We expect that
transmission providers with hydrobased systems will focus on provision of
the conditional firm option in a manner
consistent with their system conditions.
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949. We also repeat that planning
redispatch service does not need to be
provided if doing so would impair the
firmness of service to existing
transmission customers. For example,
pre-existing federal obligations, such as
those described by Bonneville, WAPA
and Bureau of Reclamation, would
qualify as the type of firm commitments
to others that would excuse
transmission providers from the
planning redispatch obligation to the
extent that redispatch impaired service
to these customers.
(B) Impact on Network Customers and
Native Load
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950. Several commenters argue that
the use of planning redispatch may
remove the ability to use reliability
redispatch in real-time operations to
respond to system contingencies,
resulting in more curtailment of
network and native load.600 In addition
to reducing availability of redispatch as
an operational tool, NRECA contends
that planning redispatch will reduce
ATC for network service and the
incentive to build new transmission.
Several commenters state that planning
redispatch may unfairly shift costs to
network and native load customers.601
Progress Energy argues that such a
mandate places the power grid in
serious jeopardy because the system has
not been designed to handle the
redispatch planning model. Progress
Energy and Nevada Companies state
that the planning redispatch option
could conflict with transmission
providers’ state resource planning
obligations to reliably serve load at least
cost. Exelon replies, however, that
planning redispatch could increase
flexibility for network customers by
increasing the availability of point-topoint service across adjacent
transmission systems to bring
generation to network loads.
951. Some commenters argue that the
conditional firm option would adversely
impact system reliability by subjecting
firm customers to additional
curtailments once conditional
curtailment hours are exceeded.602
NRECA and Utah Municipals state that
the conditional firm service will reduce
the flexibility of network customers by
preventing network customers from
using secondary network service, a right
600 E.g., EEI, Duke, Imperial, LPPC, PNM–TNMP,
Public Power Council, NRECA, NPPD, Southern,
and Progress Energy.
601 E.g., EEI, TAPS, LDWP, MidAmerican,
Southern, Community Power Alliance, and MISO
Reply.
602 E.g., Duke, LPPC, NRECA, NPPD, Progress
Energy, Southern, APPA, and South Carolina E&G.
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that NRECA argues is protected by FPA
section 217.
Commission Determination
952. We reiterate that transmission
providers are not required to offer
planning redispatch and conditional
firm point-to-point service if doing so
would impair the reliable service to firm
customers, including native load and
network customers. The concerns of the
commenters regarding the impacts on
native load, network and other existing
firm uses are therefore misplaced.
953. Transmission providers are
already obligated to provide planning
redispatch service pursuant to Order
No. 888 and thus arguments that the
planning redispatch option will harm
existing customers is equally misplaced.
Indeed, under the limitation on the
duration of planning redispatch service
imposed in this Final Rule, transmission
providers will be able to better manage
the risks of curtailment for current users
of the transmission grid. This is because
the obligation to redispatch will no
longer be an open-ended obligation.
Customers will need to commit to
upgrade the system or to have their
service reassessed periodically. Both of
these allow the transmission provider to
better plan to serve needs reliably
because it reduces the unknowns. With
regard to NRECA’s argument that
planning redispatch will cause less
flexibility in real-time and more
potential for curtailments of network
customers and bundled retail native
load, all sales of point-to-point service
could to some extent cause more
curtailments of network customers and
bundled retail native load. Our decision
today limits the existing planning
redispatch obligation for point-to-point
service, rather than expanding it.
954. Similarly, the conditional firm
option does not reduce the availability
of secondary network service or the
ability of network customers to
temporarily undesignate network
resources any more than short-term firm
point-to-point service already reduces
the availability of these network
customer options. We see no reason to
reject the conditional firm option so that
transmission providers avoid offering
higher-quality service such as
conditional firm point-to-point service
in order to retain the ability to offer
lower-quality service such as secondary
network service.
955. Finally, we believe that network
customers can benefit from the use of
the planning redispatch and conditional
firm options available in a point-topoint transmission service request. As
described below, long-term point-topoint service that employs the planning
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redispatch or conditional firm option
would qualify as a network resource on
any adjoining system importing that
resource.
(3) Implementation of Planning
Redispatch and Conditional Firm
Options
956. Commenters raise various
concerns regarding specific
implementation issues associated with
the planning redispatch and conditional
firm options. We address those concerns
below, but first provide an overview of
the planning redispatch and conditional
firm service required in this Final Rule
in order to outline the new rights and
obligations of transmission providers
and customers. Following this overview,
we address specific comments relating
to the service.
957. Pursuant to the modified
obligations adopted in this Final Rule,
where a request for long-term point-topoint firm transmission service is made
and cannot be satisfied out of existing
capacity, the transmission provider
shall, at the request of the customer and
in the system impact study, identify (1)
the transmission upgrades necessary to
provide the service, and (2) the options
for providing service during the period
prior to completion of those
transmission upgrades. Additionally, if
upgrades cannot be completed prior to
expiration of the requested service term,
the transmission provider shall, at the
request of the customer and in the
system impact study, identify options
for providing the service during the
requested term. The options studied by
the transmission provider must include
planning redispatch and conditional
firm options.603 The transmission
provider, at its discretion, may study
and offer a mix of planning redispatch
and conditional firm options for a single
service request. We provide further
detail on each required option below.
958. If the transmission provider
determines that planning redispatch is
available, it shall provide the customer
with non-binding estimates of the
incremental costs of redispatch and
identify the relevant constrained
flowgates for which redispatch will be
provided. For the conditional firm
option, the transmission provider shall
identify the conditions and hours
pursuant to which the service may be
curtailed, using a secondary network
curtailment priority, to maintain
reliability. Specifically, the transmission
provider shall identify (1) the specific
603 Although partial interim service is not
addressed in this rulemaking, we note that the
OATT continues to require this service, on an as
available basis, if a multi-year service request is
denied.
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system condition(s) when conditional
curtailment may apply and (2) the
annual number of hours when
conditional curtailment may apply.
Customers agreeing to take conditional
firm service must choose one of these
options, conditions or hours.
959. Where the customer requests
firm service for more than two years, but
is unwilling to commit to a facilities
study or the payment of network
upgrade costs, the transmission provider
shall identify and provide the planning
redispatch or conditional firm options
subject to the following limitation. The
transmission provider shall have a
periodic right to reassess (1) the
planning redispatch required to keep
the service firm or (2) the conditions or
hours under which the transmission
provider may conditionally curtail the
service. This reassessment may occur
every two years during the term of the
service, i.e., at the end of year two, year
four, year six, and year eight of a tenyear service. The transmission provider
may not implement reassessments
during intervening periods nor may it
reassess the conditions in order to
amend the service agreement in an
intervening year should it forego any
biennial reassessment.604
960. The service agreement shall
specify the relevant congested
transmission facilities and whether the
transmission provider will provide
planning redispatch, a mix of planning
redispatch and conditional firm, or
conditional firm in order to provide the
point-to-point transmission service. For
the conditional firm option, customers
must choose among and the service
agreement must specify either (1)
specific system condition(s) during
which conditional curtailment may
occur or (2) annual number of
conditional curtailment hours during
which conditional curtailment may
occur. We deem that any service
agreement that incorporates planning
redispatch or conditional firm options is
a non-conforming agreement and must
be filed by the transmission provider
pursuant to section 205 of the FPA.
Additionally, transmission providers
must file with the Commission any
amendments to these service agreements
that result from reassessments. If a
transmission provider proposes to
change the redispatch or conditional
curtailment conditions due to a
reassessment, the transmission provider
must provide the reassessment study to
604 For
example, if a transmission provider opts
to forego the reassessment at the end of year two,
the transmission provider may not reassess the
conditions of the service again until the end of year
four of service for imposition of new conditions
starting in year five.
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the customer along with a narrative
statement describing the study and
reasons for changes to the curtailment
conditions or redispatch requirements
no later than 90 days prior to the date
for imposition of these new conditions
or requirements. The transmission
provider shall assess the conditions
based on two years of service or the
continuation of the term of service,
whichever is less.
961. In situations in which the
customer commits to paying the costs
associated with upgrades necessary to
provide the service on a fully firm basis,
the conditions or hours identified by the
transmission provider shall remain in
effect until such time as the upgrades
have been completed. Also, for such
customers, the service agreement shall
specify the upgrade costs as determined
through the facilities study.
(A) Eligibility for and Timing of
Planning Redispatch and Conditional
Firm Options
NOPR Proposal
962. In the NOPR, the Commission
proposed that customers who request
long-term firm point-to-point
transmission service and have the
service denied because of lack of ATC
would be eligible to receive planning
redispatch service or, if the Commission
chose to adopt the conditional firm
service option, conditional firm service.
The Commission also proposed earlier
evaluation of the planning redispatch
option in the system impact study rather
than in the facilities study. The
Commission proposed that, if it were to
adopt conditional firm service, the
evaluation of conditional firm
availability should occur prior to a
system impact study or facilities study.
Comments
963. If the conditional firm option is
required by the Commission, many
commenters believe it should be a
bridge product to span the gap between
when the relevant transmission service
request is being studied and when the
relevant upgrades become
operational.605 These commenters state
that a bridge product is appropriate
because it would not depress funding
for new transmission infrastructure and
would better meet the NOPR’s and
Congress’ grid expansion objectives. In
their view, use of a bridge product
would avoid equity and free rider
605 E.g., Progress Energy Supplemental, PNMTNMP Supplemental, LPPC Supplemental, APPA
Supplemental, TAPS Supplemental, TDU Systems
Supplemental, NRECA Supplemental, EEI
Supplemental, Entergy Supplemental, Ameren
Supplemental, Powerex Supplemental, and MISO
Supplemental.
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12389
problems that may occur if a conditional
firm customer is taking long-term
service and the transmission system is
upgraded during that service. They also
argue that the bridge product would
better allow for transmission providers
to judge the likelihood of curtailment
and avoid complicated system modeling
and planning issues; as well as protect
existing long-term transmission
customers. Duke and Ameren state that
an annual re-determination of the
conditional period is necessary for a
bridge product. If the upgrade has not
been completed within a three year
period, NRECA suggests that the
customer be required to make a new
long-term firm service request so the
provider can update to reflect system
conditions at that time.
964. Several commenters suggest that
transmission providers should offer
conditional firm service as both a bridge
product and as a stand-alone long-term
firm service.606 Where not used as a
bridge service, several commenters state
that it should be limited to reservations
that do not have rollover rights.607 Duke
argues that the service duration for nonbridge service should be one year, but
with renewal rights that give the
conditional firm customer a priority
over other non-bridge conditional firm
service customers seeking capacity.
APPA supports one to two-year service
offers.
965. In supplemental comments, EEI
supports a voluntary conditional firm
product with three types of service: A
one-year product with no rollover
rights; a bridge product for a term of
more than one year that is provided
until upgrades necessary to
accommodate a firm service request are
completed; and a non-bridge product of
more than one year, with no rollover
rights or transmission provider
obligation to construct upgrades and
subject to the transmission provider’s
periodic review of its system capability
to provide such service. EEI contends
that the Commission should encourage
transmission providers to offer
conditional firm service for more than
one year without rollover rights to a
customer that is not willing to take
service of sufficient length to allow
recovery of upgrades costs, if such
service can be provided without
affecting the reliability and quality of
service to firm transmission customers.
966. In support of limitations on the
term of conditional firm service, many
606 E.g., Bonneville Supplemental, PPL
Supplemental, EPSA and AWEA Supplemental, EEI
Supplemental, Barrick Supplemental, and
Constellation Supplemental.
607 E.g., Xcel Supplemental, Duke Supplemental,
and EEI Supplemental.
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commenters state that analyzing and
modeling system conditions will always
be more accurate in the near term than
in the long term.608 EEI and Community
Power Alliance believe that limitations
on system modeling prevent many
transmission providers from accurately
evaluating their ability to provide
conditional firm service over long
periods. According to EEI, system
conditions change on both the
transmission provider’s and neighboring
systems substantially affecting the
ability of the transmission provider to
provide conditional firm service and the
periods such service is subject to
curtailment. While system loads can be
predicted with a reasonable degree of
accuracy for more than one year, other
components of the prediction model,
such as transmission and generator
outages, typically are not determined
more than a year in advance. For
example, EEI states that members in the
SERC region coordinate transmission
and generation outages in a 13-month
planning horizon. Duke states that the
ability to model the system varies
significantly by region. Entergy and
MidAmerican believe that system
modeling limitations would present
serious reliability problems if
transmission providers were required to
offer a multi-year conditional firm
transmission product because even the
most advanced modeling software
cannot predict long-term conditions that
may affect service. Entergy and
MidAmerican propose that the
Commission allow transmission
providers to update the curtailment
criteria for a reservation, to reflect,
among other things, changing load
assumptions and forecasts over time.
MidAmerican argues that without
annual reevaluation there would be cost
shifts to other firm customers. In its
reply comments, MidAmerican explains
that this reevaluation can only occur
when the actual data becomes available
for projecting potential curtailment
hours.
967. If a transmission provider offers
conditional firm service based on
specified system conditions, Bonneville
states in supplemental comments that
limitations on modeling do not present
a problem. If, however, the service is
based on a maximum number of
conditional curtailment hours per year,
Bonneville believes that modeling
presents problems in offering longerterm service. Bonneville states that
608 E.g., Nevada Companies Supplemental, TDU
Systems Supplemental, LPPC Supplemental,
Ameren Supplemental, Community Power Alliance
Supplemental, MISO Supplemental, PNM-TNMP
Supplemental, NRECA Supplemental, and Xcel
Supplemental.
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forecasting the number of hours of
conditional firm service requires great
analysis. To remedy this, Bonneville
suggests allowing the transmission
provider to make conditional firm offers
under which the transmission provider
could periodically adjust the number of
conditional curtailment hours.
968. In supplemental comments,
Constellation proposes that the
Commission require transmission
providers to offer two types of
conditional firm service: service for less
than the service term eligible for
rollover rights (e.g., five years) if
customers do not agree to pay for
transmission upgrades; and service for
five years or longer with a rebuttable
presumption that the customer is
obligated to pay for upgrades that are
both economic and necessary to relieve
the constraint that prevents its service
from being fully firm.609 EPSA and
AWEA maintain that it is critical that
the conditions be defined, and remain
unchanged, for the term of the service
agreement in order to obtain financing
of new projects. EPSA and AWEA also
propose that, if the contingency is
removed during the life of the
customer’s conditional firm service, the
service should convert to traditional
firm service. Williams, EPSA and
AWEA argue that up-front commitment
to continue the conditions for the
entirety of a long-term service
agreement would take no greater risk
than transmission providers take today
in committing to other long-term firm
transmission service. EPSA and AWEA
state that limited term conditional firm
service should pose no problems based
on system modeling.
969. Several commenters believe that
there is no need for any type of special
rules for conditional firm customers
taking bridge service and required to
pay extremely expensive upgrades.610 If
the Commission abandons the ‘‘higher
of’’ pricing principle for upgrades, these
commenters suggest that any new
pricing policies should be consistent
with cost-causation principles and not
result in any improper socialization.611
Other commenters argue for special
rules when upgrades are extremely
expensive.612 Xcel states that customers
609 EPSA and AWEA endorse Constellation’s
approach in defining and delineating the two forms
of conditional firm service.
610 E.g., Nevada Companies Supplemental, Duke
Supplemental, Bonneville Supplemental, Powerex
Supplemental, BP Energy Supplemental, MISO
Supplemental, PNM–TNMP Supplemental, Entergy
Supplemental, Community Power Alliance
Supplemental, and Southern Supplemental.
611 Proposals regarding the ‘‘higher of’’ pricing
policy are discussed below.
612 E.g., Xcel Supplemental, Constellation
Supplemental, and NRECA Supplemental.
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should have the option to take shortterm conditional firm service that would
remain subject to limitation and
curtailment if upgrades are too
expensive. Constellation proposes that
customers taking the longer-term service
should have the opportunity to show
that upgrades would not be just and
reasonable given the relevant
circumstances, e.g., the cost of upgrades
for a single service request is $300
million. If the Commission determines
that the bridge requirement in a
particular circumstance is unjust and
unreasonable, Constellation proposes
that the transmission provider would
provide the service for the requested
term, but there would be no obligation
for the transmission customer to pay for
such upgrades, and the service would
not be eligible for rollover. NRECA
contends that instances in which special
rules apply should be extremely rare
and are best addressed by the
transmission provider and customers on
an ad hoc basis.
970. Commenters recognize that
upgrades required under a bridge
conditional firm option could create
lumpiness problems,613 but most
commenters suggest that this problem is
not unique to the conditional firm
option, nor can it be resolved through
use of the option.614 These commenters
support continuation of the
Commission’s existing policies with
regard to lumpiness issues, and some
suggest the need to address the issue as
it pertains to all upgrades in a future
proceeding.615 In contrast, a few
commenters suggest that the
Commission should address the
lumpiness issue with regard to
conditional firm service. PPL, EPSA and
AWEA state that the transmission
provider should be required to pay the
costs of any incremental lumpiness
associated with upgrades and the
service request. BP Energy contends that
any lumpy capacity needs to be resolved
on a bilateral contractual basis. Powerex
suggests using an ‘‘open season’’ process
to finance expensive and lumpy
upgrades. California Commission
supports prorating large lumpy
613 In the November 15 Notice, the Commission
described an example of lumpy capacity as
upgrades to provide a requested 100 MW of pointto-point service that results in 1,000 MW of
additional transmission capacity.
614 E.g., EEI Supplemental, Xcel Supplemental,
APPA Supplemental, Bonneville Supplemental,
LPPC Supplemental, NRECA Supplemental,
Progress Energy Supplemental, Duke Supplemental,
Ameren Supplemental, Entergy Supplemental,
Community Power Alliance Supplemental, MISO
Supplemental, Williams Supplemental, and PNMTNMP Supplemental.
615 E.g., LPPC Supplemental, Bonneville
Supplemental, and EEI Supplemental.
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upgrades over a large base of new
customers, to the extent that it is nondiscriminatory and fiscally sound.
971. In supplemental comments,
Nevada Companies urge that the time
period of a conditional firm bridge
product should be left up to the
discretion of each transmission
provider. They suggest that most, if not
all, transmission providers should be
able to offer a conditional firm service
for a one-year period and most should
be able to offer it for longer periods.
Nevada Companies state that they
should be able to provide conditional
firm service in their control areas for
longer periods, possibly for up to five
years in some circumstances and in
certain locations.
972. BP Energy and Williams disagree
that conditional firm service should be
a bridge product. They state that such a
limitation would provide additional
opportunities for undue discrimination
and limit competitive alternatives used
to serve customer load. According to
California Commission, conditional firm
service needs to be available for longterm requests unless there exists a valid,
proven reason why conditions make it
physically or economically impossible
to guarantee such service. California
Commission states that some limitations
on modeling should be accepted as
justification for not providing
conditional firm or related services only
if such provisions for load growth are
nondiscriminatory, justified and
contractually sound.
973. Commenters take both sides on
whether planning redispatch should be
evaluated before the customer is
obligated to incur the costs and delays
of a facilities study. EPSA argues that
evaluation prior to a facility study meets
nondiscrimination requirements given
the methods used by transmission
owners to evaluate planning redispatch
for their own needs. In its reply
comments, Exelon supports the minor
changes to planning redispatch
proposed by the Commission, including
the earlier study of planning redispatch
options in the system impact study, and
states that these changes will expand
choices for customers. EEI states that
requiring an offer of planning redispatch
prior to completion of a facilities study
would be unduly preferential to pointto-point customers because transmission
providers consider the costs of network
upgrades and the impacts on system
reliability before choosing planning
redispatch for their native load.
Southern points to the internal
inconsistencies of the NOPR that on one
hand seek to expedite the study process
and on the other hand would require a
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planning redispatch study provision
that would slow the study process.
974. EEI states that the vast majority
of facilities studies show that the
embedded cost of transmission service
is higher than the incremental
amortized cost of upgrades. Thus, EEI
argues that the Commission’s proposal
to reform planning redispatch could
lead to uneconomic decisions by the
customer as well as provide
disincentives to upgrade and expand
transmission infrastructure.616 In their
reply comments, Utah Municipals
respond that most of the time the
embedded cost of transmission is higher
than the costs of upgrades, adding that
customers find requests for a
transmission upgrades to be a time
consuming and costly impediment to
transmission access. Further, Utah
Municipals add that limited and
occasional redispatch or curtailment,
would be more economically efficient
than the construction of transmission
facilities most of the time.
975. Several commenters state that it
would be extremely burdensome to
develop, at the system impact study
stage, a reliable estimate of the number
of hours of redispatch and the cost of
the planning redispatch.617 These
commenters state that this would
require substantial investment in
probabilistic studies of equipment
availability and extensive training of
personnel and expansion of data
collection, yet still would not provide
reliable estimates of the number of
hours or costs of the service. MISO
states that at a minimum, this would
require two years to implement.
976. EEI asserts that conditional firm
service should be determined based on
system impact studies and facilities
studies so that the customer can
evaluate the costs of upgrades versus the
lack of reliability of the conditional firm
service. EEI and others also propose that
conditional firm service only be
available when upgrades cannot be
completed during the term of service or
during the period prior to completion of
transmission upgrades.618 In its reply
comments, Bonneville disagrees that
conditional firm service should be an
interim service available only when the
customer has agreed to pay for
upgrades, stating that such a
requirement would undercut the value
of conditional firm service. Bonneville
adds that, for example, the costs to build
upgrades in order to resolve a constraint
in a two-month period could raise the
616 E.g.,
617 E.g.,
Xcel, PPM, and BP Energy.
EEI, Southern, TVA, SPP, E.ON, and
MISO.
618 E.g., APPA, PNM–TNMP, and Southern.
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12391
costs of the conditional firm service to
a prohibitive level for little additional
benefit to the customer.
Commission Determination
977. As we explain above, the
Commission finds that both planning
redispatch and conditional firm pointto-point service must be offered under
certain circumstances for the provision
of reliable and non-discriminatory
point-to-point transmission service. We
set forth below the parameters of this
service, keeping in mind the concerns
expressed by commenters.
978. First, the planning redispatch
and conditional firm options need only
be made available to customers who
request firm point-to-point service of
more than a year in duration. When the
requested firm point-to-point service is
not available and the customer agrees to
a system impact study, the transmission
provider must evaluate the planning
redispatch and conditional firm option
at the customer’s request. If the
customer requests study of the planning
redispatch or conditional firm options,
the system impact study must identify
the following: (1) The system
constraints, identified by transmission
facility or flowgate, causing the need for
the system impact study; (2) additional
direct assignment facilities or network
upgrades required to provide the
requested service; (3) redispatch
options, including an estimate of the
incremental costs of redispatch and the
relevant congested transmission
facilities for which redispatch will be
provided; and (4) conditional firm
options, including the number of
conditional curtailment hours and the
specific system conditions during which
conditional curtailment may occur.
Transmission providers may recover the
costs of studying these options through
the system impact study agreement.
979. Second, we adopt limitations on
the nature of the planning redispatch
and conditional firm options to reflect
the two different types of customers that
may request the service: customers who
support the construction of upgrades
and those who do not.
980. For customers supporting the
construction of upgrades, the planning
redispatch or conditional firm options
will serve as a bridge until upgrades are
constructed to remedy the congested
transmission facilities. For these
customers, the transmission provider
must offer planning redispatch or
conditional firm service until the time
when the upgrades are constructed. The
conditions or redispatch applicable to
this period must be specified in the
service agreement and are not subject to
change. We impose this requirement
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because customers who commit to
support transmission upgrades are
typically those financing and
constructing new resources. These
customers require certainty both with
regard to upgrade costs and, before
upgrades can be constructed, the
redispatch requirements or curtailment
conditions that may apply to their
service. We disagree with Williams and
BP Energy that requiring transmission
providers to offer this bridge product
will present more opportunities for
undue discrimination. As we note
above, available information on
transmission providers’ current uses of
redispatch and curtailment plans for
their retail native load indicates that the
mechanisms are used for relatively short
periods of time until upgrades are
completed to resolve the transmission
insufficiencies. Comparable services for
long-term point-to-point customers
should therefore be similarly limited to
shorter time periods or otherwise linked
to transmission upgrades.
981. For customers choosing not to
support the construction of new
facilities, the planning redispatch or
conditional firm options also must be
made available as a reassessment
product, i.e., subject to certain
limitations. Although many
transmission providers argue that
planning redispatch and conditional
firm service should be offered only to
customers who seek to upgrade the grid,
we disagree. We find that there are
legitimate circumstances under which
customers may not choose to support
system upgrades—either because the
costs of construction are too high or
because the term of service (e.g., less
than five years) does not merit the
construction of additional facilities. We
will therefore make planning redispatch
and conditional firm service available to
such customers, but subject to certain
limitations to reflect the nature of the
services. Specifically, we must select a
limitation on the term for the conditions
that permit interruption or redispatch,
given that, for these customers, the term
is not circumscribed by the period
during which upgrades are constructed.
We adopt two years as the appropriate
time period to allow the transmission
provider to reassess the conditions
under which planning redispatch or
conditional firm service is provided.
The transmission provider will retain
the right to reassess the planning
redispatch and conditional firm option
after the first two years of service, and
every two years thereafter. The
transmission provider shall reassess (1)
the redispatch required to keep the
service firm or (2) the conditions or
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hours under which the transmission
provider may conditionally curtail the
service. The customer will receive
service for the requested term unless the
transmission provider determines
through its biennial reassessment that
the firm point-to-point service can no
longer be reliably provided. The
customer may also choose to terminate
the service at the time of reassessment
if the service no longer meets it needs.
982. We select two years as providing
a reasonable balance between the
concerns of potential customers and
transmission providers. We recognize
that a shorter period would increase the
reliability of predictions, as sought by
certain transmission providers, but find
that a two-year period is consistent with
the bridge concept, given that two years
is often less than the typical time to
construct new facilities. While this is a
shorter period than some transmission
customers would desire, customers who
require greater certainty over the longterm can obtain that certainty by
agreeing to support the construction of
new facilities. In the long run, all firm
transmission customers, including
conditional firm customers, should
support the expansion of the grid to
reliably serve load.
983. We decline to adopt any of the
suggestions to address unique
circumstances that may arise in which
upgrades are prohibitively expensive.
Specifically, we will not adopt
Constellation’s suggestion that
customers be able to rebut the
presumption that required upgrades are
just and reasonable. In this Final Rule,
we provide customers with the option of
obtaining planning redispatch or
conditional firm service for a long term,
with the ability to roll over a five-year
or longer reservation, subject to a
limitation that the underlying
restrictions on the service, i.e., the
conditions for redispatch or curtailment,
may be reassessed by the transmission
provider every two years. We believe
that this option is superior to that
proposed by Constellation because it
will provide the customer with rollover
rights while ensuring that transmission
providers can reliably operate their
transmission systems. Additionally,
since issues of lumpy capacity are
present in the provision of transmission
services generally, we will not address
such issues in this Final Rule as they do
not present issues unique to planning
redispatch or conditional firm options.
984. Contrary to the assertion of
several commenters, we believe that
transmission providers would take
greater risk in committing to conditions
for the entire term of a 10-year
conditional option than they take today
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in committing to provide unconditioned
firm point-to-point transmission service
for a similar period. Planning for
reliable service for existing transmission
customers is a difficult process, but it is
much more difficult to plan over an
extended long-term period for reliable
service when the service is firm for most
of the hours of the year and less firm for
other hours. This is because many
transmission providers use annual
hourly peak load for two to 10-year
planning purposes. They would need to
substantially change their planning
methods to ensure no change in service
for a conditional firm customer that is
not expected to be served during the
peak hour. We therefore adopt a two
year assessment window to provide an
appropriate degree of flexibility for
transmission providers’ planning needs.
985. We acknowledge, however, that
some commenters, such as Bonneville
and Nevada Power, state that they may
be able to provide conditional firm
service over a period longer than two
years, without the need for
reassessment. The Commission
encourages the provision of planning
redispatch or conditional firm service
for longer periods where it is practical.
In the event a transmission provider is
able to extend the assessment period,
we will allow the transmission provider
to waive or extend its right to reassess
the availability of the option, provided
that the waiver or extension is provided
consistently for all similarly situated
service.
986. With regard to timing of the
study of planning redispatch and
conditional firm options, the
Commission finds that study of both
options is appropriate in the system
impact study. The obligation for the
transmission provider to study planning
redispatch options in the system impact
phase is already present in the existing
OATT.619 The Commission clarifies in
this Final Rule the specific requirements
necessary to meet this obligation.
Transmission providers, when
requested by potential customers, must
provide non-binding estimates of the
incremental costs of planning
redispatch and identify the relevant
congested transmission facilities for
which redispatch will be provided.
Transmission providers will not be
required to estimate the number of
hours of redispatch that may be required
to accommodate the requested service as
proposed in the NOPR. The Commission
is persuaded by commenters that such
an estimate is of limited use to potential
customers and is difficult, expensive
and time consuming for transmission
619 See
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providers to calculate with any
accuracy.
987. Finally, the Commission
disagrees that the study of planning
redispatch options must necessarily go
hand in hand with the study of the costs
and construction requirements of
facility upgrades. Again, the obligation
to study planning redispatch in the
system impact study is not new. Our
action in reinforcing this existing
obligation cannot violate comparability
or, in itself, cause the slowing of study
processes. We have moved to a later
study of conditional firm options so that
both options can be studied in tandem.
Furthermore, we note that the structure
of the reassessment product requires the
study of both options at the system
impact study phase, since by definition
customers opting for the reassessment
product are not likely to enter into a
facilities study agreement. We
acknowledge that the few changes that
we are making to the planning
redispatch obligation may increase
requests for study of the option and
certainly the new conditional firm
option will need more study than in the
past. While we recognize the tension
between the adoption of requirements to
speed study completion and the
increase in studies’ complexity caused
by the conditional firm option,620 we
will not forego a beneficial new option
for customers because of this tension.
We expect that transmission providers
will be diligent in completing the
system impact studies and in bringing to
our attention any difficulties in meeting
deadlines caused by the study of the
two options.
(i) Application to RTOs and ISOs
Comments
NOPR Proposal
988. In the NOPR, the Commission
requested comment on the applicability
of these two options to transmission
providers who operate as RTOs and
ISOs. The Commission also requested
comment on which resources should be
required in the provision of planning
redispatch. First, the Commission
proposed that the planning redispatch
requirement apply to the redispatch of
the transmission provider’s own
generation resources, but not to obligate
transmission providers to purchase new
resources to provide the service. If a
transmission provider cannot
accommodate a long-term firm point-topoint transmission request through
planning redispatch, the Commission
989. RTOs state that reforms regarding
planning redispatch and conditional
firm services are unnecessary in RTO
markets with financial congestion
management because these markets
already provide sufficient redispatch
inside RTOs and sufficient
interconnection service for generators
located at RTO boundaries to address
the Commission’s point-to-point service
concerns.621 Ameren and MISO add that
the options could disrupt the
distribution of financial transmission
rights in RTO markets. Others disagree
and argue that planning redispatch
should be used by RTOs to define the
current and future operational
environment to ensure that systems are
not overbuilt.622 AWEA contends that,
since RTOs and ISOs vary considerably
in the services they offer, RTOs and
ISOs should be required to demonstrate
that their services are consistent with or
superior to planning redispatch and
conditional firm services. In particular,
AWEA argues that RTOs that do not
provide financial rights should be
required to provide both of these
services. Exelon states on reply that the
Commission has proposed minor
changes to the existing planning
redispatch requirement that should not
be impractical or too burdensome for
RTOs to administer.
990. In its reply comments, California
Commission adds that capping the
frequency or costs of redispatch in an
RTO market would inappropriately shift
the costs of congestion to others.
Although SPP has successfully used
planning redispatch to facilitate shortterm firm transmission service and to
address interim circumstances
associated with long-term firm
620 In section V.D.5.a, we adopt a requirement
that transmission providers post metrics on their
performance in processing system impact studies
and facilities studies.
621 E.g., MISO, PJM, California Commission, and
ISO New England.
622 E.g., AWEA, Indianapolis Power Reply, and
Exelon Reply.
(B) Who Must Provide Planning
Redispatch and Conditional Firm
sroberts on PROD1PC70 with RULES
proposed requiring the transmission
provider to identify additional
generators in other control areas that
could relieve the constraint. The
Commission also requested comment on
whether the planning redispatch
obligation should be expanded to
require the use of network customer
resources in addition to transmission
provider resources or expanded to
require that transmission providers
contract to purchase off-system
resources to facilitate the planning
redispatch.
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12393
transmission service,623 it argues that
the Commission’s proposed expanded
planning redispatch service would slow
its batch processing of transmission
service, require significant investment
of time to evaluate the options given the
scope of an RTO, and create speculative
redispatch estimates at best. SPP adds
that RTOs should simply assist the
customer with identification of planning
redispatch options so that the customer
can bilaterally contract with the
generation owners of its choice.
991. MISO adds that conditional firm
is inconsistent with RTO market
mechanisms, requires burdensome
changes to curtailment protocols and
reliability coordinator’s procedures, and
would impact every tool used in real
time for congestion management in
RTOs. In its reply comments, MISO
adds that adoption of conditional firm
service would require revisions to seams
agreement protocols. California
Commission states on reply that the
added administrative complexity of
conditional firm service is unnecessary
in the CAISO because the ISO’s
transmission service model makes no
distinction between firm and non-firm
service and provides prospective new
customers with information to
objectively estimate curtailments.
FirstEnergy and MISO express concern
regarding disruption of existing RTO
communication protocols if these
services are required in RTOs.
Commission Determination
992. Notwithstanding the
requirements of section IV.C of this
Final Rule, the Commission finds that it
would be inappropriate to require RTOs
and ISOs with real-time energy markets
to adopt the provisions for conditional
firm point-to-point service. Customers
transacting in RTOs and ISOs are able
to buy through transmission congestion
in the RTOs’ real-time energy markets
and need no prior reservation in order
to access transmission. Voluntary
curtailment in order to access
transmission is thus not an attractive
option given the range of options
available for customers transacting in
RTOs and ISOs. Further, in RTOs and
ISOs with financial transmission rights,
conditional firm service may disrupt the
distribution of these rights. We therefore
believe that there is no need to reform
existing RTO and ISO procedures to
satisfy concerns underlying the
adoption of the conditional firm option.
993. The Commission directs,
however, RTOs and ISOs that already
623 Citing Attachment AC of the SPP OATT
(Optimal Reservation Processing Method for Short
Term Firm Transmission Services).
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provide planning redispatch pursuant to
section 13.5 of the pro forma OATT to
modify the relevant provisions of their
tariffs consistent with our directives in
this Final Rule.624 RTOs and ISOs need
not amend their tariffs if the
Commission has previously found that
these tariffs were just and reasonable
without the inclusion of pro forma
section 13.5 planning redispatch
provisions. We will not require
incorporation of the more limited
planning redispatch obligations adopted
in this Final Rule if RTOs and ISOs have
already been excused from the planning
redispatch obligations of the existing
pro forma OATT.
(ii) Generation Resources Required for
Planning Redispatch
sroberts on PROD1PC70 with RULES
Comments
994. Most commenters agree that
resources in addition to the
transmission provider’s resources can
and should participate in the provision
of planning redispatch. Commenters
differ as to whether this participation
should be mandatory or voluntary. A
few commenters maintain that
participation by resources outside the
transmission provider’s control area
could have adverse impacts on
reliability in the control area.625
995. In arguing for mandatory
participation, EEI and others contend
that all generation resources owned or
operated by all jurisdictional
transmission customers in the control
area or balancing authority area should
be obligated to redispatch to
accommodate new requests for service
in order to avoid undue
discrimination.626 Exelon argues that
transmission providers should
redispatch resources of its network
customers, subject to appropriate
compensation. SPP contends that
generation affiliated with transmission
owners that have transferred functional
control of their transmission assets to an
RTO should not have any greater
planning redispatch obligation than
unaffiliated generation. In its reply
comments, Entergy states that the
Commission at a minimum should
continue to allow network customers to
request that transmission providers
redispatch network customer resources
in order for the customer to designate a
new network resource.
996. Others argue for a least-cost
economic dispatch to relieve real-time
624 This
includes the transmission provider’s
obligation to post monthly redispatch costs for each
transmission facility over which planning and
reliability redispatch are provided.
625 E.g., Ameren, PNM–TNMP, Xcel, and WAPA.
626 E.g., Southern, FirstEnergy, MidAmerican, and
Community Power Alliance.
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system constraints, including not only
the transmission provider’s own
resources and those of its network
customers, but also all non-affiliated
resources both within and outside its
footprint that choose to be included.627
EPSA explains that this redispatch
would: Require transmission providers
to solicit offers from resources to
provide energy and perhaps ancillary
services; be based on a resource’s offer
of service and take into account
generating resource and transmission
operating limits; include performance
assurance terms, unit commitment
procedures, billing, compensation and
bidding protocols, confidentiality
protections, and information-sharing
protocols; and dispute resolution
procedures to avoid disputes rising to
the level that would require judicial or
regulatory intervention. AWEA supports
Deseret’s OATT provisions that require
the transmission provider to relieve
constraints by the least cost means,
whether by seeking a change in
generation output from the transmission
provider’s merchant function or from
any other feasible generator. Williams
suggests that independent generators
must be allowed to participate in the
provision of planning redispatch service
through submission of a formulary rate
to the transmission provider. If the
Commission intends to have nonaffiliated generators participate in
planning redispatch, PPL states that the
Commission should require
transmission providers to negotiate
agreements with generators on their
systems.
997. TranServ, MidAmerican, and
Nevada Companies support a planning
redispatch service similar to that
employed by the Mid-Continent Area
Power Pool, whereby customers arrange
for their own redispatch through
bilateral or centralized energy markets
and submit plans for approval to their
transmission provider and reliability
coordinator.
998. Several commenters discuss the
need for market development in
conjunction with the planning
redispatch obligation. TranServ and
Xcel state that the planning redispatch
option may force transmission providers
without generation assets to develop
some form of energy market to arrive at
the costs of redispatch. Southern and
Progress Energy add that forced
627 E.g., AWEA, Project for Sustainable FERC
Energy Policy, Exelon, Powerex, Constellation,
Williams, Sempra Global, PJM, EPSA, and Entegra
Reply. Sempra Global contends that the
Commission should require transmission providers
to offer redispatch of non-affiliated resources both
within and outside its footprint, subject to preexisting contractual commitments.
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adoption of such a market would raise
significant political opposition and be
contrary to the Commission’s
commitment in the NOPR to avoid such
restructuring.
999. EPSA, AWEA and PJM support
such market development. When a
generator in another control area is
called upon to relieve a constraint in
regions not administered by an RTO,
PJM states that the Commission must
direct the development of an alternate
LMP pricing scheme to establish
‘‘system marginal costs’’ that are
consistent with transparent generator
pricing in RTO markets. EPSA and PJM
argue that vertically integrated utilities
in non-RTO areas should turn over
functional control of their dispatch
function to a disinterested entity or
replicate the transparency by publishing
generation dispatch. EPSA suggests that
the Commission require this
transparency to ensure
nondiscriminatory redispatch.
1000. A few commenters state that
any requirement for the transmission
provider to purchase generation from
outside the control area to facilitate
planning redispatch is functionally
unworkable and would adversely
impact reliability.628 EEI supports the
Commission’s proposal to have
transmission providers identify offsystem resources that could provide
planning redispatch but requests
clarification that no additional
investigations or studies are required to
identify these additional options.
MidAmerican adds that the coordinated,
open and transparent planning
provisions of the NOPR should provide
customers with the ability to identify
off-system resources. EEI and Southern
state that any redispatch on adjacent
systems should be arranged by
transmission customers and the service
should be curtailed prior to other firm
uses of the system if the off-system
generator fails to perform. WAPA and
Bonneville argue against the use of offsystem redispatch, stating that lack of
control over these resources could cause
reliability problems on the originating
transmission system. WAPA also
believes that off-system redispatch
would not provide the price certainty
needed by customers because the
redispatched megawatts will differ
based on the transmission system
parameters, and customers would be
required to pay for any loop flow
resulting from the off-system redispatch.
1001. In its reply comments, EEI adds
that a requirement for transmission
providers to solicit planning redispatch
628 E.g., Xcel, PNM–TNMP, and Public Power
Council Reply.
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proposals from generators inside and
outside their control areas would
require that transmission personnel
become involved in generation and
power sales matters in violation of the
Commission’s Standards of Conduct.
Duke argues on reply that such an
approach would require that third party
generators reveal their costs to the
transmission provider and that a means
of estimating costs for all generators
subject to planning redispatch would
need to be set forth in the pro forma
OATT.
1002. LPPC, APPA and TAPS oppose
any requirement that transmission
providers redispatch their network
customer’s resources as well as their
own to provide planning redispatch,
stating that this action would
appropriate resources beyond the
Commission’s jurisdiction, result in
endless conflict between transmission
providers and resource owners, and
interfere with network customer’s use of
their limited resources.
sroberts on PROD1PC70 with RULES
Commission Determination
1003. Order No. 888 compelled
transmission providers to provide
planning redispatch from their own
resources.629 The Commission declines
to expand that obligation to require
transmission providers to solicit third
party resources in order to provide
planning redispatch. We will, however,
require transmission providers to
identify in the system impact study (1)
generation resources located within the
transmission provider’s control area,
including its own resources, that can
relieve the congested transmission
facility at issue, and (2) the impact of
each identified resource on the
congested facilities, e.g., the generator
shift factor. The resources identified in
the system impact study need not be
available to provide the redispatch.
Customers must simply be provided
with the set of generators that could, if
available, make a significant
contribution toward relieving the
constrained facility at issue. This
information, in addition to the
information provided through
congestion planning studies, will
provide the necessary information to
customers wishing to solicit third party
resources to relieve congested facilities
629 See pro forma OATT section 13.5. With
respect to SPP’s assertion that transmission owners’
affiliated generation should have no greater
redispatch obligations than unaffiliated generation
in RTOs, we find that relevant redispatch
obligations in the RTO tariff and transmission
owners’ tariffs govern this issue. See Southwest
Power Pool, Inc., 110 FERC ¶ 61,133 at P 17 (2005)
(rejecting proposed provisions that would have
removed the obligation for transmission owners to
provide planning redispatch).
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in order to accommodate long-term firm
point-to-point service. We note that this
information is readily accessible by the
transmission provider, as it is the same
information used to determine pro rata
curtailments of firm resources in
contingency situations.
1004. In addition to identifying
generation resources within the control
area, the Commission also requires
identification of resources outside the
control area that may be able to relieve
congested transmission facilities. To the
extent the transmission provider is
aware of generation resources outside of
its control area that can relieve the
constraint, the transmission provider
must inform the customer of these
resources. To be clear, this does not
require the transmission provider to
undertake any additional investigation
or study to identify generation options
located outside of the control area. To
the extent the transmission provider has
such information, however, it must
provide it to the customer.
1005. The Commission will not
mandate the use of network customer
resources or other third party resources
in the provision of planning
redispatch.630 If they choose, network
customers and third parties may
voluntarily provide planning redispatch
services. A seller is free to post its price
to relieve a specific congested
transmission facility and its ability to
relieve the congestion. To facilitate
provision of such service by third
parties, we direct transmission
providers to modify their OASIS sites to
allow for posting of these third party
offers. Accordingly, we direct
transmission providers to work in
conjunction with NAESB to develop
this new OASIS functionality and any
necessary business practice standards.
Transmission providers need not
implement this new OASIS
functionality and any related business
practices until NAESB develops
appropriate standards.
1006. Customers may then contract in
advance with these third parties or use
their own resources to secure planning
redispatch services in lieu of or in
addition to service from the
transmission provider. In this way,
customers can arrange for their own
planning redispatch through bilateral
markets and submit plans for approval
to their transmission provider and
reliability coordinator. The
arrangements must, however, be
sufficiently detailed and coordinated
630 Network customers will continue, however, to
be obligated to make their network resources
available to the transmission provider for reliability
redispatch in real time.
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12395
with the transmission provider to
ensure that reliability is maintained.
1007. We therefore direct in this Final
Rule that transmission providers work
with customers to facilitate the use of
third party generation, where available,
in provision of planning redispatch.
This entails review of redispatch plans
submitted by customers, coordination
between the transmission provider and
reliability coordinator, and signaling
third party generators when the
redispatch is needed. These
arrangements will require close
coordination between the transmission
provider, third party generators and
transmission customers. The
arrangements must be sufficiently
detailed to allow the transmission
provider to maintain reliability.
Although we will not allow
transmission providers to unreasonably
deny customers the use of third-party
resources to provide planning
redispatch, it is the customers’ ultimate
responsibility to ensure that all the
necessary contractual and technical
arrangements are in place to maintain
reliability. We clarify for Entergy that
this would allow transmission providers
to continue to provide planning
redispatch for network customers from
the network customers’ resources. We
also clarify that transmission providers
may curtail transmission customers if a
third-party resource fails to perform its
contractual redispatch obligation. This
or any other remedy for nonperformance must be specified in
writing between the parties prior to
commencement of the service.
1008. For the reasons discussed below
regarding the TDA proposal, we decline
to adopt the bid-based redispatch model
suggested by EPSA. In section V.C.1 of
this Final Rule, we similarly reject
proposals to impose LMP and
independent control of the dispatch
function. We believe that a bid-based
generation market design is not
necessary to remedy undue
discrimination in the provision of
transmission service. We also believe
that our modifications to the planning
redispatch requirement, including the
OASIS changes directed herein and the
requirement that transmission providers
make available information on
generators capable of providing
planning redispatch, will provide
potential customers with greater
information about redispatch choices
and enable greater opportunities for
planning redispatch and comparable
service.
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(C) Pricing of Planning Redispatch
sroberts on PROD1PC70 with RULES
NOPR Proposal
1009. In the NOPR, the Commission
sought comment on which type of
redispatch pricing would ensure
effective use of the planning redispatch
option. The Commission described one
type of pricing, a formula rate, to
include a MW quantity, the incremental
cost of fuel at the point of delivery, and
the decremental cost of fuel at the point
of receipt capped at the price of fuel.
The Commission sought further
comment on whether it would facilitate
planning redispatch to base calculations
of the various costs for input into the
formula on the difference between the
cost of ramping up a generator at the
point of delivery and ramping down a
generator at the point of receipt. The
Commission also described a redispatch
pricing proposal to calculate redispatch
charges monthly and charge the higher
of actual redispatch costs or the OATT
rate each month made by PacifiCorp in
response to the NOI.
Comments
1010. While many specific comments
were received on the pricing of planning
redispatch service, there is little
consensus on this subject. Several
commenters state that pricing
challenges associated with planning
redispatch are difficult if not
insurmountable.631
1011. MidAmerican and EEI argue
that the current cap on planning
redispatch at the costs of upgrades
should be removed because a customer
will always choose planning redispatch
and the risks that redispatch costs
exceed construction costs falls to the
transmission provider and is either
unrecoverable or passed on to other
customers.
1012. According to several
commenters, requiring the transmission
provider to establish a standard fee for
planning redispatch, either on the
overall system or on a path-by-path
basis, would accomplish cost certainty
for the customer and hold the
transmission provider accountable for
the accuracy of the studies used to
assess redispatch requirements.632
These commenters support a
standardized formula-rate for planning
redispatch or a capped amount at, or
close to, the embedded cost rate. Entegra
and TransAlta state that the redispatch
pricing proposal may allow
transmission providers discretion to
charge redispatch costs without
631 E.g., Powerex, Manitoba Hydro, Seattle,
NRECA, Ameren, and E.ON.
632 E.g., Utah Municipals, Public Power Council,
PPM, Entegra, Constellation, TransAlta and TAPS.
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providing customers a practical way to
verify that claimed redispatch costs
have actually been incurred. PGP states
that the Commission should allow for
regional differences in planning
redispatch pricing. APPA does not
support a departure from the current
redispatch pricing approach, while
Seattle states that the existing section
13.5 is unworkable because the cost of
planning redispatch is difficult to
calculate for both historical and nearterm operating horizons, much less over
a multi-year planning horizon.
1013. EPSA and AWEA believe that
the pricing mechanisms suggested in the
NOPR would be open-ended and highly
variable over the duration of the
reservation and, thus, not meet the
needs of customers. EPSA and AWEA
assert that, consistent with Commission
precedent,633 a utility must identify and
justify its costs in excess of average
system costs before service commences
in a manner that meets the customer’s
needs to charge a rate in excess of
average system costs, i.e., some
customers may require a firm estimate
upfront to obtain financing while others
may be willing to negotiate a rate based
on estimates.634 EEI states on reply that
the policy in American Electric Power
related to an expansion cost rate, which
is inapposite to redispatch costs because
the costs of new construction are easier
to estimate in advance than are the costs
of planning redispatch. EEI contends
that the planning redispatch customer’s
interest in price certainty is not a
sufficient basis for shifting costs to other
customers or to the transmission
provider.
1014. EPSA and AWEA suggest that,
when the cost of planning redispatch is
estimated to exceed the transmission
rate, the transmission provider should
offer either: a formula rate for
incremental redispatch costs with the
number of hours of redispatch, the
resources to be redispatched and the
conditions under which redispatch
would occur defined in advance or, an
incremental cost rate determined at the
time of the reservation to cover the
reservation period that may include a
risk adder for the transmission provider.
Morgan Stanley argues that planning
redispatch options should include the
following: Redispatch priced at a market
index; where market prices are not
available, the price should be the
incremental costs; full cost pricing
should be allowed for ‘‘life of service’’
(total dollar cost for unlimited
redispatch over the term of a contract)
633 American Electric Power Service Corp, 64
FERC ¶ 61,279 (1993) (American Electric Power).
634 Id. at 62,976.
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or fixed rate contracts for actual
redispatch agreed to at the time of
contracting; and redispatch costs
provided from a third-party provider.
Morgan Stanley opposes ‘‘higher of’’
pricing that would allow for monthly
charges for redispatch costs or long-term
firm transmission service rate.
1015. In contrast, many transmission
providers and EEI ask the Commission
to allow for recovery of actual costs of
redispatch, rather than the estimated
costs, with the customer obligated to
pay all costs.635 Since providing
accurate estimates of redispatch costs
and hours are difficult, especially with
respect to longer-term service requests
given the variability of fuel costs,
transmission providers contend that
they should not bear the risks of
inaccurate cost estimates for a service
that benefits only the point-to-point
customer.636 Indianapolis Power adds
that planning redispatch should be
priced to discourage inefficient dispatch
of generation. In its reply comments,
PPM agrees that planning redispatch is
unworkable without certainty of cost
recovery for the transmission provider,
but believes that with enough
information customers can evaluate the
risks and gain certainty required for a
workable product.
1016. Southern argues that the current
pro forma OATT language unreasonably
places the risk of uncertainty in
estimating redispatch costs on the
transmission provider and its native
load customers, contrary to basic cost
causation principles and native load
protections in Order No. 888. Southern
suggests that the Commission follow the
approach in the Deseret and SPP tariffs,
which allow for the transmission
provider to recover its actual costs of
redispatch. Ameren states that a
standard per kWh fee is simpler to
administer, but should be structured to
recover all of the costs of planning
redispatch, including opportunity costs.
1017. Various commenters argue that
the Commission should allow the
following redispatch costs to be
recovered: Fuel; variable operations and
maintenance; increased maintenance
costs due to cycling; start-up and rampdown costs; emergency purchases; costs
of additional operating reserves;
environmental costs; and lost
opportunity costs.637 MidAmerican also
argues that a transmission provider
should be able to recover the costs of
635 E.g., Southern, MidAmerican, Entergy,
FirstEnergy, Ameren, Nevada Companies, E.ON,
and South Carolina E&G.
636 E.g., EEI, Entergy, LPPC, NRECA,
MidAmerican, Ameren, and FirstEnergy.
637 E.g., LDWP, EEI, Ameren, MidAmerican, and
Southern.
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redispatch energy purchased in
response to a pre-schedule by a
planning redispatch customer regardless
of schedule changes by the customer
and regardless of any pro rata
curtailments affecting such customers
due to system reliability.
1018. EEI and Southern argue that
customers that choose planning
redispatch should pay the cost of
transmission service and the cost of
redispatch. EEI asserts that allowing
recovery of both costs is not prohibited
‘‘and’’ pricing because the services
differ, as one is provided by the
transmission system and one is
provided by generators, and native load
and network customers pay pro rata
shares of reliability redispatch costs to
relieve constraints on the system as well
as the basic costs of transmission
service. TAPS and TDU Systems take
the opposite view and state that the
Commission should require planning
redispatch pricing consistent with the
Commission’s ‘‘higher of’’ or ‘‘or
pricing’’ policy. In addition, they state
that the redispatch charges must be
capped up front at fixed dollars and
hours at or close to the embedded cost
rate.
1019. Arkansas Commission agrees
with the PacifiCorp pricing method in
which redispatch costs are recalculated
monthly and customers are charged the
higher of the redispatch cost rate or the
monthly OATT transmission rate. TAPS
states that this method avoids ‘‘and’’
pricing, but does not address the
complexity or risks associated with
determining redispatch costs over a long
period. APPA argues that the PacifiCorp
proposal, if applied after the fact, could
lead to uncertainty and disruption of
market transactions. Southern opposes
any pricing method that caps the total
costs that a planning redispatch
customer would bear, including the
PacifiCorp proposal, stating that caps
allow the planning redispatch customer
to shift costs to the transmission
provider and its native load customers.
1020. E.ON points to an inherent
problem in planning redispatch pricing:
Transmission providers should be kept
whole with regard to actual real-time
redispatch costs but customers may not
know until after the fact that the
planning redispatch was not economic
for their purposes. E.ON foresees
difficulty in allocating redispatch costs
among multiple planning redispatch
service customers and requests that the
Commission adopt a specific
methodology for calculating each
request’s impact on the system.
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Commission Determination
1021. Although there is no consensus
regarding which form of pricing
methodology is most appropriate for
planning redispatch service, there is
general agreement among the
commenters that the current pricing
rules fail to meet the needs of either
customers or transmission providers
and consequently fail to make planning
redispatch an attractive means for
customers to obtain access to the grid.
Transmission providers and customers
both express concern regarding the
variability of redispatch costs.
Customers worry that actual redispatch
costs may greatly exceed estimates and
thus seek cost certainty over the term of
the service. Conversely, transmission
providers claim that accurately
estimating future redispatch costs for
long duration service is extremely
difficult. In fact, transmission providers
state that the uncertainty in forecasting
long-term redispatch costs is much
greater than any uncertainty inherent in
determining the costs of transmission
upgrades.
1022. The Commission has carefully
considered these comments and agrees
that the current method for pricing
planning redispatch service is no longer
just, reasonable or not unduly
discriminatory. The Commission takes
three principal actions to address the
concerns of customers and transmission
providers.
1023. The Commission therefore
adopts a new pricing method for
planning redispatch service. We will no
longer require the capping of redispatch
costs over the term of the service at the
costs of expansion. This change is
inextricably linked with the change in
the obligation to provide planning
redispatch, i.e., the removal of the openended requirement to provide planning
redispatch as long as it is more
economical than transmission upgrades.
We have shortened the planning
redispatch obligation to apply before
upgrades are built as a bridge product or
to apply as part of a reassessment
product. In prior cases, the Commission
expressed the view that capping cost
recovery for long-term transmission
service at the costs of expanding the
transmission system provides an
incentive for transmission providers to
undertake expansion when it is
warranted.638 The expansion cost cap
should not be applied to the bridge
product because (1) upgrades will in
fact be constructed and should be paid
for by the customer under the ‘‘higher
of’’ policy, and (2) an expansion cost
638 See, e.g., Florida Power & Light Co., 70 FERC
¶ 61,158 at 61,484 (1995).
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12397
cap does not serve as an incentive for
expansion because the transmission
provider already will have started the
process of building transmission
facilities for the customer who opts for
the bridge product. If planning
redispatch is provided as part of a
reassessment product, the customer has
chosen not to pay for upgrades and thus,
the expansion cost cap cannot provide
an incentive for transmission expansion.
1024. We will therefore adopt a new
pricing methodology. We believe that
the PacifiCorp proposal described in the
NOPR is the one that balances the
competing concerns of transmission
customers and transmission providers.
Under this pricing methodology,
customers will have the option of
paying (1) the higher of (a) actual
incremental costs of redispatch or (b)
the applicable embedded cost
transmission rate on file with the
Commission or (2) a fixed rate for
redispatch to be negotiated by the
transmission provider and customer and
subject to a cap representing the total
fixed and variable costs of the resources
expected to provide the service. If the
customer selects the higher of
incremental cost or the embedded-cost
rate, the transmission provider shall
calculate the costs of redispatch
monthly and charge the higher of
redispatch or the embedded cost rate
each month.
1025. We have selected a monthly
comparison of embedded costs and
redispatch costs on the basis of a
number of factors. The Commission has
rejected basing the comparison on the
life of a long-term firm transmission
contract.639 For administrative
efficiency, a transmission provider
should be allowed to close its books and
not be subject to possible refunds or
surcharges at the end of its billing cycle.
The standard billing cycle in the
industry is one month. Allowing
transmission providers to finalize
accounting entries will provide
certainty to both the transmission
provider with regard to revenue
recovery and to the transmission
customer with regard to cost exposure.
We therefore find that a monthly
comparison of embedded and
incremental cost is appropriate. This
method retains ‘‘higher of’’ pricing for
customers, but does not subject
transmission providers to open-ended
liability for refunds and otherwise
should make planning redispatch
service more attractive for transmission
providers to provide. Further, given that
redispatch often occurs only in selected
time periods within a year (e.g., during
639 Id.
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the peak season, shoulder months, etc.),
it is just and reasonable to allow the
transmission provider to perform the
higher of calculation in each month
when the service is provided, not spread
those costs over the entire year.
1026. For purposes of calculating
planning redispatch charges,
incremental costs shall include fuel or
purchase power costs caused by
ramping up generator(s) at the point of
delivery and ramping down generator(s)
at the point of receipt. Additionally,
where applicable, transmission
providers may specify in customer
service agreements other incremental
costs for inclusion in the monthly actual
incremental costs, including
opportunity costs. Identification and
derivation of these costs must be
included in the service agreement. We
reiterate our existing requirement that
all information necessary to calculate
and verify opportunity costs must be
made available to the transmission
customer.640 We clarify that the actual
costs of redispatch need not be
determined annually or at the time that
the service agreement is executed;
rather, actual redispatch cost should be
determined on a monthly basis.
1027. With respect to MidAmerican’s
request to be able to recover the
purchase power costs for a customer
requiring planning redispatch, we
reiterate that transmission providers are
under no obligation to purchase power
to provide planning redispatch services.
Should the transmission provider take
on the obligation to contract with a third
party to provide planning redispatch at
the customer’s request, however, the
customer should be obligated to pay the
purchase power costs, including any
reservation charge for the power. The
flow-through of purchase power costs
must be negotiated between customers
and transmission providers in a standalone agreement if the transmission
provider agrees to make purchases on
the customer’s behalf.
1028. The Commission will not adopt
proposals suggested by several
transmission providers to allow for
recovery of the embedded cost
transmission rate and the full costs of
redispatch. The Commission’s ‘‘higher
of’’ pricing policy prohibits the
transmission provider from charging
both embedded costs and incremental
costs such as redispatch costs.641 We
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640 See
Order No. 888 at 31,740.
Pennsylvania Electric Company, 58 FERC
¶ 61,278, 62,871–75, reh’g denied, 60 FERC ¶ 61,034
(1992), aff’d sub nom. Pennsylvania Electric Co. v.
FERC, 11 F.3d 207 (D.C. Cir. 1993); see also Entergy
Services, Inc., 71 FERC ¶ 61,139, 61,452 (1995)
(regarding the pricing of redispatch service, the
Commission stated ‘‘[i]t is a well-settled matter that
641 See
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reject EEI’s assertion that we should
adopt such pricing because native load
and network customers pay a load ratio
share of redispatch costs and the
embedded cost transmission rate.
Planning redispatch differs from the
reliability redispatch for which
transmission providers are only
obligated to provide network customers
with ability to avoid real-time
curtailments. Rather, planning
redispatch is a means of creating
additional transmission capacity,642 not
a generation service, and thus planning
redispatch is appropriately priced by
applying the Commission’s ‘‘or’’ pricing
policy. We decline to revisit that
longstanding policy in this rulemaking.
1029. With respect to concerns that
the expansion cost cap was adopted to
provide rate certainty to customers over
the term of the service,643 we believe
that the modified pricing policy adopted
here will continue to provide
appropriate certainty to customers,
while also allowing transmission
providers to recover just and reasonable
costs. For customers purchasing the
bridge product, the cost of redispatch
will be incurred only during the initial
term of the service agreement while new
facilities are being constructed. During
this term, the cost of redispatch service
represents a legitimate cost of providing
the service and therefore should be fully
recoverable under the higher of policy.
Although it is true that redispatch costs
are difficult to project, and hence create
uncertainty for customers, this does not
mean that the transmission provider
should not be allowed to recover the
legitimate and verifiable costs of
providing the service. Moreover, if the
customer desires greater certainty
regarding redispatch costs during this
period, it can elect the fixed rate option
discussed above and negotiate a fixed
redispatch charge with the transmission
provider. Once upgrades are
constructed, however, the customer will
receive the certainty of paying a fixed
rate for transmission costs and,
importantly, any expansion cost will be
fixed at the time the initial service
agreement is signed. Finally, for
customers who do not select the bridge
product because they do not want to
fund upgrades, it would be
unreasonable to cap the cost of
redispatch at the cost of upgrades. In
such an instance, the customer has
elected to forego the price certainty that
the Commission will not authorize ‘‘and’’ pricing,
i.e., embedded cost pricing plus opportunity
(incremental) cost pricing.’’).
642 Order No. 888A at 30,267.
643 Florida Power & Light Co., 70 FERC ¶ 61,158
at 61,483 (1995).
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can be gained by funding the upgrades
to remove the constraint that is causing
the transmission provider to incur
redispatch costs.
(D) Standards of Conduct and Planning
Redispatch
NOPR Proposal
1030. In the NOPR, the Commission
requested comment on the interaction of
planning redispatch requirements with
the Commission’s Standards of Conduct.
Comments
1031. Commenters generally argue
that the independent functioning
requirement and the information
sharing prohibitions under the
Standards of Conduct are irreconcilable
with the expanded planning redispatch
proposal in the NOPR.644 Southern,
TranServ and Progress Energy contend
that the planning redispatch option
would require close coordination and
communication with market
participants including the marketing or
energy affiliate, which may create
confidentiality and Standards of
Conduct problems. For instance, they
state that close coordination and sharing
of non-public transmission and
customer information would be required
to determine the generating units that
can be redispatched, the impact that
planned and forced outages of
redispatched generators will have on the
availability of transmission service and
the transmission line loadings, and the
costs of redispatch. Some commenters
request that the Commission adopt an
exception to the Standards of Conduct
to permit communication between
transmission providers and marketing
and energy affiliates, acting as
generation operators, for the
transmission provider to instruct the
generation operator to vary its
generator’s output.645
1032. MidAmerican suggests that it is
unlikely that any communication
protocols could be established that
would both comply with the
Commission’s current Standards of
Conduct and permit a transmission
provider to coordinate with its
marketing affiliate employees to arrange
planning redispatch. Rather,
MidAmerican argues that the
transmission customer would have to
waive the Standards of Conduct to
enable the transmission function
employees to share the necessary
information with their marketing
affiliate counterparts.
644 E.g., Nevada Companies, Community Power
Alliance, Progress Energy, LPPC, Southern, WAPA,
and APPA.
645 E.g., E.ON, Ameren, and APPA.
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1033. Other commenters argue that
violations of the Standards of Conduct
can be avoided by various means. PPM
suggests that publication of redispatch
costs similar to ancillary service costs
and elimination of case-by-case sharing
of information between the transmission
provider and the generation operators
would avoid Standards of Conduct
issues. MidAmerican states that sole
reliance upon bilateral agreements with
third parties to provide planning
redispatch would resolve the need to
modify the Standards of Conduct. In
their reply comments, Utah Municipals
state that they do not believe the
Standards of Conduct pose a barrier to
provision of planning redispatch since
transmission providers redispatch to
serve their own loads currently, but that
if so the Commission should make small
modifications to the standards.
Commission Determination
1034. The Commission does not
believe that any changes to its Standards
of Conduct are required for transmission
providers to implement the planning
redispatch provisions adopted in this
Final Rule. The information at issue,
e.g., generation redispatch cost, is held
by the marketing affiliate and there is no
prohibition under our Standards of
Conduct on the marketing affiliate
transferring such information to the
transmission provider. The information
sharing prohibitions under the
Standards of Conduct are ‘‘one way,’’
i.e., they restrict only communications
of non-public transmission information
from the transmission provider to the
marketing affiliate, not vice versa.
Therefore, the flow of information from
marketing affiliates to transmission
providers relating to the costs and
availability of generation resources for
planning redispatch is not prohibited
under the Commission’s Standards of
Conduct.646
1035. We next turn to the flow of
information from the transmission
provider to the marketing affiliate.
Initially, in order for transmission
providers to evaluate planning
redispatch options, they must identify
the impacted transmission facilities,
e.g., flowgates, and determine the
marketing affiliate’s generators that
could provide redispatch over those
facilities. Transmission providers
already have this information to enable
them to provide least cost reliability
redispatch. However, transmission
providers need not provide information
regarding the impacted transmission
facilities to its marketing affiliates.
Rather, in order for transmission
646 18
CFR 358.5.
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providers to evaluate the future
availability of redispatch and estimate
the costs of redispatch, they need only
tell the marketing affiliate which of its
generators would be suitable for
redispatch, thus identifying those that
require study. This sharing of
information relating to the marketing
affiliate’s generation is not prohibited by
the Commission’s Standards of Conduct.
1036. In addition, the transmission
provider may also need to provide its
marketing affiliate with transmissionrelated information from the
transmission customer’s service request,
such as service quantity and term, to
determine the required duration and
amount of the redispatch required. We
find that such information provided
from the transmission provider to the
marketing affiliate is not a prohibited
transfer of non-public information
because such details of the transmission
customer’s service request are available
via OASIS. The only customer
transmission request information not
readily available via OASIS is the
source and sink information.647 We see
no need for the transmission provider to
provide such masked source and sink
transmission information to its
marketing affiliate as part of this
redispatch evaluation process. We do
not believe that any further information
need be provided by the transmission
provider to their marketing affiliates to
evaluate the generators available for
planning redispatch and their costs.
Accordingly, we find there is no need to
create an exception to the Standards of
Conduct for the sharing of this
generation-related information and
publicly available transmission
customer request information.
(E) Attributes of Conditional Firm
NOPR Proposal
1037. In the NOPR, the Commission
described conditional firm service as a
modified form of point-to-point service
that includes non-firm service in a
defined number of hours of the year
when firm point-to-point service is not
available. The Commission proposed
that the conditional firm service
agreement would identify the
conditional curtailment hours and
include an annual or monthly cap on
those hours. The Commission further
proposed that conditional firm service
would be curtailed before firm uses
until such times as the conditional
curtailment hours were exceeded, after
which time the service would be treated
647 See Open-Access Same-Time Information
System and Standards of Conduct, 83 FERC
¶ 61,360 at 62,456 (1998), reh’g denied, 86 FERC
¶ 61,139, reh’g denied, 87 FERC ¶ 61,382 (1999).
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12399
as firm. The curtailment priority during
the conditional period was proposed as
the same as secondary network service.
The Commission proposed that
customers using the conditional firm
option would pay the long-term firm
point-to-point rate. The Commission
also proposed that conditional firm
service qualify for rollover rights,
provided that it meets the other rollover
right conditions proposed in the Final
Rule.
(i) General Terms and Conditions
Comments
1038. Most commenters support
pricing conditional firm service at the
long-term firm OATT rate and no
commenter suggested a different pricing
method. Nevada Companies and
Bonneville state that the customer
seeking conditional firm service should
pay the actual costs of the study
required to provide the number of
conditional curtailment hours.
1039. EPSA and AWEA support the
following components of the
Commission’s conditional firm
proposal: Conditional firm is available
only to customers that first request longterm service; it would provide a year
round, long-term product that is firm
during all hours of the year except at
well-defined periods when the
transmission provider is unable to
provide the service; and, in all hours
that are not conditional, conditional
firm service would be treated as any
other firm service with the same
curtailment priority as long-term firm
network and point-to-point rights.
1040. EEI proposes that conditional
firm service be firm in periods when
firm service is available according to
ATC calculations and non-firm, with a
monthly non-firm curtailment priority,
for periods when firm ATC is not
available. CREPC, Exelon and
MidAmerican argue that the
Commission should not require
conditional firm service until all
attributes of the service are clearly
defined and key implementation issues
are resolved, including modification of
NAESB and NERC processes. NAESB
states that the Commission can reduce
the amount of time required to develop
OASIS and transmission loading relief
protocols by clearly defining the
conditional firm service.
1041. In its supplemental comments,
EEI states that the Commission should
not require all transmission providers to
adopt terms and conditions for
conditional firm service that are only
workable for some systems, e.g.,
transmission providers in the Western
Interconnection using the rated path
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methodology compared to many in the
Eastern Interconnection using a flowbased methodology; rather, the
Commission should allow flexibility in
the offer of conditional firm service so
that transmission providers are not
foreclosed from offering the service.
1042. Several commenters state that
transmission providers and customers
collectively should design the
conditional firm service that best
accommodates their respective needs.648
In supplemental comments, Bonneville
states that the transmission provider,
not the customer, must determine the
conditions to offer in response to a
given request. Bonneville also requests
that the Commission clarify that there
would be no separate queue for
conditional firm service.
Commission Determination
1043. The Commission adopts the
conditional firm option as a modified
form of long-term firm point-to-point
service that includes less-than-firm
service in a defined number of hours of
the year or during defined system
conditions when firm point-to-point
service is not available. The service can
be curtailed solely for reliability reasons
during the defined system conditions or
defined number of hours. We reject
EEI’s suggestion to use a monthly nonfirm curtailment because it would allow
for curtailment of the conditional
service for economic reasons.
1044. In this Final Rule, we define the
minimum attributes of the conditional
firm option rather than allow individual
transmission providers to develop any
form of service that could conceivably
be labeled conditional firm service. The
Commission has been considering a
conditional firm product and has been
discussing it with the industry for some
time. In early 2005, the Commission
held a technical workshop to:
Work with market participants to develop
clear definitions for additional wholesale
electric transmission services, e.g.,
conditional firm transmission service,
develop applicable pro forma tariff language
that could be included in public utilities’
open access transmission tariffs and address
attendant issues.649
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Although commenters in that
proceeding stated that the Commission
need not require new services in
transmission providers’ OATTs because
648 E.g., LPPC Supplemental, PPL Supplemental,
Williams Supplemental, Community Power
Alliance Supplemental, Entergy Supplemental, and
Southern Supplemental.
649 Potential New Wholesale Transmission
Services, Notice of Final Agenda for Technical
Workshop, 70 FR 12865 (Mar. 16, 2005).
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they would be voluntarily developed,650
no individual transmission provider
developed new services in response to
the workshop. In fact, seemingly, only
one transmission provider in the Eastern
or Western Interconnection offers a
service that is similar to the conditional
firm service adopted in this Final
Rule.651
1045. Since the issuance of the NOPR,
the Commission has provided the
industry with three formal opportunities
to provide comments on
implementation of the conditional firm
option. The Commission held a
technical conference on implementation
issues after issuance of the NOPR and
held many informal technical
discussions with industry
representatives. We have taken these
steps in order to make the most
reasoned decision concerning the
minimum attributes of the conditional
firm option. These conferences and
workshops have been helpful and have
informed our decision on the minimum
attributes of conditional firm service. As
noted herein, although we are
establishing certain minimum attributes,
we also allow for some measure of
flexibility in provision of the service.
We will not, however, approve
conditional firm as a concept only.
Given our past experience, this would
provide little benefit to customers
seeking to use the service and no
certainty to transmission providers
seeking to comply with our regulations.
1046. Further, as discussed in more
detail below, we disagree that NERC
must modify its processes in order to
allow transmission providers to
implement this product. However, we
will allow for a sufficient period of time
for development of business practices
and tracking mechanisms to implement
the product. We recognize that there
may be some regional variation in the
way transmission providers approach
the provision of conditional firm service
beyond the minimum attributes that we
establish in this Final Rule. Thus, we do
not direct that transmission providers
work with NAESB to develop business
practices for implementation of the
conditional firm service. Rather, we
650 E.g., Bonneville Workshop Comments at 1–2
(April 13, 2005) (stating that Bonneville believes the
result of the workshop ‘‘will be the development of
one or more new transmission products.’’), TAPS
Workshop Comments at 2 (April 13, 2005)
(suggesting that the Commission should invite and
consider proposals by individual utilities rather
than act by rulemaking).
651 In the NOPR, the Commission noted
PacifiCorp’s 2002 modifications to partial interim
service. See NOPR at P 319 n.298. PacifiCorp’s
service is similar to that proposed by EEI with the
exception that customers are charged a pro rated
long-term firm rate.
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direct transmission providers located in
the same region to coordinate such
development among themselves. We
also encourage participation of nonpublic utility transmission providers in
the region and interested transmission
customers in the development of these
business practices. Public utility
transmission providers should make
efforts to include these interested
parties in their regional coordination
efforts. We direct transmission
providers to implement these
mechanisms and business practices
within 180 days after the publication of
this Final Rule in the Federal Register.
1047. The Commission adopts the
proposal in the NOPR that customers
using the conditional firm service pay
the long-term firm point-to-point rate.
We will not allow complete flexibility
in defining the conditional firm option
as suggested by EEI because such an
option could provide a substantially
lower quality service for which
transmission providers would be able to
recover the long-term firm rate. We also
reject EEI’s proposal that the service be
a mix of firm and non-firm periods. We
envision the conditional firm option as
one in which firm service is available
most of the period of a year. EEI seems
concerned about tailoring the product to
situations where congestion is so acute
that the ‘‘conditions’’ require frequent
interruptions. We do not believe this
concern is well founded. Because a
conditional firm customer is obligated
to pay the long-term firm point-to-point
rate, we assume that few, if any,
customers would accept the service in
circumstances where the interruptions
(or ‘‘conditions’’) are so frequent or
pervasive to make the service
unattractive.
1048. Finally, we clarify for
Bonneville that customers seeking the
conditional firm option must first
request long-term firm service. When
ATC is unavailable, the transmission
provider must study the conditional
firm option at the customer’s request.
There is no separate queue for the
conditional firm option.
(ii) Specified System Conditions and
Conditional Hours
Comments
1049. Several transmission providers
state that they cannot accurately predict
the conditional curtailment hours
because there are too many variables to
consider and ATC analysis does not
provide this level of granularity.652
These commenters contend that load
flow modeling for a wide range of
652 E.g., Imperial, Duke, Progress Energy,
MidAmerican, PNM–TNMP, Southern, and EEI.
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possible system conditions required to
estimate the conditional curtailment
hours would be complex, timeconsuming and costly. Given this
concern, Southern, PNM–TNMP, and
MidAmerican state that any conditional
firm service should be subject to a
‘‘reasonable efforts’’ standard and not
represent a guarantee of service or a
binding estimate of conditional
curtailment hours from the transmission
provider. Progress Energy states that it
would be difficult to determine a
specific number of hours that firm
service is available, given that the
industry uses seasonal models. Ameren
states that the conditional curtailment
hours should be spelled out in the
transmission service agreement.
1050. Several commenters state that
the transmission provider should
provide customers a choice between
defined system conditions and
conditional curtailment hours.653 In
supplemental comments, EPSA and
AWEA state that neither option should
be arbitrarily excluded; rather, they
argue that transmission providers
should consult with each customer in
determining the defined conditions that
could form the basis of the conditional
firm service. EPSA and AWEA propose
that conditional firm should be firm
during all hours of the year except in
those hours in which a defined
contingency occurs, and the
transmission provider is actually unable
to provide service. EPSA and AWEA
also propose that the system impact
study should describe the reliability
contingency and the transmission
service agreement should clearly define
the contingency.
1051. EPSA and AWEA state that
conditional firm should only be
curtailed after all non-firm services are
curtailed on the same constrained path
during the period of the defined
contingency. Finally, AWEA and EPSA
state that transmission providers must
maintain the committed capacity subject
to the defined contingency only, reflect
capacity commitments for conditional
firm service in their ATC calculations,
and be prevented from further curtailing
conditional firm service due to load
growth after the execution of the initial
service agreement.
1052. AWEA proposes that if a service
agreement specifies conditional
curtailment hours, the transmission
provider must provide firm service
except in the curtailable hours defined
in the service agreement and the service
must be treated as firm unless the
653 E.g., Barrick Supplemental, Bonneville
Supplemental, BP Energy Supplemental, and EPSA
and AWEA Supplemental.
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transmission provider is actually
required to curtail transactions to meet
reliability requirements and all non-firm
transactions have been curtailed. Once
the transmission provider has reached
the annual cap on curtailable hours,
AWEA argues the customer’s service
should convert to traditional firm
service for the remainder of that annual
period.
1053. Utah Municipals reply that
transmission providers should be bound
by their calculations of the availability
of firm service, even if the firm service
is not available year-round.
1054. FirstEnergy and Nevada
Companies state that monthly caps, as
opposed to annual caps of curtailment
hours, would be preferable because they
provide more information to the
customer and are more appropriate for
transmission systems with mostly
seasonal constraints. According to
Nevada Companies, a curtailment based
upon the maximum number of hours
per year, without taking into account
the specific times or conditions for
those curtailments, would be
unworkable in the context of a seasonal
peak system, such as exists with Nevada
Companies.
1055. Several commenters support a
variation on conditional firm service
that would allow a transmission
provider to specify either the
transmission facilities/elements that
may become constrained or the
operating conditions that will result in
curtailments of a particular conditional
firm service.654 Many of these
commenters propose a defined system
condition as the trigger for non-firm
curtailment of the service rather than
the use of conditional curtailment
hours.655 Entergy and LPPC propose
that such curtailments have the same
priority as secondary network service.
Entergy contends that this service
would be superior to the conditional
firm service described in the NOPR
because it would be more comparable
with the service transmission providers
make available to network customers
and would minimize the risk to other
customers who might otherwise bear the
cost of inaccurate conditional
curtailment hours, as well as disputes
between the transmission provider and
the transmission customer regarding the
number of conditional curtailment
hours. Seattle and Santee Cooper
suggest that defining the limitations on
the service based on operating
654 E.g., AWEA, EPSA, Project for Sustainable
FERC Energy Policy, Santee Cooper, Seattle,
Entergy, and LPPC.
655 E.g., Santee Cooper, Seattle, Entergy, LPPC,
and Nevada Supplemental.
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conditions, with non-binding estimates
of hours of curtailment, would lead to
more effective and reliable operation of
the transmission system that is
consistent with regional requirements.
1056. In supplemental comments,
Bonneville asserts that the transmission
provider should have the option of
offering conditional curtailment hours
or specified system conditions in order
that the transmission provider can make
a prudent choice based on available
historical system data.
1057. In supplemental comments,
TAPS argues that conditional firm
service should be limited to 100 hours
per year of conditional curtailment,
subject to curtailment on the same basis
as firm service beyond those hours, and
made available to and integrated with
network customers. In TAPS view, this
would result in a more efficient use of
the grid, provide customers sufficient
certainty to sign long-term power
purchase contracts and promote
transmission construction. TAPS also
believes that the customer should have
the option of expressing the curtailment
restriction on the basis of specified
system conditions in the 100-hour
range.
1058. In its supplemental comments,
Entergy suggests that the Commission
allow more flexibility between the
contracting parties to identify the
conditional nature of the service, i.e.,
the Commission should not prescribe
parameters of the conditional period
that may ignore real-time conditions on
the transmission provider’s system that
require a curtailment.
1059. EEI, Duke, and PNM–TNMP
object, in their supplemental comments,
to specifying system conditions or the
maximum number of curtailment hours
per year, stating that requiring either
would be incompatible with current
curtailment procedures and unfairly
shift risks of curtailment to other firm
customers. EEI, Progress Energy and
Duke argue that the service should be
curtailable during a particular season,
month or other defined period to
provide more certainty to the
transmission customer and the
transmission provider as to when the
service is subject to curtailment.
1060. With regard to modeling
methods for estimating the conditional
curtailment hours, EEI asks the
Commission not to require the
transmission provider to use a specific
methodology to evaluate whether it can
provide conditional firm service.
Bonneville argues that transmission
providers need flexibility to modify
their ATC methodologies to
appropriately model the new service
and avoid planning obligations to firm
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up the conditional curtailment hours of
a conditional firm reservation. Nevada
Companies suggest that the transmission
provider use the appropriate seasonal
operating case with updated projections
to determine the amount of requested
service that can be provided without
violating reliability criteria.
1061. Ameren argues that when a
transmission provider models system
contingency events, the events are not
interchangeable with a number of hours.
According to Ameren, the two
measurements will produce different
impacts for the transmission system,
and the transmission provider should
not be required to make both options
available at the customer’s option. LPPC
and Public Power Council state that
transmission providers should not be
required to limit the number of
curtailments on a monthly or yearly
basis because of the inherent
unpredictability of future transmission
constraints. APPA states that using
curtailment based on a specified
number of hours will cause the
transmission provider to overestimate
the number of curtailment hours.
1062. NRECA believes that the
Commission should allow for regional
flexibility in the determination of the
parameters of the service and
transmission providers should have
maximum flexibility to set conditions
that use conservative assumptions (e.g.,
based on the driest weeks of the year,
summer or winter peak period
constraints). NRECA believes such
service should be conditioned on
operating conditions as well as with
reference to a number of times of
interruption. In contrast, MISO supports
the election of a consistent method of
curtailment applied to all customers, in
order to make the service easier to
implement.
1063. Powerex states that conditional
firm service should be offered only on
paths where curtailment to existing
long-term customers is not expected to
occur.
Commission Determination
1064. The Commission requires that,
when conducting the system impact
study for the conditional firm option,
the transmission provider shall identify:
(1) The specific system condition(s)
when conditional curtailment may
apply; and (2) the annual number of
hours when conditional curtailment
may apply. A customer must select
either conditions or hours for
incorporation into its conditional firm
service agreement.
1065. We require the offer of specific
system conditions during which
conditional curtailment may apply for
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several reasons. Specified system
conditions give certainty to the
customer that it will only be
conditionally curtailed when forecasted
reliability problems actually occur.
Transmission providers benefit from
this option because they can point to
specific constraints on their system and
implement a curtailment plan when
those transmission elements are
constrained. Additionally, designation
of specific system conditions may allow
for a better fit of the conditional firm
service to a specific transmission
provider’s system. Consider the example
of firm service that is not available on
a specific system because a transmission
line is taken out of service for
maintenance about two weeks a year.
The designation of this line as the
specific condition for conditional firm
service would allow the transmission
provider to provide firm service without
having to worry if the maintenance on
the line takes an extra week. The
conditional firm customer has fewer
concerns about undue discrimination by
the transmission provider and could
benefit from maintenance on the line
that was finished one week early.
Additionally, we note that many
commenters representing transmission
providers and customers support this
approach.
1066. We will require specificity of
system conditions. Acceptable system
conditions include, but are not limited
to, designation of limiting transmission
elements, such as a transmission line,
substation or flowgate. We do not
believe, however, that designation of
system load levels, standing alone,
would qualify as an acceptable system
condition. Rather, load levels would
have to be linked to a specific constraint
or transmission element that is
associated with the request for service,
e.g., load levels in a constrained load
pocket. Otherwise, the system load level
would not be specific to the part of the
system over which service is requested
and, hence, have no necessary relation
to the problems, if any, created by the
service being requested. Furthermore,
because most system loads experience
load growth every year, conditional
curtailments would necessarily increase
over a multi-year conditional firm
service term.
1067. We recognize that modeling of
the conditional curtailment hours
entails difficulties beyond those
encountered in modeling ATC. To
address these difficulties we are
allowing flexibility in determining the
number of hours. We clarify that we will
not require a standardized method of
modeling the conditional curtailment
hours. We also note that the
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Commission’s examination of modeling
methods in the NOPR was not meant to
propose one method over another;
rather, it was meant to examine possible
ways to determine a number of
conditional curtailment hours to
encourage dialog on the issue.
Additionally, we will allow
transmission providers to add a risk
factor to their calculation of annual
curtailment hours to account for
forecasting risks. Further, we note that
our adoption of the conditional bridge
and reassessment products, detailed
above, address modeling difficulties by
limiting the number of years that a
transmission provider must model in
determining both the number of hours
and future system conditions. Moreover,
we clarify that if the customer selects
the annual hourly cap option, the
transmission provider has the flexibility
to conditionally curtail the customer for
any reliability reason during those
hours, including but not limited to, the
system condition(s) identified in the
system impact study. Without this
flexibility the hourly cap option and the
specific system condition option would
be indistinguishable with a cap on the
number of hours that the system
conditions interruption could occur.
1068. We will require annual caps on
the number of hours because calculating
an annual cap entails less risk for the
transmission provider and its existing
firm customers than monthly or
seasonal caps. While we will not require
monthly or seasonal caps, we encourage
transmission providers to offer them if
they can overcome modeling barriers
because monthly or seasonal caps give
more certainty to customers about the
particular aspects of their service.
Though we allow for flexibility in
modeling and determining the number
of conditional curtailment hours for a
particular service request, we believe
that this will have a minimal impact on
conditional firm customers.
Transmission providers will be allowed
to curtail only for reliability purposes
and conditional firm customers during
conditional curtailment hours will be
curtailed only after all point-to-point
non-firm customers have been curtailed.
(iii) Conditional Curtailment Priority
Comments
1069. Some commenters agree with
the Commission’s proposal that
conditional firm service should have
secondary network curtailment priority
during conditional curtailment hours,656
while others disagree. Bonneville
supports the use of the secondary
656 E.g., Bonneville, AWEA Reply, and EPSA
Reply.
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network curtailment priority arguing
that customers will value the service
more with the secondary network
priority, thus increasing the viability of
conditional firm service as an
alternative to transmission upgrades.
EPSA and AWEA argue that conditional
firm service during conditional
curtailment hours should be curtailed
after all non-firm uses. In their reply
comments, TDU Systems oppose EPSA
and AWEA’s position, arguing that
secondary network service should have
at least as high a priority as conditional
firm service. In contrast, EEI argues that
setting the curtailment priority equal to
secondary network service would
adversely impact the reliability of firm
service by reducing real-time redispatch
options and contradict Order No. 888
precedent that provides priority nonfirm service only for network customers
that pay a load ratio share of system
costs.657 If conditional firm service is
implemented, Powerex states that
transmission providers should provide
data and evidence demonstrating that
the rights of existing long-term firm
customers will be protected. EEI takes
issue with the Commission’s proposal to
grant conditional firm customers
priority non-firm service during
conditional curtailment hours because
they would pay for long-term use of the
grid, stating that all long-term point-topoint customers pay for service on a
long-term basis but, unlike network
customers, they do not get priority nonfirm service.
1070. Commenters address
implementation issues related to the
Commission’s right of first refusal,
tagging, tracking, and curtailment
priority proposals, as well as other
implementation issues implicated in the
conditional firm service. Manitoba
Hydro, Bonneville and Seattle support
the Commission’s proposal that
conditional firm service would qualify
for right of first refusal when firm
service becomes available. Several
commenters believe that the
Commission’s proposal with regard to
right of first refusal should be refined to
allow automatic assignment to
conditional firm customers of firm
capacity as it becomes available in the
short term.658 Bonneville asserts that
prior to implementation of the new
service the industry must work with
NAESB to develop a communications
protocol to either employ automatic
assignment or right of first refusal.
1071. Entergy and Exelon state that
the standards for implementing
657 Citing
Order No. 888 at 31,750.
EEI, EPSA, TranServ, Bonneville,
Constellation and Seattle Reply.
658 E.g.,
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transmission loading relief, including
the NERC’s Interchange Distribution
Calculator (IDC), would need
modification to allow for curtailment.
Specifically, Entergy contends that the
Commission should allow time for the
IDC to be modified to specify a different
curtailment priority for the same
transaction depending on the identity of
the constraining element. Imperial states
that it may take over a year to develop
computer software to correctly handle
new curtailment priorities during an
emergency. Bonneville disagrees and
states that conditional firm service does
not present unique issues with respect
to curtailment and that it would be
curtailable during real time like
secondary network service.
1072. EEI states that the conditional
firm service as currently proposed
would conflict with tagging protocols
and NERC criteria because there is
currently no way to tag service as both
firm and non-firm. EEI states that, if
conditional firm service is subject to
curtailment during a specific period, the
tag can identify those periods and
curtailments will be implemented in
conditional periods and non-conditional
periods in accordance with those tags.
However, if conditional service is
curtailable in a certain number of hours,
or when specific conditions occur, the
tag cannot be rewritten in a way that
will provide for curtailment without
personal involvement of balancing
authority operators, which could lead to
increased curtailments of firm
transmission customers.
1073. Xcel states that limiting
curtailments to a specified number of
hours per year could result in
conditional firm service having greater
value than firm, while strictly adhering
to a maximum number of curtailment
hours could potentially conflict with the
reliability standards in section 215 of
the FPA. NRECA argues that conditional
firm service should be subject to pro
rata curtailment with all other firm
users during non-conditional times.
Commission Determination
1074. We adopt a secondary network
curtailment priority to apply for the
hours or specific system conditions
when conditional firm service is
conditional. During non-conditional
periods, conditional firm service is
subject to pro rata curtailment
consistent with curtailment of other
long-term firm service. Thus, secondary
network service and conditional firm
service when it is conditional will share
the same curtailment priority. Also,
there is no conflict with reliability
standards because conditional firm
service will be subject to pro rata
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curtailment with all other firm uses of
the system once conditional curtailment
hours, if that is the option selected, are
exhausted.
1075. The secondary network
curtailment priority is appropriate
because the customer is paying the longterm firm point-to-point rate and thus
should receive the highest non-firm
curtailment priority during the
conditional curtailment hours or during
specified system conditions. Adoption
of this curtailment priority overcomes
what could otherwise be significant
implementation hurdles. It allows for
implementation of the service without
changes to existing NERC TLR practices.
NERC and members of the industry
need not undertake the time-consuming
and expensive process of establishing a
new curtailment priority that is between
firm and non-firm service as some
commenters requested. Use of this
curtailment priority also avoids
attendant decisions relating to the
method of curtailment that should
apply, i.e., pro rata or transactional
curtailment, for a quasi-firm curtailment
priority. It is also consistent with
existing interruption provisions of the
pro forma OATT which provide that
secondary service cannot be interrupted
for economic reasons.659 This is
consistent with our determination that
conditional firm service when it is
conditional is curtailable only to
maintain reliable operation of the
transmission system.
1076. We reject EEI’s argument that
the curtailment priority for conditional
firm service is inconsistent with
Commission precedent regarding
priority non-firm service only for
network customers. EEI’s argument is
inapposite. Long-term firm point-topoint customers taking fully firm service
without the conditional firm option do
not need access to priority non-firm
service as EEI suggests. They have
assurance that their service will not be
interrupted for economic reasons and
will only be curtailed on a comparable
basis with network service. This would
not be the case for conditional firm
customers. We also find that EEI has
failed to explain the connection
between the conditional firm
transmission service and the availability
of reliability redispatch options, i.e.,
generators on its system that can ramp
up or down in response to a
curtailment. We reject Powerex’s
request that transmission providers be
required to show that existing long-term
rights are protected. Each addition of a
new long-term firm transaction impacts
659 See
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the rights of existing firm customers to
some extent.
1077. We disagree with commenters’
suggestion that the NERC IDC must be
changed to accommodate conditional
firm service. We reiterate that we are not
creating a new curtailment priority in
this Final Rule. We also disagree that
new tags that combine a firm and nonfirm priority must be developed in order
to implement the conditional firm
option. The curtailment priority in a tag
can be changed ahead of the operating
hour based on a near-term forecast of
system conditions.660 We are cognizant
that daily and hourly operations to
change the tags for conditional firm
customers likely involve the need for
control room coordination and
development of an appropriate tracking
process. As the Commission described
in the NOPR, new tracking and tagging
business practices for this service must
be developed by each transmission
provider. Thus, we are allowing a
sufficient period for the development of
these business practices, i.e., 180 days
from the date of publication of this Final
Rule in the Federal Register. As
directed above, transmission providers
must coordinate with other transmission
providers in their regions to develop
these tracking and tagging business
practices.
1078. Finally, we address requests to
allow for automatic assignment of shortterm firm point-to-point service to
conditional firm customers. We agree
that transmission providers must take
into account the conditional firm
service in evaluating the availability of
short-term firm service. Because
conditional firm is a long-term firm use
of the system, it should not be
interrupted prior to short-term firm
service. However, short-term firm
service reserved prior to the reservation
of conditional firm service should
maintain priority over conditional firm
service in the periods when conditional
firm service is conditional, i.e., when
specified system conditions exist or
conditional curtailment hours apply.
Because the assignment proposal meets
both of these objectives, we direct
transmission providers to assign shortterm firm service to conditional firm
customers as the service becomes
available. Accordingly, we direct
transmission providers to work with
NAESB to develop the appropriate
communications protocols to implement
660 For example, in the Eastern Interconnection,
tags can be changed up to 35 minutes before the
hour in which a TLR event is scheduled. See NERC
Standard IRO–006–3, Transmission Loading Relief
Procedures—Eastern Interconnection, section 6.2
(Communications and Timing Requirements) at 23–
25 (August 2, 2006).
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this attribute of conditional firm service.
Transmission providers need not
implement this requirement until
NAESB develops appropriate
communications protocols.
(iv) Rollover Rights
Comments
1079. Several commenters support the
Commission’s proposal that conditional
firm service would qualify for rollover
rights.661 Manitoba Hydro, Bonneville
and Seattle state that rollover rights are
appropriate where the transmission
provider does not have an obligation to
plan for service to the conditional firm
customer during the conditional
curtailment hours. Bonneville adds that,
in rolling over conditional firm service,
the transmission service agreement
should allow for no more than the same
number of conditional curtailment
hours than in the original service
agreement and provide for fewer hours
of curtailment if system conditions
provide for more firm service. If
conditional firm service is used as an
interim product until transmission is
built, APPA contends that rollover
rights would be appropriate.
1080. Others argue that rollover rights
for conditional firm service are
inappropriate.662 These commenters do
not support the granting of rollover
rights, nor do they support the
designation of conditional firm service
as long-term service. In order to
accommodate conditional firm rollover
rights, FirstEnergy contends that the
transmission provider would be
required to model a number of off-peak
load flow cases and provide system
reinforcements. Ameren states that the
number of hours that the service will be
available at some future date after the
contract expires will not be known at
the time the initial contract is executed.
EEI adds that estimating conditional
curtailment hours for 10 years of service
is an impossible task. MISO states that
rollover rights would add more
complexity to the AFC/ATC calculation
process and competition queues.
Entergy and EEI state that, while
subsequent firm transmission service
should not be placed ahead of the
conditional firm service, it is
appropriate at the time of a rollover
request, and perhaps more frequently, to
allow the transmission provider to
update the conditional firm service
parameters in order to take into account
661 E.g., AWEA, EPSA, Manitoba Hydro,
Bonneville, TranServ, Seattle, and Utah Municipals
Reply.
662 E.g., EEI, FirstEnergy, Ameren, SPP, and TDU
Systems Reply.
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load growth and changes in load for
prior services.
Commission Determination
1081. The Commission finds that
rollover rights are appropriate for pointto-point service that is provided using
planning redispatch or conditional firm
options and would otherwise be eligible
for rollover rights. The following
discussion addresses only rollover
rights for service that is paired with a
transmission provider’s biennial
reassessment right. While the
Commission agrees with commenters
that subsequent firm transmission
service requests should not be placed
ahead of the conditional firm service,
we note above our concerns with the
modeling requirements and reliability
impacts of an ongoing service that relies
upon unchanging curtailment
conditions or redispatch requirements.
The biennial assessment right,
discussed above, addresses the concern
expressed by EEI that transmission
providers cannot accurately determine
conditional curtailment hours or
estimate redispatch costs for a ten-year
service. The biennial review in
conjunction with rollover rights allows
the transmission provider to update the
parameters of the service in order to
maintain reliable operations and allows
customers to keep their place in the
queue ahead of other customers seeking
conditional firm, planning redispatch
options, or other firm services.
1082. Rollover rights for the
reassessment product can provide
significant value to the conditional firm
customer. A conditional firm customer
opting to roll over will retain priority
claim to the portion of its service that
is firm. For example, if a five-year
conditional firm service initially has a
100-hour annual cap on curtailments,
but the cap is later reassessed at 150
hours, the rollover right would continue
to give the customer first call on all but
the 150 hours as against all other
subsequent requests for firm service.
1083. We note that a customer taking
conditional firm or planning redispatch
options as part of a five-year point-topoint service must declare its intent to
roll the service over in the fourth year
of service, coincident with the second
biennial review. Thus, we task
transmission providers and customers,
in negotiating their service agreement,
with coordinating the timing of the
biennial review with the deadline for
declaring rollover intent. Specifically,
customers deciding whether to renew
their service should have information
on additional conditions on the service
or additional estimated redispatch costs
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1085. Several commenters state that
the Commission should not modify
current OATT requirements for
designating network resources to
include resources delivered using
conditional firm service; otherwise,
reliability would be threatened because
network customers could lean on the
system during conditional periods.664
They oppose allowing a resource taking
conditional firm service to qualify as a
network resource when the associated
resource is imported by a network
customer from an adjacent system. EEI
and Duke agree with the Commission’s
NOPR proposal that conditional firm
service should not be available to
network customers and further assert
that a product that includes a non-firm
portion is inappropriate for a loadfollowing service like network service.
EEI asserts that because the Commission
requires that network resources be
deliverable on a non-curtailable basis,
resources using conditional firm service
cannot be designated as a network
resource until the maximum conditional
curtailment hours have been reached.
EEI and Duke contend that establishing
a defined period of curtailment for
conditional firm service, either seasonal,
monthly, or specific dates, eliminates
issues with respect to the designation of
network resources because a resource
using conditional firm service would be
eligible for designation for the part of
the year when the service was defined
as firm. In its reply comments, Duke
states that it cannot reliably operate its
system if it is required to serve
unplanned load when a network
resource is undeliverable due to
curtailment of conditional firm service.
1086. Other commenters assert that
the Commission should create an
exception to allow designation of
network resources that use conditional
firm service.665 AWEA adds that
resources should not lose their
designation when transactions are
curtailed pursuant to conditional firm
service because this is not the way
similar resources with special
protection systems are treated. Several
commenters state that conditional firm
service should qualify as a network
resource when the associated resource is
imported by a network customer.666 BP
Energy adds that more coordination
between the two systems with respect to
specifying the set of conditions or
specific set of hours is required.
1087. Some commenters state that
conditional firm service should be made
available to network customers because
conditional firm service may trump the
provision or scheduling of secondary
network service and because network
customers should have service that is at
a minimum equivalent with point-topoint service.667 These commenters
suggest that the Commission could
permit network customers to designate
a conditional network resource that
would be a firm resource for the hours
when a comparable conditional firm
point-to-point service is firm. In
supplemental comments, NRECA and
TAPS argue that ‘‘on-system’’ LSEs
should be allowed to designate a
network resource where transmission is
fully firm for all but the limited time
each year, e.g., to 100 hours or less, and
‘‘off-system’’ LSEs should be allowed to
treat a network resource supported by
conditional firm service as a resource on
the host system where it takes network
service. NRECA believes that if the
criteria for both network service
resource designations and for the
proposed conditional firm service are
based on the physical, engineering
characteristics of the transmission
system, the network customer should be
able to designate the resource as
deliverable to load on a non-curtailable
basis, except for the specified
conditions.
1088. In its reply comments,
Bonneville states that since secondary
network service cannot be purchased on
a long-term basis, the Commission
should evaluate whether the design and
663 Such a review would occur in the first year
of a rolled over service if the initial service term
was for five years.
664 E.g., Entergy Supplemental, Southern
Supplemental, MISO Supplemental, Community
Power Alliance Supplemental, and Powerex
Supplemental.
665 E.g., AWEA, EPSA, TAPS, APPA, Utah
Municipals Reply, and Barrick Reply.
666 E.g., Bonneville Supplemental, TDU Systems
Supplemental, PPL Supplemental, and BP Energy
Supplemental.
667 E.g., NRECA, TDU Systems, TAPS, and Utah
Municipals Reply.
at least 30 days prior to the relevant
rollover deadline.
1084. Additionally, because the
biennial review provides the
transmission provider with the ability to
plan for and maintain system reliability,
we will not allow the rollover right to
infringe upon this review. Thus, we
direct that the transmission provider has
a right to review the conditions or
redispatch requirements at the end of
the first year of a service that has been
rolled over, i.e., year six of service, as
consistent with a biennial review of
service.663
(v) Use of Conditional Firm Options in
Designating Network Resources
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implementation challenges of creating a
conditional firm service for network
customers can be overcome. Bonneville
also states that other options such as
seasonal firm and long-term reservation
of secondary network service should be
explored in order to allow network
customers similar access to monthly
ATC.
1089. Nevada Companies state that
network customers have load service
obligations and should always have
unconditional firm service, without
exception. However, Nevada Companies
state that network customers could
benefit from a service similar to
conditional firm service. According to
Nevada Companies, if a network
customer desires to deliver its resources
to a point of receipt that is not available
all seasons of the year, it could procure
firm transmission capacity that is
available on a seasonal basis for the
delivery of a network resource.
1090. Some commenters state that
network customers should be permitted
to designate as network resources third
party power supplies that are supported
by the supplier’s conditional firm
reservation.668 In supplemental
comments, Xcel states that it does not
oppose allowing conditional firm to
qualify as a network resource, but it
should be clear that the service is an
exception to the otherwise ‘‘firm is
firm’’ policy that requires all firm users
to be curtailed pro-rata.
Commission Determination
1091. The Commission will allow
conditional firm point-to-point service
to qualify as firm service that supports
the designation of network resources
imported from other control areas. As
we explain in more detail in section
V.D.6, the Commission has longstanding
limitations on network resources.
Network resources cannot be
interrupted for economic reasons and
third-party transmission arrangements
to deliver the resource to the network
must be non-interruptible.669 EEI is
incorrect that, under our precedent, a
resource must be ‘‘noncurtailable’’ to
qualify as a network resource under the
OATT. All resources are ‘‘curtailable’’—
e.g., if a unit trips off line, the resource
is, by definition, curtailed. Network
resources may also be unavailable due
to other reasons besides an unplanned
unit outage, such as unplanned
transmission outages or environmental
restrictions. It is appropriate to allow
conditional firm service to support the
668 E.g., APPA Supplemental, EPSA and AWEA
Supplemental.
669 Wisconsin Public Power Inc. v. Wisconsin
Public Service Corp., 84 FERC ¶ 61,120 at 61,660
(1998) (WPPI).
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designation of network resources
because the conditional firm option
only affects the transmission of the
resource to the network, not the
interruptibility of the generating
resource itself. Conditional firm service
satisfies the Commission’s requirement
for the delivery of the resource to the
network to be non-interruptible because
such transmission service is curtailable
only for specific reliability reasons, not
economic reasons.
1092. We decline, however, to adopt
the conditional firm option for network
service. Commenters argue that
conditional firm network service should
be made available to prevent
conditional firm point-to-point service
from ‘‘trumping’’ the scheduling of
secondary network service and to
ensure that network service is at a
minimum equivalent to point-to-point
service. Concerns regarding conditional
firm point-to-point service ‘‘trumping’’
secondary network service would not be
resolved by creating conditional firm
network service. The ‘‘as available’’
nature of secondary network service
will still permit all firm uses of the
system, including conditional firm
service, to have a higher reservation
priority than secondary network service.
Creating a conditional firm network
service would not change that
reservation priority.
1093. Others argue that conditional
firm network service should be required
in order to ensure that network service
is equivalent to point-to-point service.
As noted above, however, the two
services are not precisely the same, nor
were they intended to be identical. In
Order No. 888, the Commission
attempted to strike a balance between
competing interests in designing
network and point-to-point transmission
services, each service with its own costs
and benefits. It is therefore appropriate
that we consider the need for
conditional firm service in each context.
While we conclude that implementation
of conditional firm network service is
not necessary to remedy undue
discrimination at this time, we note that
allowing conditional firm point-to-point
service will nonetheless provide
substantial benefits to network
customers by allowing the designation
of network resources delivered to the
network from other control areas using
conditional firm point-to-point service.
Conditional firm point-to-point service
will thereby allow network customers to
access new alternative power sources.
Transmission providers are free to make
a filing under FPA section 205
proposing conditional firm network
service.
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1094. Finally, in light of our
conclusions above that conditional firm
service satisfies the Commission’s
requirements for designating network
resources because the delivery of the
resource to the network is not
interruptible for economic reasons, we
do not need to adopt a seasonal,
monthly or periodic method for
determining the conditions under which
conditional service may be curtailed as
suggested by EEI and others.
b. Proposals for Transparent Redispatch
NOPR Proposal
1095. In the NOPR, the Commission
explained that the major focus of this
rulemaking was to strengthen the pro
forma OATT in order to remedy undue
discrimination rather than create new
market structures. The Commission
stated its intention to retain the use of
an OATT to facilitate the development
of competitive wholesale markets by
reducing barriers to entry through the
control of transmission assets, not
impose any particular market structure
on the industry.
Comments
1096. Several commenters argue that
the Commission should expand the
planning redispatch requirements of the
pro forma OATT to incorporate third
party provision of redispatch and
bidding protocols.670 In reply
comments, Transparent Dispatch
Advocates submitted a proposal that,
among other things, would require
transmission providers to (1) post the
real-time cost estimate of providing
redispatch service from their resources
at congested locations, (2) accept offers
from third parties to provide redispatch
service, and (3) provide real-time
redispatch to resolve transmission
constraints. Transparent Dispatch
Advocates argue that their proposal is
consistent with the scope of the
rulemaking because it would not require
the adoption of LMP markets or other
standardization; rather, it would simply
provide cost visibility and proper cost
assignment of the dispatch decisions
made by transmission providers.
1097. In a notice issued on November
15, 2006, the Commission sought further
comment on the TDA proposal. The
Commission asked, inter alia, about
implementation impediments and
confidentiality issues related to posting
redispatch costs, whether the TDA
proposal was required to remedy undue
discrimination, and whether third party
670 See section V.C.1 of this Final Rule for a
discussion of comments regarding independent
dispatch and spot market development.
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participation in redispatch would
require market mechanisms.
Commission Determination
1098. The Commission addresses
below two distinct parts of the TDA
proposal: (1) Expansion of transmission
provider’s real-time reliability
redispatch obligation as well as
inclusion of third-party resources in
provision of redispatch and (2) posting
of real-time redispatch costs or
prices.671 The Commission has carefully
considered both the TDA proposal and
the comments respecting it. We agree
with many of the public policy goals
articulated by Transparent Dispatch
Advocates, such as increasing the
transparency of information and
increasing the efficient use of existing
infrastructure. However, we also agree
with many of the commenters that
certain aspects of the TDA proposal are
unclear and, depending on its
interpretation, may require the creation
of new services under the pro forma
OATT or new market structures. We are
particularly cognizant of the arguments
of customer groups such as APPA,
NRECA and TAPS that the TDA
proposal may be difficult to implement,
contentious, and may not provide
significant benefits to customers. These
customers also are concerned that it
may detract from other reforms
considered in this proceeding that they
believe provide greater benefits, such as
transmission planning reform.
1099. After considering the views of
all the parties, the Commission has
sought to strike a reasonable balance
between the positions of the
commenters. On the one hand, we adopt
certain reforms that will provide
additional information regarding
redispatch costs in a manner that
benefits consumers. On the other hand,
we will not adopt the portions of the
TDA proposal that would require the
creation of new services under the pro
forma OATT or new market structures.
We do not believe that such
fundamental changes are necessary or
appropriate at this time, nor do we have
an adequate record upon which to adopt
them.
1100. Specifically, the Commission
declines to adopt the TDA proposal to
expand transmission providers’ realtime reliability redispatch obligations
and incorporate third party bids into
redispatch. As discussed in detail
above, transmission providers will
continue to have an obligation to
671 Transparent Dispatch Advocates’ proposal for
mandatory coordination agreements between
transmission providers for provision of redispatch
service is addressed in section V.C.1 of this Final
Rule.
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perform reliability redispatch for
network customers and provide the
planning redispatch described above for
point-to-point customers. Transmission
providers will not be required, as
Transparent Dispatch Advocates
request, to incorporate third party
resources when providing reliability
redispatch or evaluating planning
redispatch options for point-to-point or
network transmission service. We will,
however, institute a posting requirement
so that the actual costs of redispatch
under existing and future redispatch
agreements is made transparent to
potential customers. While we will not
require posting of a real-time estimate of
redispatch prices as proposed by
Transparent Dispatch Advocates, the
Commission concludes that the posting
requirement required herein will
provide important information
regarding the costs of redispatch
without revealing confidential
information that might harm existing
markets.
(1) Expansion of Reliability Redispatch
Obligation and Inclusion of Third Party
Resources
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Comments
1101. In reply comments filed
September 20, 2006, Transparent
Dispatch Advocates argue that the
Commission must bring transparency to
the dispatch function to make
redispatch effective and fair and to
thereby remedy the potential for
discriminatory provision of
transmission service. Transparent
Dispatch Advocates assert that the
Commission should require each
transmission provider to publish a
‘‘dynamic real-time value of what it
would charge to provide redispatch
service at specified congestion locations
within the transmission provider’s
system and at specified flowgates at the
border of the transmission provider’s
system.’’ 672 Transparent Dispatch
Advocates contend that the publication
of this data would: Allow customers to
assess available real-time redispatch
options; allow customers to access
redispatch at actual costs; allow
customers to predict with reasonable
certainty the costs of redispatch; allow
all resource owners to voluntarily offer
redispatch solutions and be properly
compensated for their efforts; and over
time, support long-term transmission
service.
1102. In reply comments, Transparent
Dispatch Advocates further request
adoption of rules that would either
require the transmission provider to
672 Transparent
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account for independent, third party
resources in its control area in
establishing redispatch costs, or allow
independent resources to post real-time,
cost-based price and quantity bids for
redispatch plus the resource’s impact on
the constraint on the transmission
provider’s OASIS. Transparent Dispatch
Advocates state that the published
redispatch values would be cost-based
in non-market environments.
1103. On November 3, 2006, a
summary of, and frequently asked
questions regarding, the TDA proposal
(TDA Summary) was attached to
comments filed by San Diego G&E in
response to the October 12 Technical
Conference and in support of the TDA
proposal. In the TDA Summary,
Transparent Dispatch Advocates assert
that the Commission need only revise
the existing redispatch provisions of the
pro forma OATT to require posting by
the transmission providers of the nature
of congestion at pre-designated
flowgates and data concerning the
response required to relieve congestion.
Additionally, the TDA Summary states
that the transmission provider would
have no obligation to provide for realtime redispatch from its own or
affiliated generation; rather, all
generators wishing to provide
redispatch could volunteer to submit
bids. Transparent Dispatch Advocates
state that these bids could be either
market or cost based depending on
whether the bidder has market-based
rates within the control area. The
transmission provider would be
obligated to evaluate the bids, publish
the price for redispatch, and call on
generators to provide the requested
redispatch in real time. Transparent
Dispatch Advocates suggest that
transmission providers calculate the
price for redispatch by taking the
difference between bids received by
those generators that the transmission
provider would call upon to increase
output (i.e., to redispatch) and the costs
the transmission provider otherwise
would have paid the generator whose
output is lowered to relieve the
constraint. Transparent Dispatch
Advocates contend that their proposal
differs from LMP markets because,
while LMP sets system-wide clearing
prices, their transparent redispatch
proposal would apply only at selected
flowgates and only with respect to those
transacting at those flowgates.
1104. On December 15, 2006, in
supplemental comments filed in
response to the Commission’s November
15 Notice asking for comment on the
TDA proposal, Transparent Dispatch
Advocates sought to clarify their
proposal. Transparent Dispatch
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Advocates propose that the Commission
impose upon transmission providers an
obligation to do the following: Provide
reliability redispatch to point-to-point
customers in real-time for comparable
treatment to that currently provided to
network customers and native load;
consider their own resources, network
resources, and offers from non-network
resources in providing least cost
redispatch in real-time; and, publish
real-time information about the cost of
redispatch (including the prices
submitted by non-network resources) on
its OASIS site on a frequent and timely
basis. In their supplemental comments,
Transparent Dispatch Advocates
propose a different method for
calculating redispatch prices using the
difference between the cost of the
generation raised and the pre-redispatch
transmission provider’s system-wide
marginal cost (e.g., system lambda).
Transparent Dispatch Advocates further
propose that point-to-point redispatch
customers taking this service would not
be subject to curtailment along with
other firm customers in accordance with
the current OATT curtailment rules.
Transparent Dispatch Advocates argue
that their modified proposal would
facilitate comparable access to
redispatch service and ensure that the
existing redispatch provisions of the
OATT can be made effective.
1105. Several parties offer comments
in support of the TDA redispatch
proposal.673 Constellation encourages
the Commission to fully consider the
TDA proposal in the appropriate
context, whether in this docket or in a
separate proceeding. California
Commission states that a movement of
OATT policy in the direction implied
by the TDA proposal is necessary to
improve efficiency of generation and
transmission investment. BP Energy
believes that a redispatch mechanism is
necessary to minimize aggregate
consumer costs and make redispatch
equally available to all participants.
PPM supports the TDA proposal noting
that it would provide sufficient cost
certainty for both the transmission
provider and the customer and make
more efficient use of the existing grid
without impacting reliability. Although
it opposed the proposal initially, MISO
states that it now cautiously supports
the TDA redispatch proposal, provided
that RTOs do not bear an inappropriate
share of costs to modify information
technology systems.
673 E.g., EPSA and AWEA Supplemental,
Constellation Supplemental, California Commission
Supplemental, PPL Supplemental, BP Energy
Supplemental, PPM, and San Diego G&E.
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1106. Many commenters oppose the
TDA proposal stating that the record in
this proceeding does not warrant
implementing such a complex and
uncertain proposal which imposes
significant risks, costs and burdens on
transmission providers and their native
load customers.674 Public Power
Council, Southern, and NRECA do not
believe that the Commission should
adopt the TDA proposal without an
analysis of costs and benefits and note
that no party has provided any such
analysis. OG&E and Public Power
Council state that the costs of
congestion likely vary greatly by region
and argue that Transparent Dispatch
Advocates have provided no evidence
that their industry-wide solution solves
potential regional redispatch problems.
1107. Several state commissions
oppose adoption of the TDA proposal or
urge the Commission to impose
significant conditions on the proposal to
protect retail customers.675 SEARUC,
Alabama Commission, Florida
Commission, Georgia Commission,
North Carolina Commission and South
Carolina Regulatory Staff express
concern that the TDA proposal would
make competitively sensitive
information available to the public on
an inconsistent basis, compel the
provision of additional services that risk
increasing retail costs, harm reliable
service to retail ratepayers that state
commissions are obligated by state laws
to protect, impose administrative
difficulties and excessive
implementation costs, and compel states
or regions to change current practices or
market structures in contradiction of
EPAct 2005. SEARUC asks the
Commission to make clear that
implementation of a proposal targeted at
enhancing transparency will not result
in a federally imposed change in
economic dispatch practices or lessen
the amount of firm capacity available for
service to native load customers.
SEARUC also expresses concern
regarding the imposition of incremental
costs upon retail ratepayers without
prior state approval or the
implementation of any type of process
674 E.g., LPPC Supplemental, Community Power
Alliance Supplemental, Public Power Council
Supplemental, Pacific Coast Parties Supplemental,
EEI Supplemental, Duke Supplemental, Southern
Supplemental, Southwest Utilities Supplemental,
South Carolina E&G Supplemental, Ameren
Supplemental, Alabama Commission
Supplemental, Florida Commission Supplemental,
Georgia Commission Supplemental, North Carolina
Commission Supplemental, South Carolina
Regulatory Staff, and SEARUC Supplemental.
675 E.g., Alabama Commission Supplemental,
Florida Commission Supplemental, Georgia
Commission Supplemental, North Carolina
Commission Supplemental, South Carolina
Regulatory Staff, and SEARUC Supplemental.
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or organization that has not been
approved by state regulators as cost
effective for retail customers. SEARUC
opposes the mandatory use of LMP or
LMP-like pricing, congestion
management approach or organized
wholesale market structure without
prior state endorsement; and the
mandatory posting of competitively
sensitive, generation plant-specific costs
or price information.
1108. Georgia Commission states that
radical restructuring is not necessary to
achieve the goals stated by the
Commission in the NOPR. Alabama
Commission, Georgia Commission and
South Carolina Regulatory Staff state
that analyses associated with potential
implementation of new market
structures in the Southeast have
demonstrated that the implementation
costs associated with such structures
vastly outweigh the benefits. North
Carolina Commission argues that the
TDA proposal fails to comply with the
Commission’s directive in the NOI. In
its view, the Commission intended to
focus in this proceeding on specific
problems that continue to exist and
targeted remedies.
1109. North Carolina Commission
states that the Transparent Dispatch
Advocates’ reply comments incorrectly
equate the use of redispatch for
economic purposes pursuant to 13.5 of
the pro forma OATT with its use for
reliability purposes. North Carolina
Commission maintains that these
services are not comparable, and thus
the use of redispatch for reliability
purposes does not justify requiring a
transmission provider to provide it for
economic purposes. North Carolina
Commission asserts that
implementation of the TDA proposal
would result in substantial benefits
accruing to PJM without commensurate
benefits to non-RTO areas. North
Carolina Commission, Southwest
Utilities and Southern argue that the
costs of implementing the proposal are
not justified by any potential efficiency
benefits and thus there is a compelling
reason to reject the TDA proposal.
1110. Several parties argue that the
TDA proposal represents a move toward
Standard Market Design (SMD).676
Alabama Commission, Georgia
Commission and North Carolina
Commission submit that the TDA
proposal shares characteristics with the
centralized dispatch and LMP proposals
676 Commenters reference a proposal in a
proceeding terminated by the Commission. See
Remedying Undue Discrimination through Open
Access Transmission Service and Standard
Electricity Market Design, 67 FR 55454 (Aug. 29,
2002), FERC Stats. & Regs. ¶ 32,563 (2003),
terminated by, 112 FERC ¶ 61, 073 (2005).
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advanced in the SMD proceeding and
thus conflict with state commission
jurisdiction in much the same manner
as the SMD proposal. Georgia
Commission and others assert that the
only difference between the SMD
proposal and TDA proposal is that the
TDA proposal would require
transmission providers, but not third
party merchants, to make their costs
transparent.677 NRECA believes that a
real-time pricing scheme based on some
value other than actual costs constitutes
the creation of a new product and an
organized, bid-based market in regions
that have not adopted such market
structures. NRECA contends that it
would be politically unacceptable to
reform the OATT in a manner that
necessitates the formation of regional
bid-based markets in non-RTO areas.
1111. In contrast, California
Commission supports the TDA proposal
to the effect that transmission providers
should be required to post redispatch
cost information and to provide realtime redispatch. In supplemental
comments, California Commission
asserts that this effort is needed to
prevent undue discrimination, for
improved efficiency of generation and
transmission investment and to improve
the efficiency, transparency and
openness of redispatch, and
transmission access generally.
1112. Some commenters argue that
the TDA proposal is necessary to
remedy undue discrimination.678 Others
disagree.679 Transparent Dispatch
Advocates contend that making realtime economic dispatch available to
‘‘non-network transmission customers’’
is necessary to remedy undue
discrimination against those customers
as compared with network customers. In
their supplemental comments, EPSA
and AWEA state that the TDA proposal
is necessary to remedy the same undue
discrimination targeted by the NOPR
proposal pertaining to planning
redispatch service. PPL suggests that the
TDA proposal may permit transmission
customers to benefit from redispatch,
which transmission owners in non-RTO
677 E.g., Community Power Alliance
Supplemental, and Entergy Supplemental.
678 EPSA and AWEA Supplemental, BP Energy
Supplemental, California Commission
Supplemental.
679 E.g., LPPC Supplemental, Community Power
Alliance Supplemental, Public Power Council
Supplemental, Pacific Coast Parties Supplemental,
EEI Supplemental, Duke Supplemental, South
Carolina E&G Supplemental, Ameren
Supplemental, North Carolina Commission
Supplemental, South Carolina Regulatory Staff
Supplemental, and North Carolina Commission
Supplemental.
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areas now employ to benefit themselves
or their native load customers.
1113. A number of commenters assert
that neither the record nor Transparent
Dispatch Advocates present evidence of
discriminatory treatment of
transmission customers with regard to
transparent redispatch.680 South
Carolina E&G asserts that
implementation of the TDA proposal
should not be unjustifiably forced onto
individual transmission providers given
that there is no demonstration that there
is a problem. MidAmerican and
Progress Energy and others argue that
unsupported assertions of undue
discrimination are insufficient to
support the TDA proposal. These
commenters argue that pursuant to the
recent National Fuel decision, the
courts would likely require the
Commission to overcome substantial
hurdles in order to adopt the TDA
proposal based on theoretical assertions
of undue discrimination.681 These
commenters contend that the National
Fuel case would likely require the
Commission to demonstrate how
potential undue discrimination justifies
a costly redispatch proposal, why
section 206 rights are insufficient to
ensure redispatch is comparably
provided, and why the comparability
findings of Order No. 888 are no longer
sufficient.
1114. In response to assertions that
utilities routinely redispatch to meet
electric load, LPPC argues that there is
nothing discriminatory about a
vertically integrated utility’s use of its
own nonjurisdictional generation to
support bundled sales service. LPPC
states that the use of generation first to
serve native load has been the
fundamental operating principal for
jurisdictional and nonjurisdictional
utilities for decades, and certainly under
Order No. 888. LPPC concludes that this
is not a problem calling for Commission
attention. In response to assertions that
TLRs are discriminatory, Duke notes
that neither the Transparent Dispatch
Advocates nor any other commenter has
provided an analysis of the scope,
location and magnitude of the TLR
problem.
680 E.g., LPPC Supplemental, Community Power
Alliance Supplemental, Public Power Council
Supplemental, Pacific Coast Parties Supplemental,
EEI Supplemental, Duke Supplemental,
MidAmerican and Progress Energy Supplemental,
South Carolina E&G Supplemental, Ameren
Supplemental, North Carolina Commission
Supplemental, North Carolina Commission Staff
Supplemental, and North Carolina Commission
Supplemental.
681 E.g., Entergy Supplemental, LPPC
Supplemental, Public Power Council Supplemental,
and OG&E Supplemental.
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1115. Many commenters contend that
the TDA proposal is ambiguous,
insufficiently developed or marked by
inconsistencies.682 Pacific Coast Parties
argue that the TDA proposal is too
sweeping and contains too many
uncertainties to allow for meaningful
comment. Southwest Utilities believe
that it would be premature for the
Commission to adopt the TDA proposal
without further development, comment,
discussion and input from affected
electric industry stakeholders. PPL and
Xcel believes that the Commission
needs to better define the proposed new
service and allow comment on the
service before detailed tariff language is
developed to implement this proposed
new service. Public Power Council
contends that, although the proposal
appears to seek only the posting of
information, in reality, Transparent
Dispatch Advocates ask that the
Commission require reciprocal
redispatch coordination. Public Power
Council also argues that the TDA
proposal is silent or ambiguous
concerning critical issues associated
with implementation; the proposal fails
to explain the ‘‘cost’’ at which
transmission providers would offer
redispatch or the price, terms, and
conditions of such a transaction.
1116. Several parties refer to seeming
discrepancies between Transparent
Dispatch Advocates’ explanations of the
proposal and question whether the TDA
proposal entails cost-based or marketbased bidding.683 APPA notes that
Transparent Dispatch Advocates state in
reply comments that effective
redispatch service must reflect actual
costs. APPA adds that the TDA
Summary, in contrast, provides that any
generator with market-based rate
authority in the transmission provider’s
control area could charge a marketbased price for generation offered for
redispatch service. LPPC, TDU Systems,
TAPS, APPA and NRECA express
concern about allowing redispatch
providers to bid under market-based
rate authority. These commenters argue
that reliance on existing market-based
rate authority to support redispatch
offers no protection against the exercise
of market power, given the high
concentration of transmission providerowned generation within its control
682 E.g., Pacific Coast Parties Supplemental,
Southwest Utilities Supplemental, Entergy
Supplemental, EEI Supplemental, PPL
Supplemental, Public Power Council Supplemental,
Florida Commission Supplemental, SEARUC
Supplemental, Progress Energy and MidAmerican
Supplemental, APPA Supplemental, NRECA
Supplemental, and TAPS Supplemental.
683 E.g., Progress Energy and MidAmerican
Supplemental, APPA Supplemental, NRECA
Supplemental, and TAPS Supplemental.
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area. If the Commission adopts the TDA
proposal, APPA asserts that the
Commission should limit all sellers of
generation used for redispatch service to
cost-based bids and require all parties to
provide cost information.
1117. In supplemental comments, EEI
and Public Power Council assert that the
Commission in seeking comment on the
TDA proposal has not proposed a rule
with sufficient clarity to allow
meaningful comment and, therefore, it
would be inappropriate to adopt the
TDA proposal based on this
proceeding’s record. Pacific Coast
Parties add that the Commission cannot
adopt the TDA proposal based on the
sparse record in this proceeding.
MidAmerican and Progress Energy
contend that the Commission’s notice
here does not satisfy Administrative
Procedure Act requirements for public
notice and comments on the TDA
proposal. In their view, the Commission
must initiate a separate rulemaking
proceeding to evaluate the TDA
proposal.
1118. Progress Energy and
MidAmerican assert that, under the
current pro forma OATT, redispatch is
based on a ‘‘careful’’ evaluation of the
reliability and cost impacts of using
redispatch on a long-term basis and thus
the transmission provider is able to
serve transmission customers and
wholesale load-serving obligations at
least cost. In their view, the
transmission provider’s retail and
wholesale customers would absorb the
costs to serve transmission customers
that obtain the forced real-time
redispatch under the TDA proposal.
1119. Community Power Alliance,
North Carolina Commission, Progress
Energy and MidAmerican contend that
native load customers would be harmed
by a requirement that transmission
providers sell their excess generation to
redispatch customers. They state that
such a requirement would prevent or
reduce the sale of generation in
competitive markets and that these
market sales would otherwise reduce
costs to native load customers.
Moreover, where the transmission
provider is required to redispatch its
own generation, Progress Energy and
MidAmerican argue that Transparent
Dispatch Advocates’ proposed
redispatch would either use more
expensive units or cause the
transmission providers to lose the
opportunity to make higher valued
sales, which also increases costs for
native load customers.
1120. In supplemental comments,
E.ON, Progress Energy and
MidAmerican assert that some
generators face limits with regard to the
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amount of time that they are allowed to
operate due to air emissions caps and
maintenance schedules. They contend
that the TDA proposal could cause
allowable run time to be ‘‘used up’’
prior to the time that the generator has
fulfilled its planned native load
obligation, thus requiring that the
transmission provider resort to
alternative, likely more expensive,
power supplies for these obligations.
1121. Several parties assert that
Transparent Dispatch Advocates’
proposal to substitute redispatch for
transmission upgrades will depress
transmission investment.684 LPPC
argues that Transparent Dispatch
Advocates’ proposal conflicts with the
Commission’s policy of promoting
transmission infrastructure
development. NRECA states that, to the
extent that redispatch is required to
fulfill long-term point-to-point service
on a particular transmission provider’s
system, such providers have failed to
meet their obligations under the existing
OATT to plan and expand the system
for those transmission customers’ longterm needs. NRECA envisions
redispatch customers potentially
requesting ‘‘ever more convoluted’’
dispatch rules in order to avoid
transmission upgrades. NRECA prefers
better enforcement of section 15.4 of the
OATT in conjunction with a more open
and inclusive planning process. TAPS
argues that transmission providers will
profit from market-based prices for
redispatch and will be discouraged from
transmission expansion. TAPS contends
that PJM has conceded that LMP signals
have proven insufficient to create a
robust grid. In TAPS view, this counters
Transparent Dispatch Advocates’ claims
that their proposal will reveal the value
of transmission upgrades and encourage
investment.
1122. Several commenters submit that
the TDA proposal raises Standards of
Conduct issues.685 They argue that
requiring the TDA proposal would
complicate if not undermine the
functional separation and information
sharing policies of the Standards of
Conduct because the transmission
function would be performing
merchant, or at least merchant-related,
functions. According to Community
Power Alliance, the requirement that
transmission providers allow merchant
generators to offer to sell generation to
684 E.g., LPPC Supplemental, TAPS
Supplemental, NRECA Supplemental, Southern
Supplemental, South Carolina E&G Supplemental,
and E.ON Supplemental.
685 E.g., Nevada Companies Supplemental,
Community Power Alliance Supplemental,
Southwest Utilities Supplemental, and Southern
Supplemental.
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alleviate constraints in order that other
customers’ transactions could flow
would violate Standards of Conduct.
1123. TAPS argues that accurately
forecasting the price of long-term firm
service may be difficult and thus the
TDA proposal would not provide
adequate levels of certainty to facilitate
long-term service.
1124. Mark Lively asserts that the
TDA proposal fails to address other
types of redispatch, including loop flow,
reactive power, Inadvertent Interchange
and intra-hour interchange, and as such
will result in suboptimal operation of
the network.
1125. OG&E questions whether the
TDA proposal would apply to RTOs but
if so, OG&E argues that the proposal
should be rejected. OG&E contends that
the Commission explained in Order No.
2000 that congestion management is a
regional function and that the TDA
proposal should not apply to a
transmission provider located within an
RTO.
1126. In supplemental comments,
Transparent Dispatch Advocates
contend that the transparent dispatch
proposal would not involve the
establishment of organized markets of
any sort; rather, it simply would require
the posting of redispatch costs.
Transparent Dispatch Advocates state
that the proposal only requires the
consideration by the transmission
provider of additional price data from
non-network resources and minimal
adjustments in transmission provider’s
reporting systems.
1127. Several parties disagree with
Transparent Dispatch Advocates and
argue that the proposal would require
the establishment and operation of
markets by transmission providers.686
APPA and TDU Systems assert that
under the TDA proposal transmission
providers would select bids, from
among a variety of affiliated and
unaffiliated resources, that most
effectively relieve constraints.
Community Power Alliance, Georgia
Commission, Southern and Entergy
assert that the TDA proposal would
result in the establishment of formal
LMP markets in non-RTO/ISO areas, or
at least start down the ‘‘slippery slope’’
to LMP markets. Community Power
Alliance and Entergy contend that
adoption of the TDA proposal is in
conflict with the purpose of the
rulemaking as stated in the NOPR and
686 E.g., APPA Supplemental, LPPC
Supplemental, TDU Systems Supplemental, NRECA
Supplemental, Progress Energy and MidAmerican
Supplemental, Southern Supplemental, Duke
Supplemental, OG&E Supplemental, Georgia
Commission Supplemental, and North Carolina
Commission Supplemental.
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Congress’ focus on protecting native
load and ensuring reliability in EPAct
2005.
1128. APPA argues that the
implementation of the TDA proposal
would require the following:
designation and posting by the
transmission provider of chosen
flowgates; posting by the transmission
provider of the desired characteristics of
generation or demand-side responses
that could alleviate such constraints;
posting by the transmission provider of
historical redispatch costs; resolution of
whether public utility transmission
providers can be required to provide
generation resources for redispatch;
resolution of whether transmission
providers would be discriminated
against if they were not permitted to
charge market-based rates;
administration by the transmission
provider of short-term (daily or hourly)
market for redispatch, notwithstanding
a conflict of interest between the
transmission provider’s market-making
and market-participant roles and
possibly third-party monitoring of
market administration.
1129. APPA, Xcel, North Carolina
Commission, and NRECA raise concerns
over the costs of establishing and
administering redispatch markets and
systems, including the costs of
hardware, software, communication
systems, billing and reporting systems.
North Carolina Commission submits
that the costs of implementing the TDA
proposal would be substantial because
there are no current practices or rules on
which to model structures for the TDA
proposal. Other commenters similarly
assert that the TDA proposal would
impose significant administrative
burdens and expenses on transmission
providers, especially if an independent
entity were required for
implementation, and that most of these
costs would be shifted to native load
customers.687 Xcel argues that
redispatch cannot be cost-effectively
managed unless done within the context
of a regional Day 2 energy market.
1130. NRECA asserts that
transmission providers would need an
enormous amount of data, including
resource status, marginal generation
costs, start up costs, ramp rates, and
environmental costs of operation, to
redispatch resources. NRECA asserts
that the allocation of redispatch costs
for multiple customers taking redispatch
may be difficult.
687 E.g., Community Power Alliance
Supplemental, Southwest Utilities Supplemental,
Florida Commission Supplemental, Ameren
Supplemental, and Entergy Supplemental.
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1131. Xcel, APPA, and TDU Systems
assert that the TDA proposal would not
address concerns about subjective
redispatch decisions by transmission
providers. TDU Systems argue that the
proposal would allow for the functional
equivalent of an RTO market, without a
market administrator that satisfies the
independence criteria of Order No. 2000
or Order No. 888. APPA asserts that
posting of information concerning the
nature of congestion at designated
flowgates would be followed by
differences of opinion as to how the
dispatch entity is exercising its
judgment in calculating the costs and in
redispatching resources.
1132. Southwest Utilities and
Southern assert that the proposal raises
significant questions regarding
commercial, operational, economic, and
compliance issues that remain
unanswered. For example, Southwest
Utilities argues that it would appear that
under the TDA proposal a transmission
provider accepting a third party bid
would be required to assume the
commercial obligation, including credit
risk associated with the bid and the
posting of collateral, and would execute
the contract with the third party bidder
under currently unspecified terms and
conditions. Southwest Utilities and
Southern further argue that the proposal
fails to resolve how operational and
economic liability to the redispatch
customer would be impacted in the
event of non-performance by a third
party supplier. Southwest Utilities also
asserts that it is unclear whether the
TDA proposal could function within the
rated path/contract path model of much
of the Western Interconnection.
1133. Many parties argue that
implementation of the TDA proposal
would raise jurisdictional issues.688
Community Power Alliance, South
Carolina E&G, Progress Energy,
MidAmerican and Southern assert that
the TDA proposal conflicts with state
and federal laws in that it forces
transmission providers to use generation
(that was built, dedicated and
dispatched to serve retail and wholesale
customers at least cost) to serve other
wholesale suppliers and customers.
Community Power Alliance argues that
states, not the Commission, have
authority to regulate how utilities
dispatch generation and procure
resources. Further, Community Power
Alliance asserts that requiring utilities
to establish platforms for third-party
generators’ offers would convert the
688 E.g., APPA Supplemental, LPPC
Supplemental, Community Power Alliance
Supplemental, South Carolina E&G Supplemental,
Progress Energy and MidAmerican Supplemental,
and Southern Supplemental.
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transmission function into a generation
procurement function, violating the
scope of the Commission’s jurisdiction.
Southern, LPPC and North Carolina
Commission add that the TDA proposal
would be in violation of section 201 of
the FPA that expressly limits the
Commission’s jurisdiction to matters
which are not subject to regulation by
the States. Southern further asserts that
this is made clearer by the exclusion in
section 201 of ‘‘facilities used for the
generation of electric energy’’ from the
Commission’s jurisdiction. Southern
contends that mandated cost-based sales
would also constitute an unlawful
taking of private property under the
Fifth Amendment of the Constitution.
1134. LPPC states that Transparent
Dispatch Advocates seek to reason
around section 201 of the FPA in
arguing that redispatch ‘‘does not
involve the sale of electricity for re-sale
or consumption; it involves the
provision of a service to support
transmission service.’’ 689 LPPC
counters that, in redispatch, generation
is used instead of transmission service
rather than in support of transmission
service. North Carolina Commission,
LPPC and APPA argue that the courts
have previously rejected Commission
attempts to extend regulation to matters
specifically excluded, statutorily, from
regulation on the grounds that they are
the functional equivalent of a
jurisdictional service.690 LPPC also
asserts that section 217 of the FPA
specifies that utilities have a right to use
their transmission facilities on a priority
basis in order to meet their core service
obligations.
1135. North Carolina Commission
asserts that in Order No. 888 the
Commission interpreted its authority
under sections 205 and 206 of the FPA
to include the effect the Rule may have
over generation facilities because
preventing undue discrimination is one
of the matters specifically provided for
in Part II. North Carolina Commission
argues that California Independent
System Operator v. FERC,691 however,
establishes limits on how broadly
sections 205 and 206 can be interpreted.
North Carolina Commission contends
that sections 205 and 206 historically
have been interpreted to apply to the
rates for wholesale sales and purchases,
rather than to the underlying generating
facilities. As a result, North Carolina
Commission argues that the adoption of
689 Transparent
Dispatch Advocates Reply at 17.
Northwest Pipeline Corp. v. FERC, 905
F.2d 1403, 1410–11 (10th Cir. 1990); Detroit Edison
Co. v. FERC, 334 F.3d 48, 54–55 (D.C. Cir. 2003).
691 372 F.3d 395 (D.C. Cir. 2004).
690 Citing
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12411
the TDA proposal could not be justified
under these provisions of the FPA.
Commission Determination
1136. The Commission agrees with
the Transparent Dispatch Advocates
proponents that greater transparency of
reliability redispatch information can
provide benefits to consumers, as well
as increase efficient use of the existing
transmission grid. We are therefore
adopting certain reforms, as explained
in the section below, that will increase
the availability and transparency of
redispatch costs. However, we are
adopting these reforms in the context of
the existing obligation to provide
network and point-to-point transmission
service under the pro forma OATT. We
will not adopt the portion of TDA
proposal that would require the creation
of new services or any broader market
reforms.
1137. The TDA proposal has
generated controversy for several
reasons, including the lack of clarity in
the proposal, certain inconsistencies
that appear in Transparent Dispatch
Advocates’ various submissions, and
concerns that Transparent Dispatch
Advocates’ true intent is to restructure
bilateral markets. We believe that many
of the concerns regarding the TDA
proposal are overstated, but we do agree
that it lacks clarity and consistency in
many important respects. For example,
it is not clear whether the proposed
service would be available to all
customers, any point-to-point customer
including those taking non-firm service,
or solely to long-term firm point-topoint customers.692 Additionally, while
Transparent Dispatch Advocates
contend that ‘‘the one step’’ required of
the Commission is to implement a
redispatch cost posting requirement,693
the TDA proposal also would require
the Commission to expand the current
redispatch obligations under the pro
forma OATT and adopt complex
settlement mechanisms to account for
third party redispatch. The different
TDA proposals also vary as compared
with each other. For instance, the TDA
Summary states that transmission
providers would not be obligated to
provide their resources for real-time
redispatch, but the Transparent
692 Compare Transparent Dispatch Advocates
Supplemental at 2 n.4 (stating that the proposed
service would supplement the existing OATT
requirement to provide redispatch to long-term firm
point-to-point customers) and Transparent Dispatch
Advocates Supplemental at 5 (discussing the
proposal as a remedy for undue discrimination
against firm point-to-point customers) with
Transparent Dispatch Advocates Supplemental at
14–15 (demonstrating the redispatch pricing
mechanism for a non-firm transaction).
693 Transparent Dispatch Advocates Reply at 18.
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Dispatch Advocates Supplemental
Comments make clear that the
transmission provider would be
obligated to use its own (or affiliated)
resources to provide this redispatch.
1138. We first address the contention
of Transparent Dispatch Advocates that
the real-time reliability redispatch
obligation of transmission providers
must be extended to ‘‘non-network
transmission customers’’ to remedy
undue discrimination. We disagree. In
order to remedy undue discrimination,
we have made changes to the pro forma
OATT to implement a new conditional
firm option for point-to-point service
and we make changes to the existing
planning redispatch obligation.
However, Transparent Dispatch
Advocates have failed to show that the
unavailability of reliability redispatch
for point-to-point transmission
customers amounts to undue
discrimination. Order No. 888 provided
for reliability redispatch for network
customers but not for firm point-topoint customers.694 There is a good
reason for this distinction. The pro
forma OATT requires network
customers to make their generation
resources available to the transmission
provider to provide reliability
redispatch to maintain the reliability of
service to both native load and network
customers. There is no corresponding
obligation on point-to-point customers
to make their generation resources
available to provide reliability
redispatch. Therefore, the two services
are not comparable in this respect,
which is why reliability redispatch
service was not required for point-topoint customers. However, if a
reliability problem does arise, any
curtailment of firm point-to-point
transmission service must be on a
nondiscriminatory and pro rata basis
with the treatment of network service
and native load customers.695 The
694 See pro forma OATT section 33.2; see also
Midwest Independent Transmission System
Operator, Inc., 84 FERC ¶ 61,231 at 62,168 (1998)
(‘‘redispatch will be utilized to avoid the
curtailment of firm point-to-point services, a
requirement that is not imposed under the pro
forma tariff.’’); Mid-Continent Area Power Pool, 87
FERC ¶ 61,190 at 61,726–27 (1999) (finding no
obligation to offer reliability redispatch to point-topoint customers and no obligation for point-to-point
customers to participate in reliability redispatch).
695 See, e.g., North American Electric Reliability
Council, 88 FERC ¶ 61,046 at 61,123–24 (1999)
(explaining that pro rata curtailment is consistent
with comparability even if network/native load
reduction is accomplished by redispatch and pointto-point customer reduction is not); Northern States
Power Co., 83 FERC ¶ 61,338 at 62,369 (1998) (the
existence of redispatch options is not a criterion
under the pro forma OATT for disproportionate
curtailments), reh’g, clarification and stay denied,
84 FERC ¶ 61,128 (1998), remanded on other
grounds sub nom. Northern States Power Co. v.
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Commission has found that this
treatment meets the comparability
requirements enunciated in Order No.
888.696
1139. Next, we also decline to adopt
a requirement for transmission
providers to incorporate offers to
redispatch from third parties into their
reliability redispatch or planning
redispatch. Mandatory inclusion of
third party offers is not necessary to
remedy undue discrimination. The pro
forma OATT obligates transmission
providers to use their resources to
provide, where available consistent with
reliability, redispatch service because
they do so when serving their native
load customers. Third party generators
do not have this obligation, nor do the
Transparent Dispatch Advocates
propose to create such an obligation.
Rather, under the TDA proposal,
transmission providers would remain
obligated to provide redispatch service,
but third party generators would have
only the option of doing so. Transparent
Dispatch Advocates are therefore not
proposing comparable treatment and we
decline to adopt the proposal. This
notwithstanding, we believe that
redispatch offers by third party
generators can increase system
reliability and reduce costs to customers
by increasing the planning redispatch
options available to transmission
providers. We therefore are adopting, as
explained above, a requirement that
transmission providers modify their
OASIS to allow for the posting of third
party offers to supply planning
redispatch. This OASIS posting
requirement does not obligate
transmission providers to incorporate
bids from third parties into their
redispatch; rather, posting of third party
offers to provide redispatch may be used
by transmission customers to secure
planning redispatch provided the
appropriate agreements are reached
between the customer, third party
redispatch provider, transmission
provider and reliability coordinator.
1140. We disagree with Transparent
Dispatch Advocates and their
supporters that their proposal for realtime redispatch and third party
generation participation would allow for
additional long-term rights through
planning redispatch. If third party
participation in the offer of redispatch is
voluntary, transmission providers
would not be able to depend upon third
party resources in evaluating the
availability of resources during the term
FERC, 176 F.3d 1090 (8th Cir. 1999) (Northern
States Power).
696 Northern States Power, 83 FERC ¶ 61,338 at
62,369.
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of the planning redispatch service.
Transmission providers therefore would
only be able to evaluate the availability
of their own resource as they do today.
Thus, Transparent Dispatch Advocates
have failed to show how its proposal
would supplement provision of longterm rights.
1141. Because we find that the TDA
proposal for real-time redispatch and
third party participation is unnecessary
to remedy undue discrimination or
comparability issues, we need not
address the issue of the scope of the
Commission’s jurisdiction as it relates to
the TDA proposal.
(2) Redispatch Rate Transparency
Comments
1142. PJM argues that if the
Commission does not provide for
independently administered real-time
spot markets, it should require
transmission providers to ‘‘make public
their dispatch sequence and the realtime marginal costs of electricity.’’ 697 In
reply comments, Transparent Dispatch
Advocates request that the Commission
require publication of ‘‘dynamic realtime value of what [each transmission
provider] would charge to provide
redispatch service at specified
congestion locations within the
transmission provider’s system and at
specified flowgates at the border of the
transmission provider’s system.’’ 698 In
supplemental comments, Transparent
Dispatch Advocates state that ‘‘[t]he
essence of the TDA proposal is to
require transmission providers to make
real-time information about the cost of
redispatch available on their OASIS in
order to allow more efficient use of the
transmission system.’’ 699 Transparent
Dispatch Advocates, EPSA and AWEA
state that the posting requirement
should be limited to pre-determined
flowgates and that the estimated price
for redispatch should be posted
frequently and sufficiently in advance of
the hour in which the price would be
effective in order to allow the
transmission customer to change its
schedule and avoid redispatch charges.
1143. EPSA, AWEA and Transparent
Dispatch Advocates state that since this
information is available today and
considered by transmission providers in
serving their own native load, there are
no impediments to implementing their
proposed posting requirement.
Transparent Dispatch Advocates argue
that concerns about release of
confidential data can be addressed by
697 PJM
at 6.
698 Transparent
Dispatch Advocates Reply at 5.
Dispatch Advocates
Supplemental at 7.
699 Transparent
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using system costs instead of unitspecific cost data to calculate the posted
redispatch price. EPSA and AWEA state
that there are not confidentiality issues
with the Transparent Dispatch
Advocates’ posting proposal because
redispatch costs are not the costs that
the transmission provider is incurring to
sell energy into the market: they
contend that redispatch costs are the net
cost incurred by the transmission
provider, e.g., the difference between
the costs of ramping up and ramping
down resources. EPSA and AWEA also
state that there would be no competitive
concerns over the posting of this
information from third party suppliers
because the suppliers names need not
be used.
1144. Some commenters do not
believe that making certain information
publicly available will result in
confidential information disclosure.700
PPL states that while confidentiality
concerns must be considered, the nature
and type of information that is publicly
provided may be structured so as to
alleviate or minimize such concerns.
PPL argues that rather than posting
specific generator cost information the
all-in price for redispatch may be posted
instead. BP Energy argues that posting
redispatch prices at specified locations
reveals the economic value of adding
transmission/generation at those
locations, but does not reveal the
production cost associated with specific
generation resources. BP Energy states
that hourly redispatch costs should be
posted for all ‘‘significant congested
interfaces’’ within a transmission
provider’s control area and for all
interfaces at control area boundaries.
PGP asserts that transmission providers
with OATTs should post any available
information on hourly redispatch
costs.701 PGP and PPL argue, however,
that there should be an appropriate lag
in the disclosure of actual redispatch
costs in order to address confidentiality
concerns. Williams states that increased
transparency and proper monitoring are
immediate, real solutions to ‘‘issues’’
with the posting of the cost of
redispatch. Williams asserts that those
customers requesting redispatch should
be provided the cost differential
between the original dispatch and the
redispatch and that post audit
redispatch data and system models can
be made available (after the expiration
of a non-disclosure period) to provide
700 E.g., EPSA and AWEA Supplemental, BP
Energy Supplemental, and California Commission
Supplemental.
701 PGP asserts that the transmission provider
should be required to post redispatch information
by event and by entity to address concerns about
anticompetitive behavior.
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market certainty of least cost redispatch
and appropriate bid selection.
1145. PGP states that the redispatch
option should be available irrespective
of time frame, but must recognize the
limited ability of the transmission
provider to identify likely redispatch
costs further out in time. Thus, PGP
argues, posting redispatch costs in areas
without organized markets should focus
initially on real-time reliability
redispatch, later expanding to longer
time frames. PGP asserts that redispatch
should be undertaken only when firm
bids are available and the transmission
customer has accepted responsibility for
redispatch costs, which should be based
on just and reasonable prices and must
be known with a degree of certainty.
PGP adds that the transmission provider
should establish protocols that support
firm bids, which would be published
and, if accepted, result in binding
obligations on the part of the bidders.
PGP argues that it is reasonable for
transmission providers to post real-time
bids on constrained paths that are
otherwise subject to curtailments to
ensure compliance with reliability
criteria. PGP contends that postings
should take place on the transmission
providers’ OASIS and that all
information should be retained by the
transmission provider. PGP submits that
redispatch bids should be explicitly
added to the Commission’s Electric
Quarterly Reports filing requirements if
not already required.
1146. Constellation argues that the
Commission should require each
transmission provider to post two
values to the market on its OASIS site,
in order to enhance transparency:
historical costs of redispatch at certain
specified flowgates (perhaps those most
congested historically) and real-time
redispatch costs at the same flowgates.
Constellation submits that each
transmission provider engages in
redispatch and thus can readily
ascertain the cost of redispatch at
various locations. Constellation argues
that posting such costs will enable
transmission customers to more
accurately assess the potential costs of
redispatch prior to deciding to incur
redispatch costs. Constellation adds that
the customer receiving redispatch
should be obligated to pay the actual
costs of redispatch, regardless of the
costs reflected in the postings, which,
Constellation contends, should reflect
the transmission provider’s most
accurate and up-to-date information.
1147. Williams believes that
Transparent Dispatch Advocates’
redispatch proposal offers a partial
remedy to transmission congestion
caused by insufficient infrastructure and
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12413
undue discrimination. Williams
proposes that affiliate and third-party
generators submit either a preestablished rate structure or formulary
pricing methodology prior to the
provision of redispatch service.
Williams states the primary
implementation impediment to greater
transparency of redispatch cost
information is the accuracy and
availability of redispatch costs.
1148. BP Energy submits that posting
the costs of redispatch is not the same
as posting operational cost curves of
specific generating units. BP Energy
adds that, given the availability of
redispatch costs, there is no reason to
post the differential in unit-specific
costs as a supplement to marginal prices
posted at significant locations
throughout the control area. PGP states
that there is no need to establish
markets to provide real-time redispatch.
Rather, PGP asserts that limited
protocols can be established for specific
locations or types of congestion that
may be directly relieved via redispatch.
PGP believes that the Commission
should avoid establishing detailed rules
governing redispatch protocols, but
rather should permit regional practices
to be developed that result in ‘‘just and
reasonable’’ charges for redispatch
service.
1149. In its reply comments, Southern
states that requiring vertically integrated
utilities to post their real-time marginal
costs of electricity would be
discriminatory and violate the Trade
Secrets Act.702 Southern states that
RTOs do not make public the marginal
costs of the utilities participating in
their markets, thus requiring other
transmission providers to do so would
be discriminatory. Southern states that
marginal costs information is
commercial or financial information
protected by federal statute that if
released would put it at a competitive
disadvantage and harm its customers by
allowing competing generators to price
their power just below the published
marginal costs.
1150. Several parties assert that the
TDA proposal would require the posting
of vertically integrated utilities’
generation costs and thus would
provide competitors and buyers with
commercially-sensitive information.703
702 18
U.S.C. 1905.
Entergy Supplemental, Community
Power Alliance Supplemental, Progress Energy and
MidAmerican Supplemental, Southern
Supplemental, Southwest Utilities Supplemental,
Nevada Companies Supplemental, OG&E
Supplemental, Florida Commission Supplemental,
PPL Supplemental, Ameren Supplemental, North
Carolina Commission Supplemental, and SEARUC
Supplemental.
703 E.g.,
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Many of these parties assert that posting
a utility’s incremental costs publicizes
the price at which the utility elects to
operate resources rather than purchase
from a third-party.704 EEI and South
Carolina E&G assert that making this
information public may adversely affect
competition and markets. Duke argues
that having the transmission provider
post daily and hourly generator costs
assigns it responsibilities that are
beyond the typical transmission
function. Duke urges the Commission to
consider voluntary alternatives to
resource-specific cost information that
would divulge competitively-sensitive
data. SEARUC argues that any
incremental transparency improvements
not be implemented in such a manner
as to make competitively sensitive
information available to the public on
an inconsistent basis. Nevada
Companies assert that the requirement
to make such information publicly
available to the transmission provider
would have to be imposed upon all
generators, including independent
power producers, so that such
information would lose the value it
derives from not being publicly known.
1151. Entergy argues that the
Commission is statutorily prohibited
from requiring the disclosure of
information that undermines fair
competition under the electric market
transparency provisions in sections
220(b)(1) and (2) of the FPA.705 South
Carolina E&G submits that the TDA
proposal is inconsistent with this
provision of the FPA. Southern further
contends that mandating that
transmission providers post and offer
their generation on an at-cost basis,
while allowing third party generators to
submit bid prices would also be
discriminatory. TAPS asserts that the
proposed real-time disclosure of bid and
cost information runs contrary to the
Commission’s policy of a 6-month delay
for release of bid information.
1152. NRECA asserts that the
Transparent Dispatch Advocates fail to
explain why transmission providers
coordinating with third parties or
704 E.g., Entergy Supplemental, Community
Power Alliance Supplemental, Southern
Supplemental, Duke Supplemental and South
Carolina E&G Supplemental.
705 Entergy refers to the following language:
(1) The Commission shall exempt from disclosure
information the Commission determines would, if
disclosed, be detrimental to the operation of an
effective market * * *; and (2) [i]n determining the
information to be made available under this section
and the time to make the information available, the
Commission shall seek to ensure that consumers
and competitive markets are protected from adverse
effects of potential collusion and other
anticompetitive behaviors that can be facilitated by
untimely public disclosure of transaction-specific
information.
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neighboring transmission providers will
not run afoul of anti-trust and collusion
concerns that they are colluding in price
setting; and how to verify providers are
selecting the lowest bid unless they are
required to post all third party generator
bids as well as their own or their
affiliates’ cost of providing the service.
1153. Ameren asserts that the existing
OATT contains requirements for
information to be posted by
transmission providers, and does not
believe that additional posting ought to
be required. Ameren provides several
recommendations were the Commission
to adopt some or the entire TDA
proposal. First, Ameren asserts that
there are many different ways to
estimate this cost and, in order to avoid
the creation of competing methods for
estimating redispatch costs, the
Commission must consider and provide
guidance on several questions.706
Second, so that transmission providers
are not disadvantaged by this new
obligation, Ameren urges the
Commission to develop detailed
requirements, including uniform
timelines for posting, guidelines for
estimating cost, and inclusion of all
dispatchable generation in the relevant
footprint. Ameren further argues that
posting only the difference in costs
would not address the potential for
anticompetitive impacts. Finally,
Ameren contends that the Commission
may wish to consider implementing the
changes only on an interim basis, then
to observe whether there is any market
benefit or any competitive harm as a
result of the new requirements.
1154. Duke believes that the posting
of hourly redispatch costs would create
near-constant off-OASIS
communications between the
transmission provider and merchant
function employees, which, Duke
asserts, would raise Standards of
Conduct concerns.
1155. NRECA argues that allocated
costs may vary significantly regardless
of methodology, which devalues the
posting of costs. North Carolina
Commission argues that publishing
indicative redispatch costs in real time
would require a determination as to
how such costs are determined and
whether each component of such costs
are appropriately charged to customers.
706 Ameren raises several questions to this effect:
Does the transmission provider estimate cost effect
across all market LMPs or just the congested points?
Should the analysis take into account credits and
adjustments to which some participants may be
entitled? For what period should the transmission
provider provide this estimate? For those
transmission providers within a centralized market,
how should they treat market costs such as losses
or RSG (Revenue Sufficiency Guarantee in MISO)
in calculating the redispatch cost?
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Commission Determination
1156. After careful consideration of
the comments of the parties, we adopt
a posting obligation that balances
several competing considerations. First,
we agree with Transparent Dispatch
Advocates and supporting parties that
the increased availability of information
regarding redispatch costs can benefit
consumers and increase the efficient use
of the grid. Second, we are cognizant,
however, that increased posting and
reporting can impose cost burdens on
transmission providers or otherwise
harm market participants. For example,
the reporting obligations can reveal
confidential information that could
harm market participants or increase the
cost of serving native load customers.
We also recognize that the posting or
reporting obligation should be
reasonably tailored to provide useful
information to consumers without, at
the same time, imposing unnecessary
burdens on transmission providers,
either in the frequency of the posting
obligation or the scope of information
provided.
1157. In balancing these
considerations, we will, as explained
further below, adopt a requirement that
transmission providers post certain
redispatch cost information associated
with the existing redispatch services
that must be provided under the pro
forma OATT. We find that providing
customers with additional transparency
and greater information regarding the
cost of congestion, will facilitate their
consideration of planning redispatch
options which in turn will provide for
more efficient use of the grid. We stress,
however, that this posting requirement
relates only to the existing redispatch
services required under the pro forma
OATT; it does not expand those service
obligations. The primary purpose of the
posting requirement is to ensure that all
customers have access to this
information, not only the customer
receiving the redispatch service.
1158. Moreover, the costs of the
dynamic posting requirement proposed
by Transparent Dispatch Advocates
outweigh the benefits of such a
requirement. Transparent Dispatch
Advocates propose that the posting
requirement be limited to specified
congestion locations within and at the
border of each transmission provider’s
system. Transparent Dispatch Advocates
have not proposed ex ante criteria to
determine which flowgates would
require posting. In fact, some members
of the Transparent Dispatch Advocates
coalition would have the posting
requirement apply to all transmission
facilities, whether or not they were
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congested and whether or not customers
were seeking service over those
facilities. Such an open-ended
obligation to post costs for all facilities
on a transmission provider’s system
would unnecessarily impose
uncertainties and unbounded
administrative costs on transmission
providers. Additionally, depending on
the frequency of publication and the
method used to calculate the estimates,
the publication of these estimates could
reveal sensitive confidential information
about transmission providers’
generation costs that would likely harm
existing markets and native loads. There
is no simple formula for estimating the
costs that would fully mask this
confidential information and at the
same time provide practical information
about the costs of redispatch.
1159. While we agree that
transparency can benefit customers,
Transparent Dispatch Advocates have
not demonstrated the benefits of its
posting requirement to customers
seeking reliability or planning
redispatch. Transparent Dispatch
Advocates would have transmission
providers frequently post an estimate of
the cost of the next increment of
redispatch. Customers seeking
redispatch would not know the actual
costs customers paid for redispatch. Nor
would they be able to apply the estimate
of cost to their transactions since most
transactions would involve more than a
single increment of redispatch service
and there might be multiple redispatch
transactions over a single transmission
facility. Thus the estimate would only
be of value to the marginal customer
taking a small amount of redispatch
service. Transmission providers would
expend time and money determining
the correct formula to use to estimate
costs, collecting data for the inputs to
the calculation and frequently posting
estimates throughout each day that
could have little or no correlation to the
actual costs a transmission customer
would pay for the redispatch service.
1160. Third party participation in
redispatch is one of the benefits
Transparent Dispatch Advocates point
to in support of its proposed posting
requirement. Transparent Dispatch
Advocates would have transmission
providers act as the conduit for service
from third party redispatch providers,
collecting from customers and paying
third party providers. As described
above, we are allowing third party
participation in planning redispatch
without requiring transmission
providers to act as bill collectors for
third party redispatch providers or
requiring coordination agreements
among each transmission provider and
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all potential third party providers. This
OASIS modification, described above,
will provide third parties seeking to
provide redispatch with the opportunity
to frequently update the price of their
offers as suggested by Transparent
Dispatch Advocates.
1161. We do believe, however, that
information regarding actual redispatch
costs should be made more widely
available. Currently, when a
transmission provider provides
reliability or planning redispatch, the
associated cost information is provided
only to the customer receiving the
service through its invoices. This
ignores the fact that information
regarding the cost of redispatch can
benefit all customers and increase the
efficient use of the grid. We therefore
find that it is no longer just, reasonable
and not unduly discriminatory to limit
the provision of this information only to
the individual customers receiving the
service.
1162. Accordingly, to provide greater
availability of redispatch information,
the Commission adopts certain
additional posting requirements for
transmission providers. Specifically, we
direct each transmission provider to
post on OASIS its monthly average cost
of redispatch for each internal congested
transmission facility or interface over
which it provides redispatch service
using planning redispatch or reliability
redispatch under the pro forma
OATT.707 Additionally, to demonstrate
the range of redispatch costs each
month, the Commission directs
transmission providers to post a high
and low redispatch cost for the month
for each of these same transmission
constraints. The transmission provider
shall calculate the monthly average cost
in $/MWh for each congested
transmission facility by dividing
monthly total redispatch costs (at the
facility) by the total MWhs that would
otherwise be curtailed (at the facility) in
the month absent the redispatch.708
Transmission providers shall post
internal constraint or interface data for
the month if any planning redispatch or
707 The relevant reliability redispatch costs for
posting purposes are those costs the transmission
provider invoices network customers based on a
load ratio share pursuant to section 33.3 of the pro
forma OATT. The transmission provider need not
perform new calculations of out-of-merit dispatch
costs; rather the reliability redispatch invoices
should form the basis of information from which
the transmission provider determines monthly
average reliability redispatch costs.
708 For example, if reliability redispatch is used
by the transmission provider to prevent curtailment
of 10 MW of transmission provider or network
customer load for 5 hours during the month across
flowgate A, the transmission provider would use 50
MWh as the divisor to determine the monthly
average cost of redispatch for flowgate A.
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12415
reliability redispatch is provided during
the month, regardless of whether the
transmission customer is required to
reimburse the transmission provider for
those exact costs. Thus, if the
transmission customer pays for
redispatch pursuant to a negotiated
fixed rate, the transmission provider is
required to post and calculate the
monthly average redispatch costs and
the high and low costs in the month
even though the transmission provider
will bill the customer the fixed rate. The
same posting requirement applies if the
customer is paying a monthly ‘‘higher
of’’ rate.709 The transmission provider
shall post this data on OASIS as soon as
practical after the end of each month,
but no later than when it sends invoices
to transmission customers for
redispatch-related services. We direct
transmission providers to work in
conjunction with NAESB to develop
this new OASIS functionality and any
necessary business practice standards.
1163. There are several benefits to this
posting requirement. First and foremost,
it will give customers fairly current
information regarding the cost of
redispatch of the congested
transmission facilities over which
redispatch is provided, presumably
some of the most congested facilities on
transmission providers’ systems.
Second, it will limit posting only to
those congested transmission facilities
over which redispatch has actually been
sought and granted and for which
redispatch charges have been billed to
customers. This addresses commenters’
concerns about the posting of
information that is valuable only
hypothetically. Third, because we
require the posting of average redispatch
costs, not real-time redispatch costs or
real-time system lambda or system
incremental costs, it will not be harmful
to native load or reveal otherwise
competitively sensitive information.
1164. Finally, in addition to the above
posting requirement, we note that, as
part of the transmission planning
provisions adopted in this Final Rule,
we are providing customers with a right
to request a study of a defined number
of congested transmission facilities on
an annual basis. This will provide
customers an additional opportunity to
evaluate redispatch costs, including
costs for those congested transmission
facilities for which redispatch service
has not been granted.
709 This is not a new calculation for the
transmission provider because the transmission
provider must determine the redispatch costs to
know whether to charge higher of the embedded
rate or the redispatch costs.
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c. Other Requested Service
Modifications
NOPR Proposal
1165. In the NOPR, the Commission
summarized requests for various new
services made in response to the NOI.
The Commission’s proposed solutions
evaluated solely the planning redispatch
and conditional firm options.
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Comments
1166. Commenters make several
suggestions with regard to additional
services or modifications to existing
services. Most popular among the
suggested new services is long-term,
seasonally-shaped firm point-to-point
service. Several commenters support
this service for circumstances in which
the transmission provider determines
that the requested service is available
during some, but not all, months of each
year of a single or multiyear request.710
Commenters suggest that the long-term,
seasonally-shaped service would
provide an option for the transmission
customer in lieu of costly upgrades
without the operational difficulties of
conditional firm service. In its reply
comments, Powerex states that this
product would have less of an adverse
impact on existing firm rights holders.
Northwest IOUs propose that the
transmission customer pay the longterm point-to-point transmission service
rate prorated for the portion of the year
for which it receives the service. Public
Power Council states that the
transmission customer would be free to
purchase non-firm or secondary service
for the periods when firm service
through the seasonally-shaped service
was unavailable. Northwest IOUs argue
that ‘‘cream-skimming’’ is avoided by
processing only requests for long-term
service and having the transmission
provider determine the availability of
the service.
1167. Powerex supports the
implementation of a long-term non-firm
point-to-point service. Tacoma believes
priority non-firm or partial firm
transmission services are alternatives to
planning redispatch. Entegra proposes
an additional service that would allow
the customer, in the event of a
constraint, to agree to either pay for
redispatch or have its service curtailed.
In contrast to these request for new
services, TranServ states that simplified
services and a reduction in the number
of services would increase the
transparency and fluidity of electricity
trading.
710 E.g., MidAmerican, Public Power Council,
Northwest IOUs, Xcel, Powerex Reply, PPL, and
Seattle Reply.
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1168. MidAmerican urges the
Commission to allow for dynamic
scheduling service between control
areas on a case-by-case basis, by
including and pricing the service in the
service agreement. MidAmerican states
that this service would be similar to
point-to-point service, but would allow
the transmission customer to
dynamically monitor its loads in
neighboring control areas and dispatch
its own remote resource to meet the load
fluctuations in load pockets served by
other transmission providers.
MidAmerican further states that this
new service is necessary in the Western
Interconnection because neither pointto-point nor network service meets the
needs of loads that are not confined to
a single geographic area served by a
single transmission provider.
1169. Barrick states that the
Commission should require
transmission providers to confirm the
availability of secondary service for
network customers on a monthly or
quarterly basis so that network
customers can plan ahead for the use of
secondary service. In its reply
comments, Seattle supports the
development of short-term redispatch
service, currently under discussion for
provision in the Pacific Northwest.
TranServ requests that the Commission
clarify whether sequential reservation of
12 consecutive months of monthly firm
service is long-term service. TranServ
requests that the Commission direct the
development of business practices by
NAESB to allow customers to designate
minimum term and capacity for partial
interim service, similar to the practice
employed by Bonneville.
Commission Determination
1170. The Commission rejects the
requests to order new services or
modifications to existing services
suggested by commenters. We believe
that the modifications to point-to-point
transmission service adopted herein
best address the issues raised by these
requests. The planning redispatch and
conditional firm options provide a
means of remedying undue
discrimination, and increasing
transparency and access to the grid by
point-to-point customers. We note that
there is considerable overlap between
these options and the new services
suggested by commenters. However, we
find that the introduction of the
requested new services may create
greater complexities than those present
in the planning redispatch and
conditional firm options. For example,
several commenters propose a long-term
seasonally shaped firm point-to-point
service as a superior option to the
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conditional firm service. However,
requestors have not adequately
addressed concerns about the service,
including the potential for hoarding
transmission and the reliability issues
related to evaluating the availability of
the service or granting the service over
many years. A seasonally shaped service
could exacerbate the lumpiness of
transmission investment by preventing
customers willing to pay for
transmission upgrades from obtaining
all twelve months of service. While we
will not reduce the number of services
required as suggested by TranServ, the
Commission must limit the number of
new services adopted and modifications
to existing services to a reasonable
number that transmission providers can
reliably implement. For these reasons,
we decline to adopt any additional
proposals or modifications to firm
point-to-point service beyond those
directed above in this Final Rule. Of
course, transmission providers remain
free to voluntarily propose additional
services that are consistent with or
superior to the pro forma OATT, as
modified by this Final Rule.
1171. The Commission rejects the
request to adopt long-term non-firm
service because there is no indication
that customers would find such a
service useful and it would be
inconsistent with the policy in the pro
forma OATT that values firm service
over non-firm service.
1172. MidAmerican requests that the
Commission allow a point-to-point
service that would let a transmission
customer monitor its load and dispatch
its remote resources to meet load
fluctuations. In Order No. 888–A, the
Commission clarified that this type of
dynamic scheduling was not mandated
Order No. 888, but that nothing in Order
No. 888 precludes a transmission
provider from offering it as a separate
service.711 Thus, MidAmerican may
propose such a service pursuant to an
FPA section 205 filing with the
Commission, and we will consider it, as
we would any new service proposal, on
a fact-specific, case-by-case basis.
1173. Barrick requests that the
Commission require the confirmation of
the availability of secondary service for
network customers on a monthly or
quarterly basis so that network
customers can plan ahead for the use of
secondary service. As we stated in the
NOPR, secondary network service refers
to transmission service for network
customers from resources other than
designated network resources and is
provided on an ‘‘as available’’ basis.
Since the secondary service is provided
711 Order
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on an as available basis, Barrick’s
request seeks to allow secondary
network service to pre-empt firm uses of
the system, such as short-term firm
point-to-point service, for what is a less
than firm service. Barrick has not clearly
articulated why this proposal is
necessary to prevent the exercise of
undue discrimination or why service
from designated network resources
would not meet its need for firmer
secondary service. Thus, we reject
Barrick’s request.
1174. With regard to Seattle’s support
for redispatch being developed in the
Pacific Northwest, we believe that this
type of redispatch shares many of the
attributes of the Transparent Dispatch
Advocates proposal rejected above.
Although we acknowledge that market
mechanisms that provide hour-ahead or
real-time redispatch for all transmission
customers can provide benefits to
customers and efficient use of the
transmission grid, for the reasons stated
in the prior section, we will not require
in this Final Rule that all transmission
providers implement such market
mechanisms. We note that nothing
prevents the Commission from
reviewing proposals for such market
mechanisms on a case-by-case basis. We
note that the conditional firm and
planning redispatch options adopted in
this Final Rule will provide some of the
flexibility Entegra seeks. Customers
taking service under these options will
be able to choose, when executing the
service agreement, between curtailment
and redispatch.
1175. Also, the Commission clarifies
for TransServ that twelve months of
consecutive monthly firm service,
where the term of any particular
monthly service agreement is for less
than a year, is not long-term service.712
The Commission rejects TranServ’s
request that NAESB develop particular
business practices regarding partial
interim service as TranServ has not
shown a need for such a requirement.
1176. The Commission continues to
encourage transmission providers to
propose other services that are
consistent with or superior to the pro
forma OATT that meet customers’ needs
and make more efficient use of the
transmission system. We will not
mandate that transmission providers
provide any service other than the
services set forth in the pro forma OATT
since they may not be applicable in all
circumstances. However, if transmission
providers seek to provide any
modifications to the required pro forma
712 See pro forma OATT section 1.18 (defining
long-term firm point-to-point transmission service
as service with a term of one year or more).
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OATT services or new services, they
may submit an FPA section 205 filing to
propose such modifications and the
Commission will evaluate such
proposals on a case-by-case basis.
2. Hourly Firm Service
NOPR Proposal
1177. In the NOPR, the Commission
proposed to add point-to-point hourly
firm service to the pro forma OATT. The
Commission stated its belief that adding
this service would eliminate a barrier to
the development of markets and thereby
decrease opportunities for undue
discrimination. The Commission further
stated that the concerns expressed in
Order No. 888 regarding the unduly
discriminatory effects of hourly firm
service have proven unfounded.
Consistent with our precedent, the
Commission proposed to use the ‘‘IES
Method’’ to price hourly firm service
and apply different pricing based on
whether the service is taken during peak
or off-peak hours.713 The Commission
explained that this pricing method
would ensure that hourly firm
customers pay a fair share of the costs
of the transmission system.
1178. The Commission proposed
allowing transmission customers to
batch requests and schedules for hourly
firm service that will be provided
within the same calendar day.
Schedules for firm hourly service, like
all other firm schedules, would be due
by 10 a.m. the day before the service is
to commence. The Commission also
proposed that, consistent with other
durations of service, the confirmation
period for hourly firm service specified
in section 13.2 of the pro forma OATT
would allow longer term requests for
service to preempt shorter hourly firm
requests for service until one hour
before the commencement of hourly
firm service.
Comments
1179. Commenters are split on
whether to require hourly firm service.
Varied interests express some support of
the requirement, while mostly IOUs,
cooperatives, and public power
providers oppose the requirement.
Supporters, which include several
entities that currently offer hourly firm
service, foresee increased use of
713 See IES Utilities, Inc., 81 FERC ¶ 61,187 at
61,833–34 (1997), reh’g denied, 82 FERC ¶ 61,089,
aff’d on other grounds sub nom. Wisconsin Public
Power Inc. v. FERC, No. 98–61,089, 1999 U.S. App.
LEXIS 3998 (Feb. 23, 1999) (unpublished opinion)
(adopting peak and off-peak pricing to hourly nonfirm transmission service); see also New York State
Electric & Gas Corp., 92 FERC ¶ 61,169 at 61,593–
94 (2000) (approving application of the IES Method
for time-differentiated hourly non-firm rate design),
order on reh’g, 100 FERC ¶ 61,021 (2002).
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12417
transmission facilities and market
efficiencies. Chief among the arguments
cited by those objecting to the required
service is the potential adverse effect on
those serving native load or taking
longer term service due to increased
frequency of curtailments. Other
objections to the required service
include reliability concerns and the
unjustified curtailment priority that
would be afforded to short-term
customers that have not financially
committed to long-term grid service. To
the extent hourly firm service is
required, commenters generally support
use of the IES Method for pricing,
although some commenters ask the
Commission to allow pricing to vary
according to regional practice. As for
batching and scheduling, many parties
request that the Commission clarify
specific details of each of these
proposals to prevent future disputes.
Mandatory Hourly Firm
1180. Various commenters state their
general support of, or non-opposition to,
the proposal to require hourly firm
service.714 Among those who support it,
several state that they already supply
the service themselves.715 Such
commenters argue that hourly firm
service would decrease opportunities
for undue discrimination, enhance the
customer’s ability to participate in the
real-time energy markets, encourage
trade and marketing liquidity, increase
firm uses of the grid, allow greater
customer choice, increase efficiencies in
wholesale markets, and help maximize
use of existing transmission facilities.716
WAPA states that its experience
indicates that the current provisions for
preempting shorter-term transmission
service with longer-term service, as
codified in OATT section 13.2,
adequately serve to discourage
speculative hoarding of hourly capacity.
1181. Numerous commenters
objecting to the proposed service cite
the effect of curtailment on customers
taking network or longer term service,
especially in the service of native
load.717 Specifically, they argue that the
inclusion of an additional short-term
firm service would increase the
714 E.g., Ameren, Arkansas Commission,
Bonneville, BP Energy, Constellation, FirstEnergy,
MidAmerican, MISO/PJM States, Morgan Stanley,
Nevada Companies, Newmont Mining,
NorthWestern, Pinnacle, PPL, CREPC, and Suez
Energy NA.
715 E.g., Bonneville, Pinnacle (noting Arizona
Public Service Company’s adoption of the service),
PNM–TNMP, and WAPA (in its Desert-Southwest
region).
716 E.g., Arkansas Commission, BP Energy,
FirstEnergy, Morgan Stanley, Pinnacle, PNMTNMP, and PPL.
717 e.g., APPA, Duke, EEI, MISO, and Southern.
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likelihood that longer-term service
would be curtailed and degrade the
reliability of service to native load, since
all firm service (point-to-point and
network), regardless of duration, would
be curtailed pro rata. Objecting
commenters argue that such a result is
unfair to customers that have made a
long-term commitment to taking service,
including expanding the system;718
inconsistent with FPA section 217(b)(4),
which requires the Commission to
promote the availability of transmission
for native load service;719 and
inconsistent with the Commission’s
commitment in the NOPR to maintain
existing native load protections.720
1182. Although transmission
providers plan for their native load
needs when calculating ATC, Imperial
argues that they cannot always
accurately predict these needs. Imperial
states that transmission providers have
been able to rely on the release of
unscheduled capacity when balancing
their schedules to meet fluctuating
needs (such as during heat waves). In
view of the decline in transmission
infrastructure relative to load
throughout the country, NRECA objects
to the reduction in ATC that would
result from dedicating transmission
capacity to hourly firm service. NRECA
argues that designated network
resources may no longer be regarded as
such because firm transmission to
support them is not available on
constrained transmission systems (i.e.,
most transmission systems). If hourly
firm service is to be required, Imperial
proposes also requiring transmission
providers to make available all but 20
percent of non-reserved transmission as
firm so that non-firm service will be
available for the use of network
customers and native load providers.
1183. Southern argues that the
provision of hourly firm service would
require the transmission provider to
predict the exact hour on which
expected peak conditions will occur in
order to be able to post the amount of
hourly firm service that will be available
for each hour of a given day. If system
conditions then change, Southern
continues, reliability could be placed in
jeopardy, which would result in longterm service being curtailed. Southern
also argues that the provision of this
hourly firm service would complicate
real-time operations and negatively
impact reliability since, if curtailments
on a specific path prove necessary, it is
more difficult to curtail a large number
718 e.g.,
MISO and Southern.
719 e.g., APPA, NRECA, and Southern.
720 e.g., Southern.
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of transactions on a very short-term
notice.
1184. Many argue that the
justifications provided in Order No. 888
for not requiring this service remain
valid, such as the argument that the
service will invite cream skimming.721
MISO sees a likelihood that an ‘‘hourly
priority war’’ would ensue on
constrained interfaces between firm and
non-firm requests and that resolving
these conflicts would be time
consuming and stretch its resources.
MISO argues that an hourly firm
product would degrade the value of
non-firm service and that the
introduction of this new, logistically
challenging service, further compounds
the task of rooting out undue
discrimination. MISO argues that the
proposed mandatory introduction of
this service will have serious adverse
implications for many functioning
RTOs. MISO contends that hourly firm
service should remain strictly optional
for RTOs arguing that weighing the pros
and cons of this new service can best be
addressed within each RTO’s
stakeholder process.
1185. TVA argues that hourly firm
reservations would likely end up being
bumped by requests for longer service
(such as daily firm), consuming valuable
transmission provider staff time and
resources on administrative tasks with
no real benefit and potentially
significant costs. Similarly, Southern
argues that hourly firm service would
likely result in the transmission
provider receiving less revenues
(because fewer customers would take
daily firm service) while incurring
higher costs (due to implementation
complexities), the net effect of which
would raise OATT charges.
1186. Among commenters offering
qualified support for mandatory hourly
firm service,722 ELCON and FirstEnergy
ask the Commission to monitor the use
of this service and to reconsider its
continued need if it impairs the quality
or availability of long-term firm
services. Powerex argues that hourly
firm point-to-point service could
increase opportunities for undue
discrimination unless the conditions
under which the non-firm transmission
service can be interrupted are clarified.
South Carolina E&G argues that the
Commission should give the service a
lower curtailment priority than any
longer term firm service (citing as
support the lower reservation priority
for short term firm service in section
721 e.g., LDWP, MISO, Southern, TAPS, TDU
Systems.
722 E.g., ELCON, FirstEnergy, Powerex, and South
Carolina E&G.
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13.2(iii)) and adopt the proposal to
require that hourly firm service be
scheduled the day before service is to
commence.
1187. Duke explains that the current
10 a.m. deadline for firm schedules
need not be enforced in the absence of
hourly firm service and often is not
enforced (with transmission providers
acting on a comparable basis in waiving
the deadline). Thus Duke identifies as a
drawback to the addition of hourly firm
service the likelihood that transmission
providers will enforce the 10 a.m.
deadline and thereby reduce existing
flexibility.
1188. Some commenters objecting to
the new service requirement argue that,
if the Commission retains this service,
certain modifications should be
made.723 These modifications include:
giving the service a lower curtailment
priority, pricing it at a premium above
the IES methodology, requiring that the
firm hourly postings be based upon the
daily firm ATC (with the additional
capacity that might be available in
‘‘shoulder’’ hours of the day being made
available only as hourly non-firm), and
giving secondary network service a
higher priority over hourly firm. Duke
argues on reply that, if the Commission
determines that hourly firm service
should be required, a technical
conference should be held to develop
appropriate, workable tariff language in
light of the implementation issues
raised by commenters.
Voluntary Hourly Firm Service
1189. Various commenters ask that
hourly firm service not be required and,
instead, continue to be allowed on a
voluntary basis by willing transmission
providers.724 These commenters
generally argue that the service’s effect
on reliability, curtailment priority,
longer term service, transmission
expansion, and the ability to serve
native load counsels against mandating
the service. NRECA argues that hourly
firm service would unduly interfere
with the ability of network customers
(and the transmission provider on
behalf of its native load customers) to
use secondary network service, which is
offered only on an ‘‘as available’’ basis
and therefore would have a lower
reservation and curtailment priority
than hourly firm service.
1190. NRECA notes that the Western
Interconnection, where hourly firm
service has proven to be a useful
product, differs from the Eastern
723 e.g.,
APPA, NRECA, Southern, and TAPS.
APPA, Duke, East Texas Cooperatives,
EEI, Imperial, LDWP, LPPC, Northwest IOUs,
NRECA, PJM, Southern, and TDU Systems.
724 E.g.,
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Interconnection in a number of respects,
in particular, by virtue of extensive
reliance on point-to-point service by
LSEs to serve native load. For this
reason, NRECA continues, public utility
transmission providers should only be
allowed to voluntarily offer hourly firm
transmission service if the service is
available equally to all transmission
customers and the new service does not
undermine the quality of, and flexibility
of, the transmission provider’s existing
network service (including secondary
network service) and point-to-point
transmission service. NRECA also
requests that the Commission clarify
that the only circumstance in which
hourly firm service could be offered
would be if daily service were not being
fully used.
1191. Northwest IOUs suggest that the
Commission develop standardized
point-to-point hourly firm service
provisions for the voluntary provision of
this service by those transmission
providers that determine such service
would be appropriate to offer on their
systems. TDU Systems argue that the
Commission should condition approval
of an hourly service on requirements
that a lower curtailment priority is
established for hourly firm service than
other firm services, including secondary
network service; and, it may only be
sold in the hour preceding the start of
service to ensure that hourly service
would not impede the provision of
service to other firm services, including
secondary network service. In light of
comments, Powerex abandoned its
initial conditional support for the
proposal to support voluntary provision
of the service.
Alternative Proposals
1192. PJM recommends adding a
service similar to PJM’s non-firm willing
to pay congestion (NF–WPC) service
which may serve the same purpose as,
and be an alternative to, hourly firm
service. NF–WPC service would be
evaluated for ATC and curtailed by
transmission customers if the effective
price of congestion were too high. Thus,
NF–WPC service will result in a
reduction in all TLR curtailments. To
add this service to the OATT, PJM
explains, all transmission providers
with control over dispatch would have
to provide a transparent means for
redispatch to clear congestion and
maintain reliability on either side of a
border.
1193. Xcel argues that it is possible
that hourly firm service would not be
needed if the existing OATT were
clarified as it relates to priority of nonfirm service. Xcel proposes that the
Commission could clarify that non-firm
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service is not interruptible during the
hour due to other non-reliability driven
requests, but rather at the start of the
next hour, provided sufficient
scheduling notice is given. Xcel
continues that this clarification would
also stipulate that non-firm service (and
all other types of service) may be
curtailed without notice at any time for
reliability reasons.
Pricing
1194. Many commenters support the
Commission’s proposal to use the IES
Method to price hourly firm service.725
Several commenters suggest that the
Commission allow transmission
providers to define their own peak and
off-peak hours under the IES
methodology, with some suggesting that
it should be allowed as a regional
variation to account for the different
peak times in regions such as the
WECC.726 East Texas Cooperatives asks
the Commission to require that revenue
from hourly firm service be applied as
a credit to network service revenue
requirements like other point-to-point
services. PGP supports the IES Method,
but recommends that the Commission
be open to other approaches.
Reservations, Scheduling, Preemption
and Right of First Refusal, Batching
1195. Some commenters support the
proposed reservation or scheduling
requirements for hourly firm service.727
Others commenters express concerns
regarding, or object to, this aspect of the
hourly firm proposal.728 As discussed
below, several commenters suggest
modifications to different components
of the proposal.
1196. Some commenters state that
hourly firm should be a means of selling
unused capacity in hours not purchased
for longer-term transactions and, as a
result, it will be important to establish
a sequencing for sales that accomplishes
this so that cream skimming does not
occur.729 Tacoma recommends that the
Commission establish hourly firm
service as the lowest priority in the
service request queue. Tacoma also
suggests that the Commission limit the
purchase of hourly firm in such a way
as to assure that the purchase is not an
attempt to manipulate a market, such as
making the service available only to
LSEs, which Tacoma states would
725 E.g., Ameren, EEI, NorthWestern, PGP, and
PNM–TNMP.
726 E.g., Northwest IOUs, Public Power Council,
and CREPC.
727 E.g., Ameren, Duke, NorthWestern, PNM–
TNMP, and WAPA.
728 E.g., Bonneville, Southern, and TVA.
729 E.g., Public Power Council and Tacoma.
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12419
ensure that capacity is utilized to meet
a real market need.
1197. SPP urges the Commission to
apply the same reservation deadline to
hourly firm as used for daily firm
service in order to make the service
easier to administer (and limit the
impact on non-firm service). Bonneville
also suggests that reservation timing
requirements be the same as those for
hourly non-firm service and, with
respect to competing reservations,
hourly firm service be classified as
Short-Term Firm. TVA notes that
although the scheduling deadline for
service is 10 a.m. the day before service
is to commence, the NOPR also states
that longer-term requests may preempt
shorter requests until one hour before
the commencement of service. TVA sees
an inconsistency in that it appears firm
service can be reserved and scheduled
after 10 a.m. on the day prior all the way
up until one hour before the service is
to commence. TVA argues that no
service that could preempt the hourly
service should be sold after the 10 a.m.
day-ahead deadline, and requests that
the Commission clarify this ambiguity.
1198. If the Commission requires
hourly firm service, Progress Energy
requests that it be offered on a dayahead basis only, as proposed in the
NOPR, to allow transmission providers
sufficient time to analyze the reliability
impacts of the requested hourly firm
service. Nevada Companies recommend
that any hourly firm service have the
same scheduling deadlines as daily firm
and that customers not be permitted to
submit hourly firm schedules
throughout the day. In Nevada
Companies’ view, this would enable
transmission customers to schedule firm
transmission only for the part of the day
that it is needed while, at the same time,
transmission providers would not be
overwhelmed with the task of
administering the reservation process.
1199. Some recommend that
scheduling conform to the existing
scheduling practices in each region,
such as in the WECC.730 For its part,
MISO argues that the proposed
scheduling deadline for hourly firm
service is before the deadline for the
submittal of the MISO daily firm
service, which would require a
substantial change to its Energy Markets
Tariff, firm service evaluation process,
and other firm and non-firm timing
requirements. MISO argues that this
could adversely affect the current Joint
and Common Market Alignment of
Business Practices initiative with PJM.
Public Power Council offers
730 E.g., MidAmerican, Northwest IOUs, Public
Power Council, and CREPC.
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Bonneville’s scheduling timeline as an
example in which longer blocks get
priority over the shorter blocks within
the 10 a.m. to 2 p.m. preschedule-day
reservation period, and hourly firm is
bought within the day at the same times
as hourly non-firm transmission (i.e., up
to 20 minutes prior to the delivery
hour).
1200. Occidental requests that the
Commission change the 10 a.m. daybefore scheduling timeline to be as close
to real-time as possible. It contends that
under the pro forma OATT, merchant
generators still will be relegated to
making non-firm reservations and sales,
because the 10 a.m. prior day firm
service scheduling timeline would
cause them to incur expensive
reservations to the sales point, but not
be able to have the transaction tagged
with source and sink (as required under
the NERC tagging procedure), before
consummation of the firm hourly
transaction. Occidental further contends
that the change in scheduling timeline
will not be problematic to the
transmission providers, particularly if
the transaction takes place in a single
control area. Occidental also argues that
the OATT benefits the transmission
provider, which can favor its own or
affiliated generation when balancing
with other control areas and dispatching
in real time.
1201. Bonneville, which has provided
hourly firm service since 2002, takes
issue with the fact that the Commission
proposes that the service would become
unconditional only one hour before the
commencement of delivery. Bonneville
argues that its own timeline, under
which hourly firm service becomes
unconditional at the close of the
preschedule window for the day of
delivery (currently, at 2 p.m. of the
preschedule day or as soon as
practicable thereafter), is superior and
should be adopted by the Commission.
Bonneville explains that, in its
experience, customers place great value
on having unconditional firm rights
before they reach the real-time
scheduling window, and an hour leaves
little or no time to make alternative
arrangements if the hourly firm
reservation is preempted. Finally,
Bonneville foresees potential reliability
effects if a customer using hourly firm
transmission for operating reserves is
preempted the hour before delivery, and
is unable to make transmission
arrangements elsewhere.
1202. Ameren argues that a later
request for hourly firm service should
not be able to preempt an earlier
request, even if it is for a greater number
of hours. According to Ameren, this will
provide certainty to users of this service
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since they will know they will not be
bumped by other customers using the
service.
1203. Duke requests guidance on how
long the hourly firm customer has to
respond to a competing request. Since
hourly firm could be preempted up to
an hour before the schedule starts, Duke
argues that in many cases there will not
be 24 hours available and the
scheduling deadline (of 10 a.m. of the
day prior to commencement of such
service) may have passed. For example,
if a pre-confirmed, longer-term,
competing request is received just prior
to the deadline (one-hour prior to
service commencing), Duke questions
whether the transmission provider is
required to offer the right of first refusal
at all.
1204. Joined by TranServ, Duke also
requests that the Commission provide
guidance on how to administer the right
of first refusal when, for example, three
different hourly customers have
confirmed reservations on a constrained
interface for different hours in a day and
the transmission provider then receives
a pre-confirmed request for daily service
on the same path for the same day.
Alternatives solutions for this scenario
offered by Duke include offering the
shorter-term customers simultaneous or
consecutive opportunities to exercise
the right of first refusal, prohibiting the
preemption of multiple overlapping
requests, or denying shorter term
customers a right of first refusal. Duke
recommends NAESB develop
appropriate business practice standards
after the Commission’s decision on this
issue.
1205. With the NOPR’s potential for
adding more complexity with hourly
firm service under similar conditions as
other short-term firm services, TranServ
requests that the Commission either
eliminate the conditional nature of
short-term firm point-to-point service
under the OATT (and the reservation
window would be set to not interfere
with requests for daily firm service) or
allow hourly firm service to be
preempted without a right of first
refusal.
1206. Duke requests that, whether or
not the Commission requires hourly
firm service, the Commission clarify
how the ‘‘short-term rights of first
refusal’’ should be implemented in
section 13.2(iii) of the OATT, since
there already is some lack of clarity with
regard to this right for daily, weekly,
and monthly service.
1207. Based on its experience, WAPA
suggests that the Commission institute
limits on the allowable time period in
which customers may contact the
transmission provider for the purpose of
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withdrawing an hourly firm request in
order to avoid potential ‘‘gaming’’ issues
that may arise from entities requesting
transmission on a pre-scheduled basis
and then asking for the request to be
withdrawn during real-time. To simplify
real-time administration of hourly firm
service, WAPA suggests that the
Commission explicitly include in the
revised pro forma OATT a statement
waiving the Order No. 638 displacement
rules for hourly requests during the
hour before the service is to commence.
1208. Several commenters support the
Commission’s batching proposal.731
WAPA argues that the proposed
limitation on batching hourly firm
requests and schedules to within the
same day would alleviate the workload
issues associated with evaluating
individual hourly firm reservations in
order to identify conflicting schedules
across congested paths.
1209. MidAmerican objects to the
batching proposal, arguing that
transmission requests should be
evaluated in queue order and schedules
linked to a specific OASIS request.
MISO argues that the batching proposal
may interfere with the established
protocols for transmission service
request processing. In MISO, for
example, there is no interface for
Available Share of Total Flowgate
Capability, which would seem to
suggest that batch processing could
infringe on the various Commissionapproved seams agreements.
1210. Some commenters offer
modifications or request clarifications.
Bonneville proposes that NAESB
develop industry standards for defining
and processing batched reservations and
schedules. EEI argues that transmission
providers who offer hourly firm service
should permit their customers to batch
multiple requests for service that have
the same points of receipt and delivery;
are for the same quantity of service, and
are for the same day. Otherwise, EEI
explains, batching will complicate the
ability of the transmission provider to
study requests for hourly service.
NorthWestern explains that it cannot
fully support the Commission’s
recommendation to allow ‘‘batching’’ of
requests without a more clear definition
of what may be batched and a
determination that requests of a longer
increment preempt shorter increment
requests (e.g., a request for daily service
preempts a request for hourly service)
regardless of how many hours are
batched together.
1211. TranServ states support for the
ability to batch requests and schedules
for multiple hours of firm service with
731 E.g.,
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varying capacity over the hours.
However, with respect to competing
requests and the right of first refusal,
TranServ suggests that the preempting
request must be for a fixed capacity over
the term of the request to be considered
a competing request. According to
TranServ, this would prevent potential
gaming by a customer submitting a
request for one extra hour at 1 MW to
gain priority over another reservation.
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Commission Determination
1212. In light of the potential for
market disruption and the scheduling
complications that would arise from
providing hourly firm service, we
decline to adopt in the Final Rule the
proposal to require transmission
providers to offer hourly firm service.
While there is some industry support for
hourly firm service, we conclude that
the downsides associated with requiring
transmission providers to offer hourly
firm service outweigh the benefits of the
proposal due to the significant issues
raised by commenters. Commenters
opposing mandatory hourly service
raise a number of legitimate concerns
with respect to the service’s potential to
adversely affect reliability and create
additional complexity and inefficiency
in scheduling and administering the
right of first refusal. We do not believe
that the modifications suggested by
commenters supporting the service
adequately resolve these concerns.
Given regional differences and varying
system constraints, a solution that may
be appropriate for resolving scheduling,
reservation or other issues resulting
from hourly firm service on one
transmission system may not be
appropriate for another transmission
system. Moreover, even the commenters
supporting the proposal do not
demonstrate a clear need for an hourly
firm service product. The Commission
therefore concludes that requiring
hourly firm service is not needed to
address undue discrimination, the goal
of this rulemaking.
1213. To the extent they deem it
appropriate, transmission providers will
continue to have the option to propose
offering hourly firm service in an FPA
section 205 filing with the Commission.
Because we are not adopting the
mandatory hourly firm service proposal,
we believe that the most serious
concerns regarding scheduling shortterm service and administering the right
of first refusal are alleviated. We address
scheduling and right of first refusal
issues relating to existing services in
section V.D.5.b.
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3. Rollover Rights
1214. Section 2.2 of the pro forma
OATT allows existing firm transmission
service customers—wholesale
requirements and transmission-only
customers with contracts of one year or
more—the right to continue to take
transmission service from the
transmission provider when the
customer’s contract expires. The pro
forma OATT provides that the
transmission reservation priority is
independent of whether the existing
customer continues to purchase
capacity and energy from the
transmission provider or elects to
purchase capacity from another
supplier. This transmission reservation
priority for existing firm transmission
service customers, which is also referred
to as a right of first refusal or a rollover
right, is an ongoing right that currently
may be exercised at the end of all firm
contract terms of one year or longer. A
transmission customer must give notice
of whether it will exercise its right of
first refusal 60 days before the
expiration of its service agreement.
1215. In Order No. 888, the
Commission provided that, if a
transmission customer subject to the
rollover right selects a new power
supplier that substantially changes the
location or direction of its power flows,
the customer’s right to continue taking
service from the transmission provider
may be affected by transmission
constraints associated with the
change.732 The Commission also
provided that a transmission provider
may reserve existing capacity for retail
native load and network load growth
reasonably forecasted within the
transmission provider’s current
planning horizon, but that any capacity
so reserved must be posted on the
transmission provider’s OASIS and
made available to others until the
capacity is needed for the anticipated
network or retail native load use.733 The
Commission also has held that a
transmission provider may restrict a
right of first refusal based on preexisting contracts that commence in the
future if the transmission provider
knows at the time of the execution of
the original service agreement that ATC
used to serve a customer will be
available for only a particular time
period, after which time it is already
committed to another transmission
customer under a previously confirmed
transmission request.734 Once a
transmission provider evaluates the
No. 888 at 31,665 n.176.
at 31,694.
734 E.g., Southwest Power Pool, Inc., 109 FERC ¶
61,041 at P 6 (2004).
12421
impact on its system of serving a longterm firm transmission customer and
grants the transmission customer
existing capacity, the transmission
provider must plan and operate its
system with the expectation that it will
continue to provide service to the
transmission customer should the
transmission customer exercise the right
of first refusal. If constraints arise after
a transmission provider enters into a
long-term agreement with the
transmission customer (and that
agreement does not contain an allowed
restriction on the transmission
customer’s right of first refusal), the
obligation is on the transmission
provider to either curtail service to all
affected customers or build more
capacity to relieve the constraint.735 A
transmission provider is obligated to
curtail service pursuant to its OATT or
expand its system when its system
becomes constrained such that it cannot
satisfy existing transmission customers,
including the exercise of their rollover
rights, because it should have planned
and operated its system with the
expectation that each long-term firm
transmission customer will exercise its
rollover rights.736
1216. If a transmission provider’s
transmission system cannot
accommodate all of the requests for
transmission service at the end of the
contract term, the existing long-term
transmission customer must agree to
match the rate offered by the potential
customer, up to the transmission
provider’s maximum rate, and to accept
a contract term at least as long as that
offered by the potential customer.
However, a competitor’s offer does not
have to be ‘‘substantially similar in all
respects’’ to the existing transmission
customer’s.737
NOPR Proposal
1217. In the NOPR, the Commission
proposed to revise the right of first
refusal provision in the pro forma
OATT to apply to firm wholesale
requirements and transmission-only
contracts that have a minimum term of
five years, rather than the current
minimum term of one year. In addition,
a transmission customer under a
rollover agreement would be required to
provide notice of whether it intended to
exercise its right of first refusal no less
than one year prior to the expiration of
its contract, rather than the current 60
days. The Commission proposed to
maintain the requirement that an
732 Order
735 Id.
733 Id.
736 Id.
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at P 9.
737 Idaho Power Co. v. FERC, 312 F.3d 454, 462
(D.C. Cir. 2002).
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existing transmission customer match
competing offers as to term and rate.
The Commission discussed whether
native load restrictions should be
reevaluated with each rollover and, if
so, whether native load should then be
required to compete with rollover
customers for the capacity. The
Commission also asked for comment on
whether there is a sufficiently clear,
consistent, and transparent method that
could be implemented on a generic
basis to address the need for a
transmission provider to demonstrate its
forecast of native load growth and its
effect on capacity reserved by rollover
customers. The rollover reforms were
proposed to be effective as to new
transmission contracts upon
Commission acceptance of the
transmission provider’s coordinated and
regional planning process required by
the Final Rule, with existing rollover
contracts becoming subject to the new
rules on the first rollover date after the
effective date of the revisions.
a. Five-Year Minimum Contract Term
Comments
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1218. Many commenters support the
increase in the contract term eligible for
a rollover right.738 These commenters
support the increase to five years based
largely on the Commission’s rationale
for proposing it, i.e., an increase to five
years would encourage longer-term use
of the grid and assist in long-term
planning. Many also point out that a
longer minimum term reduces the
universe of contracts transmission
providers must assume will exist in
perpetuity, thereby increasing certainty
and reducing speculation. These
commenters also argue that rollover
reform will improve reliability and
provide increased revenues to perform
upgrades. Some also argue that this is
consistent with the native load
protections in new section 217 of the
FPA.
1219. E.ON, for example, notes that
system expansions may have been
limited in the past because transmission
providers did not want to commit
738 E.g., APPA, Barrick Reply, Bonneville,
Community Power Alliance, Constellation,
Dominion, Duke, EEI, Entegra, Entergy, E.ON,
FirstEnergy, Great Northern, Imperial, Indianapolis
Power Reply, LPPC, LDWP, MidAmerican, MISO,
MISO Transmission Owners, Nevada Commission,
Nevada Companies, North Carolina Commission
Reply, Northwest IOUs, NorthWestern, NPPD, PGP,
Pinnacle, PNM–TNMP, Progress Energy, Public
Power Council, Sacramento, Salt River, Santa Clara,
Seattle, South Carolina E&G, Southern, SPP,
Tacoma, TAPS, TransServ, TVA, Utah Municipals,
and Xcel. The Commission notes that several of
these commenters have conditioned or qualified
their support on the adoption of a number of
modifications, which will be discussed below.
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resources to accommodate a service
guaranteed for only one year, and Xcel
and TVA note that the increase in term
should encourage investment and
expansion of the grid by providing
improved certainty of cost recovery. EEI
stresses that there is no single minimum
rollover term that works for all parties,
as power purchase contract terms vary
and some state planning obligations
require purchases for longer or fewer
than five years, but that five years
represents a reasonable balance.
Southern emphasizes that the reforms
should also improve reliability, promote
the provision of service to native load
transmission customers, and increase
market efficiencies by releasing
transmission capacity to the market. In
its reply, Southern expresses its belief
that the current policy of requiring
transmission planners to assume that all
agreements having a minimum term of
one year will continue taking service in
perpetuity threatens reliability. In
Southern’s view, this policy results in
planning that is based on speculation
and guesswork that can signal a need for
inappropriate and expensive
transmission upgrades and mask the
need for appropriate expansion.
1220. However, several modifications
and clarifications were sought by some
commenters before they could agree to
an increase in the minimum term to five
years. APPA, Sacramento, and TAPS
contend that transmission customers
making this long-term commitment
should be permitted to change their
designated resources and receipt points
as their power supply needs change.739
APPA also asserts that transmission
customers that agree to a five-year
contract term should not be forced to
compete with other transmission
customers for firm capacity whenever
their contracts come up for renewal.
Without such assurances of continued
service, APPA argues that the
Commission’s proposals would not
comport with section 217 of the FPA.740
1221. In order to further ensure
continued service, TAPS seeks the
following modifications: Transmission
providers should be required to
redispatch if necessary to accept a
‘‘reasonably foreseeable’’ and timely
designated network resource with costs
shared on a load ratio basis;
transmission providers should be
required to offer cost-based sales to
embedded transmission-dependent
utilities that cannot reach alternative
suppliers; and exceptions should be
739 See
also TDU Systems Reply.
also NCEMC and Arkansas Municipal
(opposing the increase in the minimum term to five
years).
740 See
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permitted to the five-year minimum
term and matching exposure for small
embedded transmission-dependent
utilities and full or near-full
requirements customers to ensure a
continued right to service. Additionally,
TAPS asserts that the minimum rollover
in the absence of a competing request
should be one year, rather than five.
1222. TDU Systems, which generally
opposes the increase to five years,
believes that the Commission should
clarify that rollover customers retain
their rights to transmission capacity in
the event of competing bids from either
the transmission provider or another
transmission customer if the rollover
customer matches up to a five-year
contract term. Lastly, Seattle is
concerned that with a five-year
minimum, the risk in multi-segmented
transmission transactions of one
segment being undone by refusal of
another is increased. Seattle suggests
that acceptance and confirmation of one
segment be made contingent on
coordinated acceptance and
confirmation on all other required
segments.
1223. In its reply to the arguments
that rollover rights should be extended
to accommodate service at new receipt
or delivery points, EEI argues that this
would allow a rollover customer to have
priority over higher-queued customers
on transmission paths other than the
path over which the rollover customer
is currently taking service, even if the
new service would have different
impacts on the transmission system. EEI
argues that such service would be new
service and not a rollover of existing
service. EEI also urges the Commission
to reject TAPS’s assertion that it should
require the transmission provider to
accept rollover customers’ designations
of any network resources that are
reasonably foreseeable and to redispatch
its system if necessary to accommodate
that resource, because among other
things this would require providers to
build the transmission system with
sufficient redundancy to permit any
customer to take service from any
resource. Moreover, EEI argues that
TAPS does not provide any suggestion
as to what should be considered a
reasonably foreseeable resource and that
sharing costs on a load ratio basis would
result in eighty to ninety percent of the
redispatch costs being borne by the
transmission provider’s native load
customers.
1224. EEI also argues in its reply that
TAPS’s proposal to exempt all small
customers from the five-year minimum
term would interfere with transmission
providers’ ability to plan their systems
to meet their customers’ needs, as the
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aggregated loads of several small
customers can have a substantial impact
on the system. EEI contends that TAPS’s
proposal to exempt all full and near-full
requirements customers is also
unreasonable, as the transmission
provider would be forced to provide
preferential service to certain groups of
customers. As for the proposal to allow
customers to exercise rollover rights
with only one-year contracts if there is
no competing request, EEI contends
there is no need for a rollover if there
is no competing request, since there is
enough capacity for all and the
transmission provider will grant the
customer’s new request for service for
one year.741
1225. The increase in the minimum
contract term eligible for a rollover right
was opposed outright by several
commenters for a variety of reasons.742
Many of these commenters oppose the
increase to five years because they claim
it is difficult under current market
conditions to secure a five-year power
supply agreement to underpin a fiveyear transmission contract, particularly
in organized markets where the focus is
on spot transactions or where the grid
is very weak.743 They also argue that
changes in the market (e.g., fuel costs)
could significantly change the options
available to customers within a five-year
period and that a service extension of
less than five years may be needed to
manage delays in generation
construction or some other
unforeseeable event. TDU Systems urge
the Commission to require any
transmission provider seeking an
increase in the minimum contract term
to demonstrate that sufficient economic
power supplies are available under
longer-term contracts. EEI replies that
such an approach would be inconsistent
with the separation of functions
between generation and transmission.
1226. Some commenters also argue
that five years is incompatible with
retail procurement processes in some
states, such as Illinois and New Jersey,
which they assert limit power supply
741 In their replies, Entergy, MidAmerican, and
Progress Energy note many of these same concerns.
742 E.g., Alberta Intervenors, Alcoa, Ameren,
AMP-Ohio, Arkansas Municipal, AWEA, Dynegy
Reply, Eastern North Carolina, EPSA, Exelon,
Fayetteville, Manitoba Hydro, Morgan Stanley,
NCEMC, NRECA, MISO/PJM States, PJM, Powerex,
PPM, Reliant, TDU Systems, TransAlta, Williams,
and Wisconsin Electric.
743 E.g., Alcoa, AMP-Ohio, Arkansas Municipal,
AWEA, Eastern North Carolina, EPSA, Exelon,
Fayetteville, Manitoba Hydro, NCEMC, NRECA,
MISO/PJM States, Reliant, TDU Systems, and
Wisconsin Electric. TAPS also notes the difficulties,
particularly for small transmission-dependent
utilities, of locking in a five-year supply contract a
year in advance of rollover.
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agreements to three years.744 AWEA and
PPM suggest that the Commission
increase the minimum term to three
years, because five years is beyond the
term for many shorter-term power sales
transactions and it would be cost
prohibitive to lock up service for five
years. Manitoba Hydro suggests a twoto three-year minimum term and that
guaranteed redirects be permitted.
Constellation, while generally
supportive of a five-year minimum term,
would prefer a three-year minimum
term because it says three years is more
closely aligned with much of the
commercial activity in the energy
commodity markets. Wisconsin Electric
supports the current one-year term, but
proposes three years as an alternative. In
its reply, Duke indicates that it would
support a three-year minimum term for
rollover, but only if the notice period is
required to match project lead time.
1227. In their replies, several
commenters dispute the assertion that
customers may not be able to obtain
generation supplies for five-year
periods. They contend that generators in
a competitive market will have to offer
five-year contracts or risk losing their
sales if LSEs begin requesting five-year
contract terms in order to obtain
rollover rights.745 SPP states on reply
that it has not been its experience that
suppliers have refused to enter into
power supply agreements in excess of
three years. EEI also argues that, even if
a transmission customer has to accept
the risk that its term of service exceeds
the term of its power purchase in order
to obtain rollover rights, the cost of the
transmission service that is at risk is
small in comparison to the cost of the
power because the cost of transmission
service is only a small portion of the
delivered price of energy. EEI and
Bonneville also note in their replies that
unneeded transmission service can be
sold in the secondary market.
1228. NCEMC opposes the increase in
contract term because it would inhibit
the ability to pursue its prudent
portfolio approach to mitigate price
risks by providing for a mix of shorter
and longer-term power supply contracts.
If the Commission increases the
minimum term, NCEMC argues that all
existing rollover contracts should be
grandfathered. EPSA also believes that
existing one-year contracts should be
grandfathered, otherwise it argues that
market participants that relied on the
current policy will be harmed. In its
reply, EEI urges the Commission to
reject EPSA’s proposal that all currently
744 E.g., EPSA, Exelon, Reliant, and MISO/PJM
States.
745 E.g., EEI Reply and Southern Reply.
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12423
effective one-year power supply
contracts be grandfathered because, in
EEI’s view, it would interfere with good
utility planning. EEI also argues that
extending the minimum term to five
years does not abrogate a customer’s
power supply contract because
transmission and supply are unbundled
and, therefore, changing the terms of
transmission service does not interfere
with contract rights under power sales
agreements.
1229. Exelon argues that limiting
rollover rights to contracts that are five
years or greater will discriminate against
merchant generators that do not have
load linked to generation, lead to
stranded generation investments that
were based on the current rules, and
unfairly advantage local utilities
wanting to build their own generation as
opposed to seeking competitive
alternatives. Exelon suggests that an
approach similar to that utilized in PJM
be adopted, in which PJM evaluates new
requests for service that cannot be
granted without utilizing an existing
customer’s service by notifying the
existing customer and requiring it to
match the new request within thirty
days or release the service. PJM explains
further that its approach would allow
transmission customers two rollover
options: long-term service for less than
five years with no rollover right, or
service for one year with indefinite
rollover rights conditioned on either
future limitations or an agreement to
pay for necessary upgrades to maintain
the rollover. In its reply, TAPS opposes
the PJM approach stating that it would
invite discrimination by transmission
owners.
1230. Other commenters that oppose
the increase to five years assert that they
are already long-term customers that
simply take service year-to-year and
should therefore already be included in
planning, based on the fact that they are
either a generator or load and cannot
simply pick up and leave the system.746
Several other commenters likewise
oppose the increase to five years
because they do not believe that it will
result in an increase in long-term
contracting and planning as suggested
by the Commission.747 For example,
Williams notes that it currently has a
ten-year transmission contract and
argues that its transmission provider has
done nothing to improve the grid in its
area. TransAlta believes that a five-year
minimum contract term will limit
market participation to deep-pocketed
market participants who can afford long
746 e.g.,
747 e.g.,
Morgan Stanley and Manitoba Hydro.
Alberta Intervenors, TransAlta, and
Williams.
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contracts. TransAlta also believes that
the current option to contract for just
one year and obtain a rollover right is
often the benefit that prompts market
participants to buy yearly service
instead of shorter-term products and,
therefore, is an incentive to purchase
longer-term service. Alberta Intervenors
believe that a longer minimum term will
provide a disincentive for long-term
trading since the increased time
commitment of five years will
significantly increase the trading party’s
risk.748 The Organizations of MISO and
PJM States believe that the current
rollover policy generally results in an
increase in investment in transmission
and is only detrimental if service is
terminated and the capacity goes
unused.
Commission Determination
1231. The Commission finds that the
current rollover policy is no longer just,
reasonable, and not unduly
discriminatory. The rights and
obligations of a rollover customer
should bear a rational relationship to
the planning and construction
obligations imposed on the transmission
provider by the rollover rights. We find,
for the reasons explained below, that the
current policy no longer meets this
standard and that a five-year term will
ensure greater consistency between the
rights and obligations of customers and
the corresponding planning and
construction obligations of transmission
providers. We also believe that an
increase to a five-year term is consistent
with the native load protections
contained in new section 217 of the
FPA, primarily because requiring
longer-term agreements ensures that the
rollover right is used by transmission
customers with long-term obligations to
purchase capacity.749 Accordingly, the
Commission adopts a five-year
minimum contract term in order for a
customer to be eligible for a rollover
right. At the end of its initial five-year
contract term, a transmission customer
must, within the one-year notice period
(discussed more fully below), agree to
another five-year contract term or match
any longer-term competing request in
748 See
also Morgan Stanley.
EPAct 2005 sec. 1233(a) (to be codified at
section 217(b)(4) of the FPA, 16 U.S.C. 824q), which
provides that ‘‘[t]he Commission shall exercise the
authority of the Commission under [the FPA] in a
manner that facilitates the planning and expansion
of transmission facilities to meet the reasonable
needs of load-serving entities to satisfy the service
obligations of the load-serving entities, and enables
load-serving entities to secure firm transmission
rights (or equivalent tradable or financial rights) on
a long term basis for long term power supply
arrangements made, or planned, to meet such
needs.’’
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749 See
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order to be eligible for a subsequent
rollover.
1232. Our decision to adopt a fiveyear minimum term will remedy many
of the problems associated with the
current policy. Under our current
policy, a customer can secure
transmission service for one year and, in
so doing, require the transmission
provider to plan and upgrade its system
on the assumption the rollover right will
be continually renewed. For example, if
a transmission provider’s planning
horizon is 10 years, a one-year
reservation would require the
transmission provider to plan and
upgrade the system as if the customer
had purchased 10 years’ service (i.e.,
would exercise its rollover right every
year during that 10-year period).
Because of this, the customer receives a
guarantee of service beyond what it has
contracted to pay for and the
transmission provider must plan for
service that may not actually be used.
1233. By failing to link the customer’s
rights and obligations with those of the
transmission provider, the current
policy can have several detrimental
effects. For example, it requires the
transmission provider to plan and
construct facilities that may not be
necessary to serve load. Given the
difficulty of siting new transmission, it
is inappropriate to require transmission
providers to use finite resources to
finance and construct facilities that may
not be necessary. Additionally, the
current policy harms OATT customers
by allowing rollover customers to tie up
capacity that may be needed by other
customers. This is because the current
policy allows a rollover customer to
lock up existing capacity, regardless of
whether the rollover customer intends
to use that capacity. This reduces the
availability of existing capacity for other
customers and, in turn, reduces
competitive alternatives for customers.
1234. Some commenters have argued
that the Commission should use a
shorter period, such as three years, that
is more aligned with auctions in retail
access markets or existing commercial
practices. We disagree. The purpose of
our reform of the rollover rights policy
is to ensure that the rights and
obligations of the customer are better
aligned with the planning and
construction obligations of the
transmission provider. It is not to link
the term of the rollover right to any
particular commercial practice in any
particular region. We do not believe that
such a policy could be fairly
implemented in any event. Commercial
practices vary between the regions and
change over time, and it would therefore
be impractical to tailor the rollover
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rights in the OATT to the varying
commercial practices across the
country.
1235. We also do not believe that
adopting a five-year minimum term will
have an adverse effect on participation
in retail auctions that use three-year
solicitations. At the outset, we note that
retail auctions use solicitations of
varying length and, hence, the fact that
some states may use three-year auctions
does not provide a basis to establish a
generic standard for rollover rights
under the OATT. Some states use
shorter term auctions (e.g., one year)
and, as indicated, we cannot reasonably
tailor an OATT rollover obligation to the
varying commercial practices across the
country. We also do not believe that our
policy will have an adverse effect on
any such auctions. The winners in a
retail solicitation are determined anew
in each auction, based on the bids
submitted in that auction. A prospective
bidder therefore does not need a
‘‘rollover right’’ to compete in an
auction. It only needs transmission
service over the term of the solicitation
(e.g., three years). The fact that it may
not have an automatic right to
transmission capacity in the next
auction simply places it on the same
footing as any other bidder.
1236. In response to those
commenters who argue that
transmission customers making this
long-term commitment must also be
permitted to change their designated
resources and receipt points as their
power supply needs change, we believe
that such an approach is unworkable.
Allowing rollover customers to change
their designated resources and receipt
points in this manner would
inappropriately result in rollover
customers having priority over other
transmission customers in the queue
that may have already requested service
over a given transmission path. This
could result in substantial disruptions
to transmission service to higher-queued
customers requesting long-term service
over these paths.750 Moreover,
transmission customers are not
currently guaranteed the ability to turn
to other suppliers at other designated
resources and receipt points and,
therefore, we do not understand how
simply increasing the minimum
contract term to five years should
750 We agree with EEI that requiring transmission
providers to ensure rollover customers the ability to
change their designated resources and receipt
points without disrupting service to other
customers would, taken to its logical conclusion,
require transmission providers to construct the
transmission system with sufficient redundancy to
permit any customer to take service from any
resource.
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necessarily result in allowing
transmission customers this increased
flexibility. Likewise, we do not
understand why an increase in the
minimum contract term should result,
as argued by APPA, TAPS, and others,
in a transmission customer not having
to compete with other transmission
customers for firm capacity whenever
its contract comes up for renewal. As
discussed below, we will continue to
require transmission customers to match
competing requests for service as to
term and rate, ensuring that
transmission customers that value the
service the most receive it.
1237. We reject TAPS’ proposal to
exempt all small customers from the
five-year minimum, since this would
interfere with transmission providers’
ability to plan their systems to meet
their customers’ needs. As EEI points
out, the aggregated loads of several
small customers can have a substantial
impact on the system. We therefore
believe it would be inappropriate to
categorically exempt small customers.
We also reject TAPS’ proposal to
exempt all full and near-full
requirements customers, because it
would force transmission providers to
provide preferential service to certain
groups of customers. Additionally, we
reject TAPS’ proposal to allow
customers to exercise rollover rights
with only one-year contracts if there is
no competing request. Without a
competing request, a rollover right is not
necessary in order to continue service as
long as capacity remains available.
Additionally, allowing a rollover for a
one-year contract would continue to
impose planning and construction
obligations on the transmission provider
that bear no reasonable relation to the
rights and obligations of the rollover
rights customer. We further reject TDU
Systems’ proposal that transmission
providers demonstrate the availability of
long-term supplies before moving to a
five-year term. To do so would
effectively require transmission
providers to engage in the business of
procuring supplies for their
transmission customers, which is
clearly outside the scope of their
obligation to provide transmission
service, and could implicate Standards
of Conduct issues.
1238. We also reject the proposal of
EPSA and others that all currently
effective one-year power supply
contracts be grandfathered because this
would disrupt transmission planning.
For example, such an approach would
require that a large portion of existing
capacity be planned for on a
significantly different timeline than that
subject to the reformed rollover right.
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This also would detract from one of the
primary goals of rollover reform, which
is to improve transmission planning and
encourage longer-term contracting. As
discussed below, existing transmission
contracts will be permitted to roll over
under their existing terms until the first
such rollover opportunity following the
effectiveness of the reforms required by
this Final Rule.
1239. Lastly, we note that many of the
reforms adopted elsewhere in this Final
Rule will be beneficial to customers that
no longer receive rollover rights, as well
as to customers with rollover rights that
wish to use their rollover rights to turn
to alternative suppliers using different
transmission paths. First, greater
consistency and transparency in ATC
calculations will provide greater
assurance of nondiscriminatory access
to existing transmission capacity.
Second, our reforms relating to
conditional firm and redispatch service
will help to maximize the use of
existing capacity, consistent with
reliability, thereby providing customers
without rollover rights greater flexibility
to purchase existing transmission
capacity. Third, our clarifications
regarding our policy on redirects should
improve the ability of transmission
customers to redirect their service to
new receipt or delivery points. Fourth,
lifting the price cap on reassigned
transmission capacity should assist
transmission customers in reassigning
any capacity that may not be needed on
a given path because of a change in
suppliers that requires service over new
transmission paths. This will also
necessarily result in the unneeded
capacity being freed up for use by other
transmission customers, thereby further
assisting them in obtaining capacity that
they need to access alternative
suppliers. Lastly, and most importantly,
greater openness and coordination in
transmission planning should provide
all customers better information
regarding future resource options and
access to competitive alternatives. We
also believe that improved transmission
planning should help to address
allegations made by certain
transmission customers (e.g., Williams)
that even though they have signed up
for ten years of service, they have not
seen their needs planned for adequately.
b. One-Year Notice Provision
Comments
1240. Many commenters support an
increase in the notice period to one year
or some other greater time period.751
751 E.g., Ameren, Barrick Reply, Bonneville,
Community Power Alliance, Constellation,
Dominion, Duke, East Texas Cooperatives, EEI,
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12425
Most support the increase based on the
argument that the current 60-day notice
period makes it very difficult to plan the
system, because transmission providers
often do not know until 60 days before
the end of a contract whether a
transmission customer will roll over its
service, resulting in potential
overbuilding of the system (e.g., because
a transmission provider must plan its
system assuming a transmission
customer will roll over but sometimes it
does not). They also argue that it is
difficult to re-market capacity in only 60
days if rollover is not sought and that
potential transmission customers are
often unnecessarily turned away
because transmission providers are
unaware of the availability of capacity
until 60 days before the end of a
contract subject to a rollover right. In
general, these commenters view a oneyear notice period as an improvement.
However, many of these same
commenters do not believe one-year
notice is appropriate if the transmission
provider must construct facilities to
accommodate a rollover and, therefore,
the notice should instead be tied to the
start date for any necessary upgrades.752
1241. EEI, for example, believes that
notice should be tied to the start date of
any necessary transmission upgrades,
because the transmission provider may
be left with stranded transmission
capacity if it must begin construction on
upgrades necessary to accommodate a
rollover before the transmission
customer has even indicated whether it
will in fact seek a rollover. EEI also
argues that a competing customer could
be required to pay an incremental rate
for network upgrades that could have
been avoided if the rollover customer
had provided earlier notice of its
intention not to seek a rollover. EEI
further contends that some state
commissions will not allow upgrades
where there is only the potential for a
rollover. Finally, EEI states that a oneyear notice period does not ensure that
the transmission provider will be able to
re-market the capacity, forcing other
E.ON, Entegra, Entergy, FirstEnergy, Great
Northern, Imperial, LDWP, LPPC, MidAmerican,
MISO, MISO Transmission Owners, Nevada
Commission, Nevada Companies, North Carolina
Commission Reply, NorthWestern, Northwest IOUs,
NRECA, PGP, Pinnacle, PNM–TNMP, Progress
Energy, Public Power Council, Salt River, Santa
Clara, Southern, South Carolina E&G, SPP, Tacoma,
TranServ, TVA, Utah Municipals, and Xcel. Both
APPA and TAPS support a one-year notice
provision, but only on the condition that the
clarifications and modifications they suggest are
made.
752 E.g., Barrick Reply, Duke, EEI, Entergy,
Indianapolis Power Reply, LPPC, Nevada
Commission, Nevada Companies, Pinnacle,
Progress Energy, South Carolina E&G Reply,
Southern, and TVA.
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transmission customers to bear the
increased costs associated with the
newly constructed transmission
facilities. EEI proposes that a date be
included in the initial service agreement
by which the transmission customer
must exercise its rollover rights if
upgrades are needed to accommodate
the rollover. If there is a pre-confirmed
competing request or newly projected
growth in native load, EEI suggests that
the rollover customer must exercise its
rollover and match by the later of the
project start date for any new
transmission facilities needed or 60
days after the transmission provider
notifies the transmission customer of
the competing request.753 Additionally,
if more than one-year notice is required
because of the need for upgrades, EEI
proposes that the transmission provider
be required to notify the transmission
customer if subsequent events delay the
project start date, in which case the
notice period would be revised. EEI
asserts that any disputes can be dealt
with by protesting the filing of an
unexecuted agreement. EEI stresses that
better, more inclusive planning, and
more transparent ATC calculations, will
provide transmission customers with
greater assurances that project start
dates are accurate.
1242. Southern suggests that partial
rollover be permitted if notice is not
given in time for construction of an
upgrade needed to provide full service.
Duke, Nevada Commission, and
Southern suggest that providing for oneyear notice without a link to the start
date for any upgrades falls short of the
native load protections found in section
217 of the FPA. As an alternative, the
Nevada Commission suggests tying the
notice requirement to the amount of
capacity subject to rollover, i.e., below
a certain threshold, one year would be
deemed per se sufficient.
1243. APPA argues in reply that many
customers may not know even one year
in advance if they will have firm power
supplies under contract that would
enable them to roll over their
corresponding firm transmission
agreement and, therefore, requiring
them to exercise their rollover rights
even earlier in the contract term would
only exacerbate an already impossible
situation. In their replies, NRECA,
TAPS, TDU Systems, and Utah
Municipals urge the Commission to
reject the recommendation that notice
periods be expanded to be
commensurate with construction lead
753 Ameren,
Pinnacle, Southern, and TranServ
agree that the submission of a competing request
should trigger an accelerated timeline for the
original customer to exercise or release its rollover
rights.
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times. They argue, among other things,
that LSE transmission customers need a
reasonable amount of certainty so that
they may plan their power supply
arrangements without fear that they may
become unraveled due to unforeseeable
circumstances. Utah Municipals also
assert that the proffered justification for
the proposal—to prevent overbuilding—
is questionable at best as even the
current policy which requires only a
one-year contract minimum for rollover
and 60-days notice has not resulted in
wasteful overbuilding of the system.
TDU Systems also point out that under
section 28.2 of the pro forma OATT,
transmission providers should be
planning and expanding their systems
to accommodate their network
customers’ current and future needs.
1244. The one-year notice provision is
opposed by several commenters, who
argue that having to give one-year notice
constitutes an undue burden.754 In
general, these commenters argue that
under current market conditions,
transmission customers do not typically
renew supply contracts one year in
advance of expiration.755 Alberta
Intervenors argue that a one-year notice
provision does not aid in re-marketing
capacity, as any unused long-term firm
service is already re-marketed as shortterm firm or non-firm service. Alberta
Intervenors also argue that the increased
lead time increases risk and creates
uncertainty making it less likely that
customers will enter into long-term
contracts. EPSA and Exelon suggest a
flexible notice rule that depends on the
length of the underlying contract or
requiring more than 60-days notice if
there is insufficient capacity for a new
long-term firm transmission service
request, as is done in PJM. They also
suggest PJM’s approach whereby a
transmission customer must inform PJM
whether it will roll over within thirty
days of being notified of a competing
request. PPM and Wisconsin Electric
suggest a six-month notice period,
which complements their alternative
suggestion of a three-year minimum
contract term.
Commission Determination
1245. The Commission finds that the
current 60-day notice period should be
modified to reflect the longer term (five
years) of the rollover rights. Currently,
a customer with a one-year rollover
right has 60 days to provide notice of
whether it intends to rollover its
754 E.g., Alberta Intervenors, Alcoa, Arkansas
Municipal, EPSA, Exelon, Manitoba Hydro, Morgan
Stanley, PPM, TransAlta, Williams, and Wisconsin
Electric.
755 E.g., Arkansas Municipal, Williams, and
Wisconsin Electric.
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capacity. This 60-day period was
reasonable for a rollover right of short
duration (one year), but it is no longer
reasonable for a rollover right with a
minimum five-year term.
1246. In selecting a new notice
period, the Commission has attempted
to balance the circumstances faced by
customers in renewing power supply
contracts and the interests of
transmission providers in attempting to
plan their system. The Commission
recognizes that no single notice period
can perfectly balance these
considerations, but chooses the one-year
notice period as most appropriate under
the circumstances. Given that the
minimum rollover term has been
lengthened to five years, it is reasonable
to expect that customers will consider
renewing such long term obligations in
advance of 60 days prior to the
expiration of their current obligation.
We do not believe it is reasonable to
fashion our notice period for customers
that wait until the last minute to
evaluate whether to extend their longterm contracts.
1247. Many transmission providers
argue that a one-year notice period is
too short because it is not consistent
with the transmission provider’s
planning horizon. We disagree. The
Commission is extending the minimum
term for rollover rights to five years to
ensure greater consistency between the
customer’s rights and obligations and
the planning and construction
obligations of the transmission provider.
We believe that this modification
satisfies the principal concerns of
transmission providers regarding the
current policy on rollover rights. We
recognize that a one-year notice period
is shorter than the typical planning
horizon, but we decline to extend the
notice period to a time that coincides
with the typical planning horizon or the
time it takes to construct new facilities.
Doing so would effectively eliminate
rollover rights altogether, given that the
resulting notice period could be threeto-five years. We do not believe it is
reasonable to expect customers to have
decided on new sources of supply three
years in advance of the expiration of
their current contracts. We therefore
find that a one-year notice period most
appropriately balances the interests of
customers and transmission providers.
c. Matching and Rollover Restrictions
Based On Native and Network Load
Growth
Comments
1248. As noted above, the
Commission proposed to maintain the
requirement that an existing rollover
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transmission customer match competing
offers as to term and rate. Some
commenters argue that a competing
customer be required to execute a
contingent service agreement that
becomes effective if the rollover
customer does not match.756 Given the
increase in the minimum contract term
to five years in order to be eligible for
a rollover right, TAPS argues that
matching must be structured to
recognize that a network customer must
extend its power supply by at lease five
years as well, in order to match a
competing point-to-point customer that
can simply extend its reservation. To
ensure that network customers are not
disadvantaged by matching, TAPS
suggests that the Commission restrict
reservations qualified to compete
against a network customer’s reservation
to customers with long-term power
contracts, so they are on more equal
footing with network customers. TAPS
also proposes a cut-off for requests with
which the network customer will need
to compete, such as three months prior
to when the network customer exercises
its rollover right, so that the network
customer can structure its power supply
commitments with some degree of
advance knowledge of the competing
requests. In its reply, Bonneville
suggests allowing network transmission
customers to compete based on the
duration of their network transmission
service request rather than on the
duration of their resource commitments.
As such, the transmission provider
would assume that existing designated
resources would continue to be used
after the rollover unless informed
otherwise.
1249. The Commission also discussed
in the NOPR whether native load
restrictions should be reevaluated with
each rollover and, if so, whether native
load should then be required to compete
with rollover customers for the capacity.
Several commenters argue that a
transmission provider’s native and
network loads should not be forced to
compete with other transmission
customers, as opposed to allowing the
transmission provider to continue to
reserve capacity for its native and
network load at the time of granting a
rollover.757 Most also stress that
requiring a transmission provider to
compete would violate the native load
protections in section 217 of the FPA.
LDWP contends that there should be no
limitation on a transmission provider’s
756 E.g.,
MidAmerican and Powerex.
757 E.g., Allegheny, Entergy, FirstEnergy,
Imperial, Nevada Companies, Progress Energy, Salt
River, Santa Clara, and Seattle.
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right to recall capacity based on revised
forecasts of native load growth.
1250. APPA contends on reply that
transmission customers could find it
very difficult to line up a new firm
power supply of a term long enough to
match the power supply arrangements
of its vertically-integrated investorowned transmission provider (which is
likely to have owned, rate-based
generation in its power supply portfolio
and, therefore, could agree to a very
long-term transmission agreement). TDU
Systems argue that transmission
providers should be forced to compete
for capacity and that this is, in fact,
required by section 217 of the FPA, as
the native load preference does not
distinguish between the retail native
loads of transmission providers and the
native loads of other LSEs dependent on
their systems. Powerex and PPM also
support requiring transmission
providers to compete. NorthWestern
and Southern support requiring
transmission providers to compete, but
only when a restriction is not included
in the original agreement. APPA also
notes in its reply comments that, if
Southern included LSEs’ loads in its
transmission planning and construction
program along with its own native load,
there would be no need to reclaim the
LSEs’ capacity at the close of the initial
contract term or the renewal terms.
1251. Several commenters also
addressed the Commission’s request for
comment on whether there is a
sufficiently clear, consistent, and
transparent method that could be
implemented on a generic basis to
address the need for a transmission
provider to demonstrate its forecast of
native load growth and its effect on
capacity reserved by rollover customers.
Many of these commenters support the
development of a clear and transparent
method for demonstrating native load
growth.758 Some commenters point to
the need for accurate and transparent
ATC calculations to aid in this
process.759 If the transmission
provider’s calculation of ATC is
consistent with the requirements the
Commission adopts in this proceeding
yet there is insufficient capacity to
accommodate the customer’s rollover,
EEI recommends that the provider may
include in the service agreement a
limitation of rollover rights. AWEA
recommends that transmission
providers adopt the same transparent
and consistent methods used to
758 E.g., AWEA, Duke, EEI, Entergy, EPSA,
Imperial, Nevada Commission, Powerex, Salt River,
Seattle, South Carolina E&G, Southern, SPP Reply,
and TAPS.
759 E.g., AWEA, EEI, EPSA, and MISO.
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Fmt 4701
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12427
compute the Existing Transmission
Capacity component of ATC to develop
native load growth reservations that
support rollover restrictions. AWEA,
NorthWestern, and TAPS suggest
posting forecast information on the
OASIS, and TAPS goes on to stress that
this information should be included in
state planning documents as well as the
transmission provider’s coordinated and
regional planning process. EPSA
stresses that native load capacity must
follow native load and not only be made
available for the transmission provider
and its affiliates. EPSA believes this is
required by the native load protections
found in FPA section 217.
1252. Duke asks the Commission to
address the possibility that capacity
subject to a rollover right might be
needed to serve native load outside of
the ten-year planning horizon. The
Nevada Commission and Southern
suggest that the Commission give
deference to state resource planning
processes in attempting to verify native
load growth forecasts. Southern also
asks that the Commission clarify that
rollover rights can be restricted based on
rollover rights belonging to higherqueued transmission customers. If
transmission studies show no problems
without the presence of a rollover, but
then problems are identified with the
rollover included, Southern contends
that placing a corresponding limitation
in the service agreement would be
appropriate. Pinnacle requests
clarification that when rollover rights
are restricted based on native load
growth, the transmission customer must
pay for upgrades to continue its service.
1253. Several commenters also
suggest that transmission providers
should be permitted to evaluate rollover
restrictions at the time of each
rollover.760 These commenters argue
that it is impossible to identify all
potential limitations upfront as system
conditions change in unforeseeable
ways (e.g., fluctuations in fuel prices
can change dispatch decisions). They
also argue that allowing a re-evaluation
is consistent with the native load
protections in FPA section 217.
1254. In its reply, TAPS argues that a
transmission provider should not be
permitted to avoid its planning and
expansion obligations by treating load
growth not anticipated and documented
in the original service agreement as a
competing request to be matched. TAPS
points out that section 217 of the FPA
treats all LSEs—whether they are
transmission providers or transmissiondependent utilities—the same, without
760 E.g., Nevada Companies, South Carolina E&G,
and Southern.
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distinction, and therefore provides no
basis to allow one LSE to claim
transmission rights currently used by
another LSE.761 Lastly, TAPS argues
that when a provider is reclaiming
capacity for load growth reserved in the
initial service agreement, rollover
customers should be allowed to match
the request, thereby imposing an
additional requirement on the provider.
Commission Determination
1255. The Commission will not adopt
any changes to its matching policies at
this time. At the time of rollover of their
contracts, transmission customers will
continue to be required to match
competing requests for service as to
term and rate in order to roll over their
service. This preserves the current
policy goal of providing a mechanism
for awarding capacity to those who
value it most, as well as providing for
a tie-breaking mechanism when needed
that gives priority to existing customers
so that they may continue to receive
transmission service.762 Absent the
requirement that the customer match
the contract term of a competing
request, transmission providers could be
forced to enter into shorter-term
arrangements that could be detrimental
from both an operational standpoint
(i.e., system planning) and a financial
standpoint.763 We clarify, however, that
transmission customers must also enter
into a transmission contract of at least
five years in order to obtain a
subsequent rollover right in the absence
of a competing request for a longer term.
1256. The Commission will continue
to require rollover restrictions based on
reasonable forecasts of native load
growth or preexisting contracts that
commence in the future to be included
in the initial transmission service
agreement. This will remain the only
appropriate way to restrict a rollover
right. We also will continue to evaluate
a transmission provider’s native load
growth forecasts on a case-by-case basis,
as no commenter has provided us with
a sufficiently clear, consistent, and
transparent method that could be
implemented on a generic basis that
ensures that the demonstration of native
load growth is accurate and is tied to a
need for the specific capacity reserved
by a rollover customer.764 Because we
will continue to require rollover
761 See
sroberts on PROD1PC70 with RULES
762 See
also APPA Reply and TDU Systems Reply.
Order No. 888–A at 30,197.
763 Id.
764 While the Commission has not to date
accepted any native load growth showing made by
a transmission provider, it has recently set for
hearing several such showings. See, e.g., Southern
Co. Servs., Inc., 116 FERC ¶ 61,050 (2006); Nevada
Power Co., 116 FERC ¶ 61,093 (2006).
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restrictions to be included in the initial
transmission service agreement, we
necessarily reject the suggestion that
transmission providers be permitted to
restudy for rollover restrictions at the
time of each rollover. Accordingly, it is
unnecessary for us to address whether it
would be appropriate for a transmission
provider’s native or network load to
compete with a rollover customer if a
new study at the time of the rollover
indicated a native or network need for
the capacity.
1257. In response to the suggestions of
some commenters, we believe that
consideration should be given in our
case-by-case evaluations of native load
growth forecasts to state-approved
integrated resource plans that show a
native load need for the capacity.765
Moreover, we believe that the ATC and
planning reforms that we are adopting
in this Final Rule will provide greater
transparency and assurance that
transmission providers’ forecasts of
native load growth are accurate. We
emphasize that we expect the forecasts
utilized in transmission planning to be
consistent with the forecasts utilized to
support a rollover restriction. Lastly, the
coordinated and regional planning
process required by this Final Rule is
designed to improve the availability of
transmission service by, among other
things, increasing transparency and
providing customers a meaningful
opportunity to participate in the
planning process. Accordingly, we
believe that improved planning should
help to reduce the need to restrict
rollovers in the future.
d. Other Issues
Comments
1258. A number of comments relate to
the applicability of the rollover-related
reforms to RTOs and ISOs. CAISO asks
the Commission to confirm that the
rollover reforms do not apply to CAISO
as its current tariff does not have such
a provision and rollover is, in fact,
incompatible with CAISO’s
transmission service model.
Sacramento, however, asks the
Commission to clarify that rollover
rights apply to long-term firm service
provided by RTOs and ISOs under
Order No. 681 under what it terms the
‘‘as good as or superior to’’ standard.766
765 We note that this is consistent with the
Commission’s evaluation of rollover restrictions
proposed by transmission providers in the past.
See, e.g., Nevada Power Co., 97 FERC ¶ 61,324 at
62,493 n.17 (2001).
766 In its reply, CAISO argues that this request to
expand the requirements of Order No. 681 is
inappropriate both because the Commission and
courts have already recognized that rollover rights
under the pro forma OATT do not apply to entities
PO 00000
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Organization of MISO and PJM States
assert that any changes for RTOs should
be made through the stakeholder
process. In its reply, Williams opposes
permitting RTO stakeholders to
determine changes in rollover rights
policy in RTO regions, as it would result
in disparate rules and practices and
increased opportunities for
discrimination, and therefore, the
Commission should adopt a single
policy applicable to all rollover rights.
1259. Other commenters raise
different discrete issues. Morgan Stanley
asks the Commission to amend pro
forma OATT section 2.2 to include
existing policy determinations with
respect to the manner in which a
transmission provider can curtail or,
alternatively, must honor and
accommodate rollover requests. Duke
asks the Commission to abandon its
existing policy prohibiting the
restriction of rollover rights based on
the potential exercise of other
customers’ rollover rights. Salt River
asks the Commission to clarify that the
proposal to extend the minimum term to
five years does not change the definition
in section 1.20 of the pro forma OATT
that one year constitutes a long-term
contract. AWEA, Constellation, and
EPSA ask the Commission to allow
transmission customers to waive their
rollover rights.
Commission Determination
1260. As we explain in section IV.C
above, RTOs and ISOs must submit a
filing showing that their practices are
consistent with or superior to the
modifications made in the Final Rule.
This does not necessarily mean that
entities such as CAISO must create
rollover rights if they do not have them
already. Arguments regarding the
applicability of rollover reform may be
raised pursuant to the process described
in section IV.C. We also clarify that our
decision to extend the minimum term to
five years does not change the definition
in section 1.20 of the pro forma OATT
that one year constitutes a long-term
contract. Commenters have not offered
sufficient justification for further
clarifications to our rollover policies or
amendments to section 2.2 at this time.
e. Effectiveness Upon Acceptance of
Coordinated and Regional Planning
Process and Transition
Comments
1261. Several transmission customers
and other commenters support a linkage
like CAISO that do not offer traditional Order No.
888 network and point-to-point transmission
services and because the Commission has already
rejected such a requirement in Order No. 681 itself.
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between rollover reform and planning,
but do not support making rollover
reforms effective upon acceptance of a
transmission provider’s coordinated and
regional planning process, but rather on
successful implementation of that
process.767 While both TAPS and TDU
Systems support the link to planning
generally, TAPS goes further and
advocates holding transmission
providers accountable for failing to plan
and construct facilities needed to meet
transmission customer needs. TDU
Systems point out that the linkage to
planning does not remedy concerns that
the current market does not generally
provide for five-year supply contracts.
1262. Some commenters, however,
oppose linking the effectiveness of
rollover reform to planning, arguing that
rollover reform is needed as quickly as
possible.768 For example, Duke, Progress
Energy, and Southern argue that FPA
section 217 provides no indication that
the native and network load protections
inherent in rollover reform should be
subject to conditions such as waiting for
the Commission to accept a planning
process. Moreover, Duke argues that
developing a planning process will be
time-consuming and that holding
rollover reform hostage to it could
motivate stakeholders with contracts
shorter than five years to endlessly try
to convince the Commission to delay
acceptance of a transmission provider’s
planning process.
1263. Some commenters contend that
linking planning and rollover reform
will create differences in tariffs, with
each transmission provider having a
different effective date for rollover
reforms.769 MISO argues in its reply that
the Commission should clarify in the
Final Rule that its requirement that the
new policy becomes effective upon
acceptance of the transmission
provider’s coordinated and regional
planning process is already met in
regions where RTOs or ISOs provide
service, as they already have
Commission-approved regional
transmission planning mechanisms in
place. Bonneville argues in its reply for
a consistent implementation date across
all transmission providers so as to avoid
another degree of complexity for
customers requiring rollover capacity
across multiple transmission providers’
systems.
767 E.g., AWEA, Constellation, EPSA, Exelon,
PGP, and PPM.
768 E.g., Bonneville, Duke, EEI Reply, North
Carolina Commission Reply, Northwest IOUs,
PNM–TNMP Reply, Progress Energy, Public Power
Council, South Carolina E&G Reply, and Southern.
769 E.g., Northwest IOUs, Duke Reply and EEI
Reply.
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1264. As for the transition period
proposed in the NOPR, a variety of
commenters point out that, depending
on the status of any given contract,
making the one-year notice provision
effective on acceptance of a
transmission provider’s planning
process could leave some transmission
customers unable to provide one-year
notice if there is less than one year
remaining on their contracts.770
FirstEnergy, Exelon, Great Northern,
and TAPS emphasize that existing
transmission customers should be
permitted one more rollover under the
current rules, because the parties to
such agreements have relied on the
current rules in meeting their
transmission needs. APPA and TAPS
point out that transmission customers
will need a sufficient amount of time to
secure five-year power agreements to
meet the new requirements. AWEA
argues generally for a transition period
during which existing customers can
maintain or relinquish their existing
rollover rights under current rules and
become subject to new requirements
only at the end of the transition period.
Commission Determination
1265. The Commission adopts the
NOPR proposal to make rollover reform
effective at the time of acceptance by the
Commission of a transmission
provider’s coordinated and regional
planning process also required by this
Final Rule. We believe that rollover
reform and transmission planning are
closely related, because according to our
longstanding policy, transmission
service eligible for a rollover right must
be set aside for rollover customers and
included in transmission planning. We
believe that it is necessary that reforms
in both areas proceed together, and
therefore, we reject the suggestion of
some commenters that rollover reform
proceed independent of transmission
planning reform. We understand that
our approach may result in differences
in transmission providers’ OATTs, with
some having a different effective date
for rollover reforms. However, because
the effectiveness of rollover reform will
be tied to acceptance of a transmission
provider’s coordinated and regional
transmission planning process, rollover
reforms in any given region generally
should be effective within the same time
period.
1266. We reject the arguments by
some commenters that rollover reform
be made effective upon the ‘‘successful’’
implementation, as opposed to
acceptance by the Commission, of a
770 E.g., APPA, FirstEnergy, Northwest IOUs, PGP,
and Public Power Council.
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transmission provider’s coordinated and
regional planning process. We believe
that utilizing a subjective deadline, such
as the successful implementation of the
planning process, could result in
significant confusion in the industry as
to when rollover reforms should be
effective. Furthermore, an existing filed
and accepted transmission planning
process, such as those that may be on
file for RTOs and ISOs, does not trigger
the effectiveness of rollover reform for
transmission providers using the
process. Such RTOs and ISOs and their
transmission-owning members must, as
discussed elsewhere in this Final Rule,
comply with the planning reforms
required by the Final Rule through the
compliance filing procedures identified
in section IV.C. It is Commission
acceptance of these compliance filings
that will trigger effectiveness of rollover
reform for these transmission providers,
assuming rollover reform is applicable
to their tariff services in the first
instance.
1267. In response to commenters’
concerns that, depending on the
effective date of rollover reform, certain
customers may not have a year or more
left on their contracts such that they can
comply with the one-year notice
provision, we emphasize that existing
contracts with a rollover right at the
time of effectiveness of rollover reform
may exercise their next rollover based
on the existing notice rules. It is only a
rollover contract entered into or
renewed after the effectiveness of
rollover reform that must comply with
the new rollover provisions, including
the one-year notice requirement.
4. Modification of Receipt or Delivery
Points
1268. Section 22 of the pro forma
OATT provides that a transmission
customer taking firm point-to-point
service may modify its receipt and
delivery points, i.e., redirect its service,
on either a non-firm or a firm basis.
Section 22.1 (Modifications on a NonFirm Basis) provides that, subject to
certain conditions, a firm point-to-point
customer may request transmission
service on a non-firm basis over receipt
and delivery points other than those
specified in its service agreement
(known as secondary receipt and
delivery points) in amounts not to
exceed its firm capacity reservation,
without incurring an additional nonfirm point-to-point service charge or
executing a new service agreement.
Section 22.2 (Modifications on a Firm
Basis) provides that any request to
modify receipt and delivery points on a
firm basis shall be treated as a new
request for service in accordance with
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section 17 of the pro forma OATT
(Procedures for Arranging Firm Point-toPoint Transmission Service), except that
the transmission customer shall not be
obligated to pay any additional deposit
if the capacity reservation does not
exceed the amount reserved in the
existing service agreement. While such
new request is pending, the
transmission customer retains its
priority for service at the existing firm
receipt and delivery points specified in
its service agreement.
1269. In Order No. 676, the
Commission adopted the ‘‘Standards for
Business Practices and Communication
Protocols for Public Utilities’’ developed
by the NAESB’s Wholesale Electric
Quadrant (WEQ).771 Order No. 676
incorporated the aforementioned
standards by reference into the
Commission’s regulations, required
public utilities to implement the
standards by July 1, 2006, and required
public utilities to file revisions to their
OATTs to include these standards.772
The WEQ Standards include a number
of standards addressing requirements
for dealing with redirects on both a firm
and non-firm basis.773 All of the WEQ
Standards dealing with redirects were
adopted by the Commission in Order
No. 676, except for WEQ Standard 001–
9.7, which addresses the impact of a
firm redirect on a long-term firm
transmission customer’s rollover rights
under section 2.2 of the pro forma
OATT. The Commission directed the
WEQ to reconsider WEQ Standard 001–
9.7 and to adopt a revised standard
consistent with the Commission’s
policies.774 The Commission also
offered guidance to assist the WEQ in
developing a standard that is consistent
with Commission policy.775
NOPR Proposal
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1270. In response to the NOI,
commenters raised various concerns
regarding redirects. Among other things,
771 The WEQ was established by NAESB in
response to a Commission order requesting the
wholesale electric power industry to develop
business practice standards and communication
protocols by establishing a single consensus,
industry-wide standards organization for the
wholesale electric industry. See Order No. 676 at
P 3–4.
772 The standards will hereinafter be referred to
as the WEQ Standards. The Commission adds a
reference to the WEQ Standards in section 4 of the
pro forma OATT, which identifies the
Commission’s regulations containing the terms and
conditions relevant to the OASIS and standards of
conduct.
773 The requirements for dealing with redirects on
a firm basis are found at WEQ Standard 001–9, et
seq., and the requirements for dealing with redirects
on a non-firm basis are found at 001–10, et seq.
774 Order No. 676 at P 52.
775 Id. at P 53–61.
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customers complained of difficulties
obtaining redirected service, while
transmission providers complained of a
lack of clarity in the rules governing
redirects. In the NOPR, the Commission
stated its belief that a number of these
concerns appeared to have been
resolved by the adoption of the WEQ
Standards in Order No. 676, which was
issued after the NOI. The Commission
sought comment on whether parties
believed the WEQ Standards in fact
addressed those concerns adequately.
1271. The Commission also stated its
expectation that a number of other
concerns raised in response to the NOI,
while perhaps not yet addressed (or
addressed fully) by a WEQ Standard, are
nevertheless the types of issues that are
appropriate for the WEQ process. The
Commission therefore proposed that
each commenter that continued to
believe additional reform is necessary
with regard to redirects evaluate
whether its concerns would more
appropriately be addressed by the WEQ
as it considers its next version of its
standards.776 The Commission noted
that WEQ was in the process of
reevaluating WEQ Standard 001–9.7,
dealing with redirects and rollovers, so
that it is consistent with the
Commission’s guidance given in Order
No. 676. The Commission requested
comment on whether the WEQ process,
along with the guidance provided by the
Commission in Order No. 676, is
sufficient to address the concerns of
commenters that seek clarification on
the interplay between redirects and
rollovers.
1272. In the NOPR, the Commission
acknowledged that there were
additional, more fundamental concerns
with regard to section 22 raised in
response to the NOI. Customers
generally argued that their ability to
redirect to new points is stymied by a
lack of ATC at the new points or the
need for major upgrades, or that
transmission providers take too long to
process the redirect request.
Transmission providers, on the other
hand, complained of the administrative
burdens and complexity (particularly
with regard to reliability) of processing
transmission customers’ short-term
changes in service and that there is
often not enough time for the market to
respond to capacity made available on
776 The Commission noted in this regard that the
WEQ’s procedures ensure that all industry members
can have input into the development of a business
practice standard, whether or not they are members
of NAESB, and each standard it adopts is supported
by a consensus of the five industry segments:
transmission, generation, marketers/brokers,
distribution/load-serving entities, and end-users.
See Order No. 676 at P 5 & n.5.
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a customer’s original path. The
Commission stated its belief that other
proposed reforms in the areas of
process, transmission planning, and
ATC calculation should address
transmission customer concerns
regarding redirects. The Commission
encouraged interested parties to submit
a specific proposal, along with proposed
revised pro forma OATT language, to
the extent they believe the proposed
reforms will not adequately address
their concerns.
1273. The Commission also noted in
the NOPR that several transmission
providers had posted business practices
that allow network customers either to
substitute an off-system non-designated
resource for a designated resource or to
redirect the point of receipt associated
with an existing network resource. The
Commission proposed that network
customers not be permitted to redirect
network transmission service because
network service involves no identified
contract path and therefore should not
be treated as a directable service.
a. Proposed Reliance on WEQ Process
and Other OATT Reforms
Comments
1274. Commenters generally agree
with the Commission that issues with
respect to redirects of firm and non-firm
transmission service are best addressed
through the WEQ as established by
NAESB, in accordance with Order No.
676 and the WEQ process for creating
new standards.777 Seattle argues that the
NAESB standard setting process has
worked well thus far and, as a result,
other redirect issues should be first
referred to NAESB as a standard-setting
request. MISO states that it has serious
concerns with the WEQ process and the
Commission’s unwarranted deference to
NAESB to develop what will become
binding business standards and
practices.
1275. Nevada Companies recommend
the following improvements for the
NAESB process: use of a professional
facilitator to keep discussions focused
and moving; and mandatory surveys
breaking down the sections on proposed
NAESB standards after the first round of
comments are received to determine if
consensus exists on the proposed
standards, since it appears that there are
relatively few participants at NAESB
meetings where standards are being
drafted and relatively few commenters
on those draft standards.
1276. Several commenters state that
they agree with the Commission’s
proposal to rely on other proposed
777 E.g., EEI, Imperial, NorthWestern, Southern,
and Suez Energy NA.
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reforms in the NOPR to resolve the
remaining redirect issues.778 Seattle
generally agrees that the reforms
proposed in the NOPR should improve
the ability to assign and use
transmission on a firm basis. EEI and
NorthWestern state that the NOPR
proposal to increase transparency in the
calculation of ATC should assist
transmission customers in both
selecting transmission paths that may be
available for redirect and understanding
why certain paths cannot accommodate
redirect transactions.
Commission Determination
1277. The Commission concludes that
the proposed method for addressing
remaining concerns with redirects—i.e.,
relying on other reforms adopted in this
Final Rule and in the Order No. 676
proceeding—is adequate to ensure that
transmission providers do not engage in
undue discrimination when a customer
seeks to modify its receipt and delivery
points on a firm basis. As explained
throughout this Final Rule, the reforms
adopted herein address the remaining
opportunities for undue discrimination.
Planning and ATC reforms will give
transmission customers more accurate
and complete ATC information when
evaluating their redirect options.
Increased transparency will give
transmission customers the information
they need to evaluate a transmission
provider’s denial of a request to redirect.
Modifications to the process for
requesting and securing firm point-topoint service will improve the ability to
redirect transmission service to new
points pursuant to section 22 and
ensure complete and timely responses
from transmission providers. The
Commission therefore concludes that no
further reforms specific to redirects are
necessary at this time.
1278. The Commission also concludes
that the NAESB WEQ is the appropriate
standard-setting body for developing
business practices and implementing
the Commission’s redirect policy. The
Commission will refrain from
commenting here on the NAESB process
itself because we believe that the
industry is best situated to determine
how to structure the standard-setting
process to provide for the widest
possible participation and consensus.
We nevertheless clarify that, consistent
with precedent, NAESB is charged with
implementing Commission policy
through business practices.779 The
Commission finds that the NAESB WEQ
778 E.g.,
EEI, NorthWestern, and Seattle.
Standards for Business Practices of
Interstate Natural Gas Pipelines, Order No. 587–N,
FERC Stats. & Regs. ¶ 31,125 at P 23 (2002).
779 See
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is an acceptable standards development
process, representing a cooperative
effort by industry participants to
develop business practices that enhance
the efficiency of the electric grid.780
Where necessary, NAESB participants
may seek clarification of Commission
policy so that NAESB may develop the
appropriate standards.
b. Redirects and Rollovers Rights
Comments
1279. Regarding the interaction
between redirects and rollovers, some
commenters request that the
Commission clarify what they view as
an inconsistency between Order No.
676, the Commission’s existing pro
forma OATT, and the rollover proposal
in the NOPR. Specifically, Bonneville,
MISO, and Southern argue that, contrary
to the pro forma OATT and NOPR,
Order No. 676 improperly suggested in
an example that a short-term redirect of
a long-term service agreement gives the
customer rollover rights for the new
path. TranServ supports placing the
following two conditions on the receipt
of rollover rights for redirects: a redirect
on a firm basis must be for one year or
longer, and the redirect must be for the
entire remaining term of the parent
(original) request.781 If these conditions
are met, TranServ contends that the
customer will be granted rollover rights
on the redirect path and lose the
rollover rights held on the original path.
If the customer wishes to retain rollover
rights on the original path, TranServ
continues, it will have the option to
submit multiple redirect requests of less
than one year in duration for the term
desired. With respect to WEQ Standard
001.9.7, MISO incorporates by reference
its opposition to the Commission’s
adoption of the proposed transfer of
rollover rights on the redirected path in
its request for rehearing of Order No.
676. There MISO argued that there
should be no rollover rights on a
redirect path and that the guidance in
Order No. 676 requiring the
transmission provider ‘‘to offer rollover
rights to a customer requesting a firm
redirect if rollover rights are available
on the redirect path’’ was inconsistent
with the pro forma OATT.
Commission Determination
1280. Commission policy allows a
redirect of firm, long-term service to
retain rollover rights, even if the redirect
is requested for a shorter period. In
other words, the rollover right follows
780 See
Order No. 676 at P 12.
explains that these are two primary
features in a revised WEQ 001–9.7 standard that
was open for public comment.
781 TranServ
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12431
the redirect, regardless of the duration
of the redirect. Contrary to the
comments of Bonneville, MISO, and
Southern, the Commission did not
impose this requirement for the first
time in Order No. 676, but merely
provided guidance to the industry by
restating Commission policy on this
matter. The Commission has explained
in prior orders that a transmission
customer making a firm redirect request
does not convert its original long-term
firm transmission service to short-term
service, nor does it lose its rollover
rights under its long-term firm
transmission service agreement. The
Commission’s concern underlying this
policy is that long-term customers
should not need to choose between
redirecting on a firm basis and
maintaining rollover rights, rather their
rollover rights should be retained
consistent with the long-term nature of
their service.
1281. In Commonwealth Edison Co.,
the Commission explained that a
‘‘request to change a delivery point on
a firm basis for one month and then to
revert to its original delivery point does
not convert its existing long-term firm
transmission service agreement into two
separate short-term transmission service
agreements.’’ 782 The Commission stated
that section 22.2 was intended to
provide flexibility to transmission
customers to permit them to react in a
competitive market and that some
amount of this flexibility would be lost
if a long-term firm transmission
customer seeking to modify its delivery
points would lose its rollover rights.783
1282. The Commission affirmed this
policy in American Electric Power
Service Corp.784 In that case, a long-term
transmission customer (Exelon) had
been granted a short-term redirect, but
denied rollover rights on the redirected
path. The Commission found the denial
of rollover rights was improper, since
the ‘‘redirect request made by Exelon
did not convert Exelon’s long-term firm
transmission service to short-term
service, and, therefore, did not affect
Exelon’s rollover rights under its longterm firm transmission service
agreement.’’ 785 Thus, there is no
inconsistency between the
Commission’s redirect policy and Order
No. 676.
782 95
FERC ¶ 61,027 at 61,083 (2001).
Commission, however, recognized that
this flexibility was not unlimited—any change to a
delivery point is treated as a new request for service
for purposes of the availability of capacity.
784 97 FERC ¶ 61,207 at 61,905–06 (2001).
785 Id.
783 The
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Comments
1283. With respect to the provision in
section 22.2 of the pro forma OATT
specifying that requests to redirect on a
firm basis be considered new requests
for service, LPPC and NPPD ask that this
provision be modified to ensure that a
customer redirecting its service will
retain a higher priority for service in the
transmission provider’s queue than new
customers. LPPC argues that it is
inequitable to require customers to
compete for capacity as though their
loads were incremental to the system
when they are simply changing their
receipt points as a matter of necessity
(since suppliers may commence serving
other loads or cease doing business). EEI
argues on reply that, if LPPC’s proposal
would give customers priority at new
points of receipt and delivery regardless
of whether the redirected service creates
system impacts different from the old
service, the proposal would replace
‘‘first-come, first-served’’ priority with a
system in which customers would never
know for sure whether their own
requests for service would be displaced
by subsequent requests for redirected
service. EEI cautions that the
transmission system simply cannot be
planned and constructed with enough
spare capacity to allow any customer to
redirect service to any point that it
chooses at any time.
1284. Bonneville similarly argues that
a redirect request should meet the same
term and notice requirements as a new
request given that the transmission
provider’s planning horizon and the
amount of time needed to remarket
unused capacity is no different for a
redirect and a new transmission service
request. APPA argues on reply that it is
unclear how Bonneville’s request would
affect load-serving transmission
customers that cannot obtain power
supply agreements of a term sufficient
to dovetail with the term requirements
for a new request. Imperial recommends
that redirects be evaluated using ATC at
the time of the redirect request, like any
other new request for service, but that
the transmission provider be given
additional time to determine whether
native load growth will prevent rollover
rights for the redirects.
Commission Determination
1285. Section 22.2 of the pro forma
OATT provides that redirects ‘‘shall be
treated as a new request for service in
accordance with section 17,’’ except that
the transmission customer may not be
required to pay an additional deposit in
certain circumstances. Therefore, a
redirect right does not grant the
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d. Pricing for Redirects
As a result, a uniform pricing method
for redirects is beyond the scope of this
proceeding. Nevertheless, we note that
the Commission explained in a recent
order that its policy does not allow
transmission providers to collect
additional charges when a firm point-topoint customer redirects on a non-firm
basis.786 The Commission concluded
that it would not subject non-firm
redirects to the Appalachian Method of
pricing,787 which is premised on the
assumption that a customer using the
transmission system for the 16 peak
hours of the day should pay the same
contribution to fixed costs as a customer
who has reserved capacity on a daily
basis. This is because the redirecting
customer already would have paid for
firm service over all on-peak and offpeak hours during the reservation
period of its service, therefore, there is
no need to ensure that the customer
pays a premium for the opportunity to
cherry pick the best hours each day.
Furthermore, because the Commission
is not requiring the provision of hourly
firm service, Southern’s argument
regarding redirected hourly firm service
is now moot.
Comments
e. Other Issues
1287. TranServ requests that the
Commission resolve a disagreement
among WEQ participants regarding the
pricing of redirects as requests for new
service. TranServ asks whether the
failure to charge an incremental uplift
between the original and redirected rate
(e.g., respectively, the monthly rate and
daily on-peak rate) would constitute the
offering of a discount for daily service
that in turn must be posted for all other
paths to the same point of delivery.
TranServ argues that it is reasonable to
charge an incremental uplift such that
the rate paid by the redirect customer
would be on par with that paid by any
other transmission customer reserving
(daily) short-term firm service of like
duration (i.e., a ‘‘new request for
service’’), and the customer would pay
the difference between the daily onpeak rate and 1/30th of the monthly
rate.
1288. Southern argues that, with
respect to the price for redirects, if
redirected hourly firm service is more
valuable than firm service, economic
theory would dictate that customers
should be required to pay for that added
value.
Comments
customer access to system capacity or
queue position different from other
customers submitting new requests for
service. A redirect request must be
evaluated in accordance with section 17
using the same system assumptions and
analysis applicable to any other new
request for service, including whether
sufficient ATC exists to accommodate
the request. The Commission concludes
it would be inappropriate, and contrary
to the pro forma OATT, to grant
redirects special queue treatment.
1286. Regarding Imperial’s request
that transmission providers be given
additional time to determine whether
native load growth will prevent rollover
rights for the redirects, we find that
redirects should be studied like any
other new request for firm point-topoint service. Transmission providers
must examine whether any request, a
firm redirect request or a new service
request, would be affected by future
native load growth resulting in possible
rollover rights restrictions, so we see no
need to provide additional time for
transmission provider analysis of firm
redirect request.
Commission Determination
1290. EEI agrees with the
Commission’s proposal to clarify that
network customers may not redirect
network transmission service. Alberta
Intervenors contend that undue
discrimination remains because the
flexibility to modify points of receipt
and delivery that the network customer
enjoys through ‘‘parking’’ and
‘‘hubbing’’ is not likewise granted to a
point-to-point customer. Alberta
Intervenors recommends that the pro
forma OATT either make a common
service available to all participants (not
just network customers) or prohibit
network customers from using point-topoint services for parking and hubbing.
1291. Imperial asks the Commission
to clarify that a transmission customer
should not be able to make multiple
redirects. Imperial explains that this
clarification would address two
concerns: multiple short-term changes
raise reliability concerns and often there
is insufficient time for the released
capacity to be used by another
customer; and the burden on properly
scheduling for reliability increases
exponentially when there are redirects
of redirects.
1289. The Commission has not
established a single, industry-wide
pricing policy for redirects and did not
propose a pricing policy in the NOPR.
786 Midwest Independent Transmission System
Operator, Inc., 118 FERC ¶ 61,095 at P 79–85(2007).
787 See Appalachian Power Co., 39 FERC ¶ 61,296
(1987).
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1292. MISO/PJM States argue that
because RTOs are not likely to engage in
discrimination with respect to redirects,
the Commission should not modify RTO
redirect policies in the instant
rulemaking proceeding.
Commission Determination
1293. The Commission adopts the
NOPR proposal and finds that network
customers may not redirect network
service in a manner comparable to the
way customers redirect point-to-point
service. Unlike point-to-point service,
network service involves no identified
contract path and thus is not a
directable service. A network customer
seeking to substitute one resource for
another already has the ability under the
pro forma OATT to terminate its
existing designation and designate a
new resource on an as-available basis. If
necessary, the network customer may
then request to redesignate its original
network resource by making a request to
designate a new network resource.
Alternatively, the network customer
could use secondary network service if
it wants to substitute a non-designated
network resource for a designated
network resource on an as-available
basis.
1294. For similar reasons, the
Commission denies Alberta Intervenors’
request. The Commission has explained
that customers must choose between
point-to-point and network services,
each of which has its own advantages
and risks.788 The Commission declined
to implement a single form of
transmission service in Order No. 888,
concluding that point-to-point and
network services are the appropriate
base-line services under the pro forma
OATT, and Alberta Intervenors offer no
justification for departing from that
approach now. Alberta Intervenors
parking and hubbing related arguments
alleging that network service is
commonly used to purchase power
intended for sales to third parties is
addressed in section V.D.7 of this Final
Rule. Although we deny Alberta
Intervenors’ request, we expect that the
reforms adopted in this Final Rule will
provide point-to-point customers with
increased service options and flexibility.
1295. Implementing Imperial’s
proposal would prevent customers from
redirecting for a short period or periods
of time and then redirecting back to
their original points, making redirects a
less valuable option for customers.
Multiple redirects are allowed only if
the customer can meet the scheduling
and other requirements for new requests
for service under the pro forma OATT.
788 Order
No. 888–A at 30,260.
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As long as the customer meets these
requirements, the Commission believes
that the ability to redirect service does
not present an unreasonable burden to
transmission providers. As for
applicability to RTOs and ISOs, we
explain our compliance requirements in
section IV.C of this Final Rule. To the
extent an RTO’s or ISO’s redirect policy
does not conform to the pro forma
OATT, as amended by this Final Rule,
the RTO or ISO must demonstrate that
its policy is consistent with or superior
to the pro forma provisions in
accordance with the compliance
procedures set forth in that section.
5. Acquisition of Transmission Service
a. Processing of Service Requests
1296. The pro forma OATT includes
requirements that transmission
providers process requests for
transmission service in a timely fashion.
Section 17.5 (Response to a Completed
Application) and section 18.4
(Determination of Available
Transmission Capability) of the pro
forma OATT provide that following the
receipt of a completed application for
service, the transmission provider must
respond to transmission customer
requests for determinations of the
availability of firm and non-firm
transmission capacity on a timely basis.
The transmission provider must make
the determination as soon as reasonably
practicable after receipt but no later
than certain specified time periods (or
such time periods generally accepted in
the region).
1297. Section 19 (Additional Study
Procedures for Firm Point-to-Point
Transmission Service Requests) of the
pro forma OATT provides deadlines
that transmission providers must adhere
to in issuing system impact study
agreements and facilities studies
agreements and that transmission
customers must abide by in responding
to these study agreements. Section 19
requires transmission providers to use
due diligence to complete system
impact studies and facilities studies
within 60 days. Section 32 of the pro
forma OATT (Additional Study
Procedures for Network Integration
Transmission Service Requests)
contains similar due diligence deadlines
for completing system impact studies
and facilities studies associated with
requests for network service.
(1) Posting Performance Metrics
NOPR Proposal
1298. In the NOPR, the Commission
proposed to require transmission
providers to post on their OASIS sites
metrics that track their performance in
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12433
processing system impact studies and
facilities studies associated with
requests for transmission service. The
Commission proposed that transmission
providers calculate the proposed
performance metrics separately for
affiliates and non-affiliates and for
requests for short-term and long-term
transmission service.
1299. In addition, the Commission
proposed to require a notification filing
and the posting of additional metrics if
a transmission provider completes more
than 20 percent of non-affiliates’ studies
outside of the 60-day due diligence
deadline in the pro forma OATT for two
consecutive quarters. Starting the
quarter after a notification filing, the
transmission provider would be
required to post the following
information on OASIS: (1) The average,
across completed system impact studies,
of the employee-hours expended per
completed system impact study, (2) the
average, across completed facilities
studies, of employee-hours expended
per completed facilities study, (3) the
number of employees devoted to
processing system impact studies, and
(4) the number of employees devoted to
processing facilities studies. The
Commission proposed that transmission
providers post these additional
performance metrics until they process
at least 90 percent of all system impact
and facilities studies within 60 days
after the study agreement has been
executed. The additional performance
metrics also would be calculated
separately for affiliates’ and nonaffiliates’ requests for transmission
service and for short-term and long-term
transmission service.
Comments
Standard Performance Metrics
1300. Transmission customers and a
number of other commenters generally
support or do not oppose the
Commission’s proposal to require
transmission providers to post
performance metrics.789
1301. Southern and Salt River oppose
the proposal, arguing that most of the
data needed to compute the metrics is
already available on OASIS. Southern
asserts that the NOPR does not explain
why the currently available information
is inadequate or how the proposed
metrics would not be duplicative and,
thus, does not fully justify the need for
reform. Southern also argues that the
Commission’s proposal will impose
789 E.g., ELCON, Suez Energy NA, Powerex,
Seattle, TAPS, Constellation, Entegra, NRECA, TDU
Systems, Regional Electricity Committee, MISO,
MidAmerican, FirstEnergy, Tacoma, EEI, Nevada
Companies, and TranServ.
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costs and burdens on transmission
providers, and ultimately those who use
their services, that do not correspond
with the limited benefits that might be
gained. Salt River believes that
performance tracking requirements
should be established on a case-by-case
basis in response to complaints.
NorthWestern believes the 60 days
should be a target, but not a deadline,
and, as such, transmission providers
should not be required to report
performance metrics that summarize the
time they take to perform the studies.
1302. Several commenters requested
clarification on certain features of the
Commission’s proposal. Nevada
Companies asks the Commission to be
very specific as to what statistical data
items are to be reported on the OASIS
so that transmission providers do not
inadvertently violate the confidentiality
of their transmission customers. PNMTNMP requests clarification that the
standards set out in the NOPR are solely
applicable to processing of transmission
delivery service requests, and not to
interconnection service requests. Insofar
as the Commission determines that
performance metrics should be posted,
Southern asks the Commission to clarify
that the proposed posting of
performance metrics also would be
required of RTOs and ISOs.
1303. A number of commenters
suggest that the Commission modify the
performance metrics that transmission
providers are required to post. EEI
suggests that NAESB develop the
metrics that transmission providers are
required to post, using the metrics
contained in the NOPR as guidance. EEI
and MidAmerican suggest that the
performance metrics include
information about the degree to which
transmission customers delay the study
process. MISO suggests that
transmission providers post metrics
related to the time transmission
customers take to respond to the results
of completed system impact studies and
facilities studies. Southern asserts that
fewer metrics should be required and
that they should relate directly to the
study-timing concerns raised in the
NOPR. Bonneville and MISO argue that
transmission providers should not have
to post information about the cost of
transmission system upgrades
recommended in the request studies.
Bonneville believes that the average cost
of recommended upgrades is misleading
because it will mask the wide variation
in such costs. MISO suggests that
transmission providers also report the
standard deviation for study completion
times. Southern asserts further that the
OATT does not specifically provide for
a system impact study or facilities study
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to be performed on a short-term basis,
so any metrics required as part of OATT
reform should not include short-term
requests. CREPC suggests that
performance metrics be calculated
separately for renewable resources.
1304. Several commenters suggest
that transmission providers post
additional information to further
enhance transparency. A number of
commenters suggest that the
Commission require the posting of the
disposition of all transmission service
requests, including those not requiring
studies.790 TDU Systems suggest that
the Commission require transmission
providers to post the parameters of each
denied request. MISO suggests that
transmission providers provide a
narrative to explain any anomalous
study costs that may affect the posted
average cost. If a transmission provider
anticipates that it will miss the study
deadline date, NRECA suggests that it
should post that information, the
expected finish date, and a reason for
not being able to meet the deadline.
1305. EEI recommends that the
Commission delegate to NAESB the
responsibility for developing the
Standard and Communications
Protocols, business practices and OASIS
modifications that will be necessary to
provide the metrics.
Additional Performance Metrics (After
Two Quarters of Late Studies)
1306. EEI and Southern oppose the
Commission’s proposal to require
transmission providers that fail to
complete studies in a timely manner to
post additional performance metrics
that measure the labor input used to
complete studies. EEI asserts that there
is little value to be gained from posting
the additional information that the
Commission proposes. EEI believes the
information concerning the number of
employees who perform studies will not
be determinative of responsibility for
the delay because the significant issue is
whether the number of studies that the
transmission provider is required to
perform or the total amount of time
needed to perform studies has increased
significantly or whether customers
caused the delays. Southern questions
the Commission’s legal authority to
require transmission providers that do
not complete studies in a timely manner
to post additional performance metrics,
citing Cal. Ind. Sys. Operator Corp. v.
FERC.791 Southern characterizes the
790 E.g., CREPC, MISO, Constellation, and TDU
Systems.
791 372 F.3d 395, 404 (D.C. Cir. 2004).
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Commission’s proposal as a punishment
for delays in processing request studies.
1307. Several other commenters
suggest changes to the Commission’s
proposal. Southern believes the
submission of a notification of
extenuating circumstances should
suspend the obligation to post the
additional metrics proposed in the
NOPR. EEI and Southern argue that the
Commission should be certain that it is
collecting such information only from
those transmission providers that, for no
other reason except themselves, fail to
consistently evaluate studies within the
60-day due diligence period. Therefore,
if a transmission provider demonstrates
that delays in completing studies are
due to extenuating circumstances, then
EEI and Southern believe the
Commission should not require the
transmission provider to post the
additional metrics. MISO believes the
Commission should exempt RTOs from
the additional employee performance
metrics proposed in the NOPR for the
same reason that the Commission
proposed to exempt RTOs from
operational penalties for untimely
completion of studies, as MISO claims
the additional posting requirements are
in the nature of penalty. Bonneville
believes the proposed metrics will be
misleading whenever a transmission
provider employs outside consultants to
perform or assist with studies.
Therefore, Bonneville suggests that the
Commission add two other metrics, the
number of studies performed entirely by
consultants and, in the case of studies
performed by a combination of
employees and consultants, the average
percentage of the study performed by
consultants.
Commission Determination
Standard Performance Metrics
1308. The Commission will require
transmission providers to post the
performance metrics proposed in the
NOPR, as modified by this Final Rule.
The proposed metrics will enhance the
transparency of the study process and
shed light on whether transmission
providers are processing request studies
in a non-discriminatory manner. We
also agree with comments by
MidAmerican and EEI that transmission
providers should be able to track delays
in the study process caused by
transmission customers. Doing so will
allow the Commission and market
participants to determine the extent to
which delays by transmission customers
are causing transmission providers to
process request studies on an untimely
basis, which will add needed
transparency to the study process.
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Therefore, we will revise the
performance metrics transmission
providers are required to post to include
metrics that track delays by
transmission customers.
1309. Transmission providers will be
required to post the performance
metrics, outlined below, for each
calendar quarter. Transmission
providers will be required to begin
tracking their performance upon the
effective date of this Final Rule and
keep the quarterly performance metrics
posted on their OASIS sites for three
calendar years. The transmission
provider will be required to post the
quarterly performance metrics within 15
days of the end of the quarter. The
performance metrics outlined below
must be calculated separately for
affiliates’ and non-affiliates’ requests, in
order to identify potential instances
when the transmission provider is
processing requests on a discriminatory
basis. The transmission provider is
required to aggregate studies associated
with requests for short-term and longterm transmission service when
calculating the metrics defined below.
While a transmission provider could
offer to study a request for short-term
firm point-to-point transmission service,
we acknowledge that the transmission
customer often is unwilling to pay for
such a study. Therefore, to ease the
reporting burden, the transmission
provider is not required to report the
performance metrics defined below
separately for requests for short-term
and long-term firm point-to-point
transmission service. A transmission
provider is also required to post
performance metrics for studies that it
conducts for RTOs.
1310. A transmission provider is
required to post the following set of
performance metrics on a quarterly
basis:
• Process time from initial service
request to offer of system impact study
agreement pursuant to sections 17.5,
19.1 and 32.1 of the pro forma OATT
Æ Number of new system impact
study agreements delivered to
transmission customers
Æ Number of new system impact
study agreements delivered to the
transmission customer more than
30 days after the transmission
customer submitted its request
Æ Average time (days) from request
submittal to change in request
status
Æ Average time (days) from request
submittal to delivery of system
impact study agreement
Æ Number of new system impact
study agreements executed
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• System impact study processing
time pursuant to sections 19.3 and 32.3
of the pro forma OATT
Æ Number of system impact studies
completed
Æ Number of system impact studies
completed more than 60 days after
receipt of executed system impact
study agreement
Æ Average time (days) from receipt of
executed system impact study
agreement to date when completed
system impact study made available
to the transmission customer
Æ Average cost of system impact
studies completed during the
period
• Service requests withdrawn from
system impact study queue
Æ Number of requests withdrawn
from the system impact study queue
Æ Number of system impact studies
withdrawn more than 60 days after
receipt of executed system impact
study agreement
Æ Average time (days) from receipt of
executed system impact study
agreement to date when request was
withdrawn from the system impact
study queue
• For all system impact studies
completed more than 60 days after
receipt of executed system impact study
agreement, average number of days
study was delayed due to transmission
customer’s actions (e.g., delays in
providing needed data)
• Process time from completed
system impact study to offer of facilities
study pursuant to sections 19.4 and 32.4
of the pro forma OATT
Æ Number of new facilities study
agreements delivered to
transmission customers
Æ Number of new facilities study
agreements delivered to
transmission customers more than
30 days after the completion of the
system impact study
Æ Average time (days) from
completion of system impact study
to delivery of facilities study
agreement
Æ Number of new facilities study
agreements executed
• Facilities study processing time
pursuant to sections 19.4 and 32.4
Æ Number of facilities studies
completed
Æ Number of facilities studies
completed more than 60 days after
receipt of executed facilities study
agreement
Æ Average time (days) from receipt of
executed facilities study agreement
to date when completed facilities
study made available to the
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12435
transmission customer
Æ Average cost of facilities studies
completed during the period
Æ Average cost of recommended
upgrades for facilities studies
completed during the period
• Service requests withdrawn from
facilities study queue
Æ Number of requests withdrawn
from the facilities study queue
Æ Number of facilities studies
withdrawn more than 60 days after
receipt of executed facilities study
agreement
Æ Average time (days) from receipt of
executed facilities study agreement
to date when request was
withdrawn from the facilities study
queue
• For all facilities studies completed
more than 60 days after receipt of
executed facilities study agreement,
average number of days study was
delayed due to transmission customer’s
actions (e.g., delays in providing needed
data).
1311. In response to Nevada
Companies request that we clarify the
statistical data items that are to be
reported on OASIS pursuant to the
Commission’s proposal, we reiterate
that transmission providers are required
to provide summary data as defined
above. We do not believe these data will
violate the confidentiality of any
transmission customer, even in the
event the transmission provider has
worked on a limited number of studies.
We clarify that the performance metrics
posting requirement discussed above is
solely applicable to processing of
transmission delivery service requests,
and not to interconnection service
requests. Finally, we clarify that RTOs
and ISOs also are required to post the
performance metrics described above.
As we discuss below, we believe all
transmission providers should be
subject to the same reporting
requirements.
1312. We disagree with Southern and
Salt River which argue that the data
already on OASIS is sufficient to
accomplish our goal to enhance
transparency of the transmission
provider’s request study processing.
First, the data available on the OASIS
template transstatusaudit does not
contain the information necessary to
calculate all of the performance metrics
proposed in the NOPR.792 For instance,
792 The OASIS template transstatusaudit is
defined in the Standards and Communications
Protocols section of NAESB’s WEQ Business
Practice Standards. The template transstatusaudit is
the audit component to OASIS template transstatus
and, as such, contains information regarding the
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transstatusaudit allows one to
determine when a request was moved
from ‘‘received’’ to ‘‘study’’ and then to
‘‘accepted’’ or ‘‘counteroffer’’.
Depending on when the transmission
provider moves the request into
‘‘study,’’ this information does not allow
one to determine either whether the
transmission provider provided a
system impact study agreement within
30 days or whether the transmission
provider completed the system impact
study within 60 days. In addition, the
transmission provider is required to
make the data in transstatusaudit
available on OASIS for only 90 days and
available by request for three years.793
As a result, market participants would
be required to calculate the performance
metrics they desire on a quarterly basis
if they want to use just the data posted
on OASIS. Finally, downloading
transstatusaudit data for specific OASIS
requests that required a system impact
study or feasibility study can be
cumbersome due to the manual nature
of the download process. The
transmission provider has the data
necessary to calculate the proposed
performance metrics readily available.
We believe it is more efficient for a
single transmission provider to calculate
the performance metrics for its system
rather than have multiple interested
parties calculate the performance
statistics for each transmission provider
of interest.
1313. We also disagree with
Southern’s assertion that the costs and
burdens to transmission providers are
not justified by the benefits that might
be gained. We are concerned that, under
the existing pro forma OATT,
transmission providers do not have
adequate incentives to conduct studies
on a timely and nondiscriminatory
basis. First, transmission providers have
incentives to discriminate against third
parties and in favor of their affiliates
(i.e., to delay the study requests of
nonaffiliates, but act more quickly on
those of its affiliates). Second,
transmission providers also can lack
incentives to provide sufficient staff
resources to support increasing
demands in the study process. Given
that most of the costs associated with
the study process are operational,
transmission providers, at most, will
recover those costs without profit (i.e.,
a return) and, if the demands of the
study process are increasing, fail to
recover such cost increases if the
type of transmission service requested, affiliate
status, date and time the transmission service was
requested, and the date and time of all changes in
request status (e.g., place in study mode, confirmed
or withdrawn).
793 18 CFR 37.7(b).
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transmission provider is between rate
cases. We therefore believe that there
are several reasons that greater
transparency is required to provide the
correct incentives to comply with the
pro forma OATT provisions respecting
studies.
1314. We also note that virtually all
commenters agree with our proposal to
require transmission providers to
calculate the above performance
metrics. This support stems, in part,
from transmission customers’
perception that transmission providers
do not exert sufficient effort to complete
requests in a timely manner.794 Delays
in processing study requests can cause
customers to incur material financial
damage. Moreover, the data needed to
calculate the required performance
statistics is readily available to the
transmission provider and, therefore,
the cost to the transmission provider
will be small relative to the benefits of
enhanced transparency and assurance
that the transmission provider is
processing request studies in a timely
and non-discriminatory fashion.
1315. Based on our experience and
the comments received in response to
the NOI and NOPR, the Commission
believes the steps we take here are
necessary to increase transparency for
the processing of service requests by all
transmission providers. It would be
inappropriate, as some commenters
suggest, to wait for specific complaints
about specific transmission providers
before requiring the transmission
provider to calculate the performance
metrics defined above. We conclude
that the reporting requirements adopted
in this Final Rule must be applied to all
transmission providers in order to
enhance the transparency of the study
process and ensure that transmission
provider processes study requests in a
timely and non-discriminatory fashion
for all transmission customers. The fact
that the 60-day timeframe in the pro
forma OATT is a target and not a
deadline does not change the fact that
requiring all transmission providers to
post the performance metrics defined
above will enhance the transparency of
the study process.
1316. We will not adopt any of the
changes to the proposed performance
metrics requested by commenters, other
than adding metrics to track delays by
customers as discussed above. The
Commission is in a better position to
794 E.g., Constellation, EPSA NOI Comments,
Arkansas Cities NOI Comments, APPA NOI Reply
Comments, and Powerex NOI Reply Comments 795
As noted in P 1318, we direct public utilities
working through NAESB to develop protocols for
posting the performance metrics required here so
they will be posted in a consistent fashion.
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determine the specific performance
metrics that will achieve our policy
goals and thus we will not request that
NAESB develop the metrics to be
posted.795 We believe the set of
performance metrics we have chosen
strike the appropriate balance between
requiring information that will enhance
transparency and help ensure that the
transmission provider is processing
request studies in a timely and nondiscriminatory fashion while limiting
the burden the transmission provider
faces. For instance, we believe the
performance metrics that address the
cost of system impact studies and
facilities studies as well as the cost of
any proposed transmission upgrades
can be calculated with relatively little
effort by the transmission provider and
should provide meaningful benefits to
transmission customers. The
transmission provider readily knows the
cost of studies it completes and the
costs of proposed system upgrades and
summaries of this information should
enhance the transmission customer’s
ability to decide whether to submit a
request for service that may result in a
study offer.
1317. We do not believe the relative
benefits and burdens justify requiring
the transmission provider to post
performance metrics beyond those
adopted in this Final Rule. For instance,
requiring the transmission provider to
calculate additional summary
information or post long narratives to
explain anomalous upgrade costs do not
appear necessary at this time to achieve
our stated policy goals, particularly
since transmission customers can
request data associated with completed
system impact studies and facilities
studies pursuant to section
37.6(b)(2)(iii) of the Commission’s
regulations.796 In addition, we do not
believe transmission customers, beyond
the transmission customer directly
affected, would benefit from the
information NRECA suggests the
transmission provider should be
required to post when it anticipates that
it will not complete a study within the
60-day due diligence timeframe. Section
19.3 of the pro forma tariff already
requires the transmission provider to
notify the affected transmission
customer when it will not be able to
complete a study within the 60-day due
diligence timeframe, provide an
expected completion date, and explain
why additional time is needed. We do
795 As noted in P 1318, we direct public utilities
working through NAESB to develop protocols for
posting the performance metrics required here so
they will be posted in a consistent fashion.
796 18 CFR 37.6(b)(2)(iii).
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not believe other transmission
customers would benefit enough from
this information to justify requiring the
transmission provider to post it.
Similarly, we do not believe the benefit
to market participants justifies the
burden of requiring transmission
providers to calculate performance
metrics separately for renewable
resources.
1318. We agree, however, with EEI’s
recommendation that the Commission
delegate to NAESB the responsibility for
developing the Standard and
Communications Protocols, business
practices and OASIS modifications that
will be necessary to provide the
performance metrics adopted above.
NAESB is in the best position to
develop the standards and the processes
by which the performance metrics are
posted.
sroberts on PROD1PC70 with RULES
Additional Performance Metrics (after
two quarters of late studies)
1319. The Commission also adopts
the NOPR proposal to require
transmission providers to submit a
notification filing with the Commission
in the event the transmission provider
processes more than 20 percent of nonaffiliates’ studies outside of the 60-day
due diligence deadlines in the pro
forma OATT for two consecutive
quarters. This filing must be filed within
30 days of the end of the second quarter
during which the transmission provider
processes more than 20 percent of nonaffiliates’ studies outside of the 60-day
due diligence deadlines in the pro
forma OATT. For the purposes of
calculating this notification trigger, the
transmission provider is required to
aggregate all system impact studies and
facilities studies that it completes
during the quarter for non-affiliates.797
The transmission provider may explain
in its notification filing that it believes
there are extenuating circumstances that
prevented it from meeting the deadlines
in the pro forma OATT.
1320. As the Commission proposed in
the NOPR, starting the quarter following
a notification filing, the transmission
provider will be required to post: (1)
The average, across completed system
impact studies, of the employee-hours
expended per completed system impact
study; (2) the average, across completed
797 For instance, if the transmission provider
completes 4 non-affiliates’ system impact studies
during the quarter with 2 completed more than 60
days after the system impact study agreement was
executed and completes 2 non-affiliates’ facilities
studies during the quarter with none completed
more than 60 days after the facilities study
agreement was executed, then the transmission
provider will be deemed to have completed 2 out
of 6 (33 percent) studies outside of the deadlines
in the pro forma OATT.
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facilities studies, of employee-hours
expended per completed facilities
study; (3) the number of employees
devoted to processing system impact
studies; and (4) the number of
employees devoted to processing
facilities studies. The transmission
provider is not required to post these
additional performance metrics
separately for affiliates’ and nonaffiliates’ requests for transmission
service and for short-term and long-term
transmission service. The transmission
provider is instead required to aggregate
studies associated with requests for
short-term and long-term transmission
service when calculating these
additional metrics. The transmission
provider is not required to post the
additional metrics if the Commission
concludes that delays in completing
studies are due to extenuating
circumstances. However, the
transmission provider is required to
post the additional metrics while the
Commission considers the transmission
provider’s notification filing arguing
that extenuating circumstances
prevented it from processing request
studies on a timely basis. Based on the
timing described in this Final Rule, the
transmission provider will be required
to post the additional performance
metrics approximately two months after
the provider makes its notification
filing. The Commission will have this
time to evaluate the transmission
provider’s contention that it was unable
to complete request studies due to
extenuating circumstances. As a result,
we expect the transmission provider
with legitimate extenuating
circumstances typically will not have to
post any additional metrics.
1321. We disagree with those arguing
that information concerning the number
of employees who perform studies will
not be determinative of responsibility
for the delay. The transmission provider
will have the right to establish that it is
unable to perform studies in a timely
manner because of factors outside its
control. We received a number of
comments to the NOPR and NOI that
suggest that transmission customers
believe transmission providers fail to
complete studies on a timely basis
because they do not have sufficient staff
to perform the studies.798 As explained
above, this is one of the concerns that
has led us to adopt these reforms. The
additional metrics will serve to shed
light on the transmission provider’s
resource commitment, enhance the
transparency of the study process, and
798 E.g., Constellation, EPSA NOI Comments,
Arkansas Cities NOI Comments, APPA NOI Reply
Comments, and Powerex NOI Reply Comments.
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12437
increase the transmission provider’s
incentive to staff its study function
appropriately.
1322. The additional posting
requirement is not a penalty or a
punishment. We opted not to require
the transmission provider to post these
additional performance metrics on a
regular basis out of a desire to limit the
transmission provider’s reporting
burden. However, once the transmission
provider has stopped completing
studies on a timely basis, we believe the
enhanced transparency justifies the
additional reporting burden. As a result,
ISOs and RTOs also will be required to
post the additional performance metrics
described above. We disagree with
Southern’s argument that we lack
jurisdiction to require additional
posting. The posting requirements are
directly related to pro forma OATT
obligations that are necessary to remedy
undue discrimination and, hence,
necessarily derive from our broad
discretion in fashioning remedies to
undue discrimination. We are not
attempting to dictate a transmission
provider’s internal staffing decisions;
rather, we illuminate the transmission
provider’s compliance with its pro
forma OATT obligations to perform
studies within certain deadlines and on
a nondiscriminatory basis.
1323. We will not add the two other
metrics suggested by Bonneville
regarding the number of studies
performed entirely by consultants and,
in the case of studies performed by a
combination of employees and
consultants, the average percentage of
the study performed by consultants.
Rather, transmission providers should
include the time spent by consultants
on studies in the performance metrics
defined above.
(2) Operational Penalties for Late
Studies
NOPR Proposal
1324. The Commission proposed to
impose operational penalties when
transmission providers routinely fail to
meet the 60-day due diligence deadlines
prescribed in sections 19.3, 19.4, 32.3
and 32.4 of the pro forma OATT. Under
the proposal, a transmission provider
who processes more than 20 percent of
non-affiliates’ studies outside of the 60day due diligence deadlines in the pro
forma OATT for two consecutive
quarters would be required to notify the
Commission. In this notification filing,
the transmission provider may explain
that it believes there are extenuating
circumstances that prevented it from
meeting the deadlines in the pro forma
OATT. The transmission provider
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would be subject to an operational
penalty if it continues to be out of
compliance 799 with the deadlines
prescribed in the pro forma OATT for
each of the two quarters following its
notification filing.
1325. The Commission proposed that
the operational penalty be assessed on
a quarterly basis, starting with the
quarter following the notification filing
and continuing until the transmission
provider completes at least 90 percent of
all studies within 60 days after the
study agreement has been executed. For
any system impact study or facilities
study completed during that quarter and
more than 60 days after the study
agreement was executed, the
Commission proposed a penalty equal
to $500 for each day the transmission
provider takes to complete the study
beyond 60 days. For any system impact
study or facilities study that is still
pending at the end of the quarter and
that has been in the study queue for
more than 60 days, the Commission
proposed a penalty equal to $500 for
each day the study has been in the study
queue beyond 60 days.
1326. In addition to the proposed
operational penalties, the Commission
indicated that it would order other
remedial actions, consistent with the
Policy Statement on Enforcement, to be
determined on a case-by-case basis. The
Commission proposed that RTOs not be
subject to this penalty regime because of
the RTOs’ independence.
Comments
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1327. Transmission providers
generally oppose the Commission’s
proposal.800 Some opponents argue that,
to the extent the Commission is going to
impose penalties, it should do so on a
case-by-case basis.801 Opponents cite a
number of reasons the Commission
should not impose the proposed
operational penalty regime. Several
opponents caution that imposing a
penalty may lead transmission
providers to either prematurely deny a
request or accept a request to the
detriment of system reliability.802
Several opponents argue that many
transmission requests introduce unique
complexities into the study process, so
a firm 60-day deadline is not workable
799 The transmission provider would be deemed
to be out of compliance if it completes 10 percent
or more of non-affiliates’ system impact studies and
facilities studies outside of the deadlines prescribed
in the pro forma OATT.
800 E.g., EEI, MidAmerican, Entergy, Southern,
Imperial, NorthWestern, PNM–TNMP, Salt River,
and Bonneville Reply.
801 E.g., EEI, Southern, and PNM–TNMP Reply.
802 E.g., MidAmerican, Southern, Imperial, and
EEI Reply.
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in practice.803 Several opponents argue
that the Commission’s proposed penalty
regime is inconsistent with the new
requirements the Commission has
proposed for regional planning and
requirements to consider redispatch in
the system impact study.804 In its reply
comments, EEI argues that due process
requires that the Commission not
impose penalties on transmission
providers for study delays because, in
EEI’s view, it is highly likely that the
delays will have been caused by factors
or events that were beyond the
transmission provider’s control.
Southern asserts that any scheme of
operational penalties associated with
the processing of studies cannot be
implemented fairly unless and until the
problem surrounding the submission of
multiple requests is addressed.
Southern argues that the Commission
would violate a transmission provider’s
due process rights if it were to impose
penalties for delays caused by
transmission customers. CREPC
proposes that transmission projects that
cross seams not be subject to penalties,
arguing that such an exception will
create a level playing field for those
transmission providers in the West
working with the CAISO and foreign
transmission owners to resolve
transmission service requests.
1328. A number of commenters ask
the Commission to clarify specific
elements of the proposed operational
penalty regime. Several commenters
argue that the proposal does not clearly
provide for an exemption from
operational penalties if the failure to
meet the timeliness criteria is a result of
extenuating circumstances or customer
caused delays, thereby denying
transmission providers due process.805
Several commenters ask the
Commission to clarify that a
transmission provider is not subject to
operational penalties if the transmission
provider’s failure to meet the
compliance threshold following its
notification filing is due to extenuating
circumstances.806 Southern asks that the
Commission clarify that the submission
of a notification of extenuating
circumstances would suspend the
obligation of a transmission provider to
process at least 90 percent of the study
requests within the proposed deadlines,
until such time as the Commission
issues a final determination on the
notification of extenuating
803 E.g., MidAmerican, Southern, NorthWestern,
Northwest IOUs, and PNM–TNMP Reply.
804 E.g., MidAmerican, Southern, and EEI Reply.
805 E.g., EEI, Southern, Northwest IOUs, and
MidAmerican.
806 E.g., EEI and MidAmerican.
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circumstances. Tacoma asks the
Commission to ensure that the
processing time is measured from the
point that the customer provides
complete information.
1329. EEI recommends that the
Commission hold a technical conference
to determine the extent to which studies
are not being completed within 60 days,
the principal causes of delays in
completing studies within 60 days and
whether the increased planning and
coordination requirements proposed by
the Commission will result in additional
time being needed to complete the
studies. EEI believes the Commission is
far more likely to arrive at a reasonable
conclusion concerning these issues after
a technical conference than if it simply
imposes penalties for failures to
complete all studies within 60 days.
Seattle believes the proposed penalties
should not be implemented until
providers and customers have had at
least one year of experience working
with the performance metrics.
1330. Transmission customers
generally support the Commission’s
proposal to impose operational
penalties when a transmission provider
routinely fails to meet the 60-day due
diligence deadlines.807 In its reply
comments, Entegra argues that the
question is not whether a transmission
provider has sufficient margins of
flexibility, but whether the transmission
provider has any stake in meeting the
deadlines. Occidental argues that
transmission providers may have little
incentive to meaningfully address
customers’ issues without the prospect
of a prospective remedy. Responding to
EEI’s due process argument, TDU
Systems in reply assert that imposition
of penalties in this instance raises no
more due process concerns than those
operational penalties that transmission
customers are routinely subjected to
under the OATT. TDU Systems argue
that, should the Commission determine
that transmission providers are entitled
to challenge any operational penalty for
failure to process service requests in a
timely manner, then those challenges
must be on terms and conditions that
are comparable to those available to
transmission customers—a complaint
pursuant to FPA section 206. TDU
Systems believe that the proposed
‘‘explanatory statement’’
contemporaneous with any notification
filing is a form of expedited review that
is clearly not comparable to the
treatment of customers under the tariff.
807 E.g., Suez Energy NA, TAPS, Constellation,
Entegra, TDU Systems, CREPC, and Nevada
Companies.
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1331. Several transmission customers
question whether the proposed penalty
level is sufficient to ensure
compliance.808 Constellation
recommends a penalty of up to $10,000
per day per violation. Entegra suggests
the Commission set the penalty equal to
the higher of the lost opportunity cost
to the customer resulting from the delay,
if any, or $1,000 for each day. Entegra
also suggests that penalties should be
assessed automatically, without a
notification filing to the Commission. In
its reply comments, EEI argues that the
total penalty for delayed studies will be
far higher than $500 per day if the
transmission provider is processing
more than five requests per 60-day
period, which EEI asserts is extremely
likely.
1332. Constellation asks the
Commission to consider whether to
require the transmission provider to
engage an independent transmission
administrator to the extent a
transmission provider’s posted
performance metrics are not accurate or
the transmission provider persistently
fails to adhere to the relevant timelines.
1333. Several commenters suggest
that the Commission extend the study
completion deadlines, such as to 120 or
180 days, at least for the purposes of
assessing penalties.809 Bonneville
suggests that the Commission change
the service request study process to
match the interconnection study process
as articulated in the Large Generator
Interconnection Procedures. Imperial
recommends that instead of mandating
a nationwide study schedule, each of
the NERC regions should establish a
schedule taking into account the various
needs of the region. Southern suggests
restarting the 60-day due diligence
period for any study that experiences a
delay that cannot properly be attributed
to the transmission provider. In contrast
to the suggestions to increase the study
time, Entegra suggests that the
Commission consider changing the due
diligence deadlines to 30 days to further
the goal of encouraging timeliness in
completing required studies.
1334. Several commenters suggest
methods for distributing the operational
penalties the transmission provider pays
for late studies. TAPS believes that
penalty revenues should go to victims of
study delay. Similarly, Entegra believes
the penalty should take the form of a
credit against the transmission
customer’s obligation to reimburse the
transmission provider for study costs,
808 E.g.,
TAPS, Constellation, and Entegra.
Bonneville, MidAmerican, Progress
Energy, NorthWestern, Northwest IOUs, and EEI
Reply.
809 E.g.,
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with any amount in excess of the study
costs payable to the transmission
customer, in recognition of the harm to
transmission customers when required
studies are not completed expeditiously.
CREPC asks the Commission to clarify
how it plans to determine which
unaffiliated transmission customers will
receive operational penalty payments.
CREPC also asks the Commission
whether the $500 per day penalty is a
flat rate that would be pro-rated among
eligible non-offending, unaffiliated
transmission customers or if the $500 is
a rate paid to each eligible transmission
customer.
1335. Commenters affiliated with
RTOs and one transmission customer
support the Commission’s proposal to
exempt RTOs from penalties for late
studies.810 MISO asserts that RTOs do
not have incentives to delay the
processing of transmission service
requests, as they have no affiliates to
favor and because their Commissionapproved design and internal
procedures ensure their independence.
MISO argues further that all
transmission service requests benefit
some RTO member and, as a result,
RTOs have no disincentive to approve
service so long as reliability is
maintained. MISO/PJM States asserts
that the NOPR proposal to exempt RTOs
from operational penalties for late
studies is appropriate because a penalty
does not serve a useful purpose with
respect to RTOs. TDU Systems state that
an RTO should not be financially
penalized for late studies because RTO
independence should minimize
incentives for affiliate preference and
RTO members indirectly pay for all RTO
incurred costs in any event.
1336. Most of those commenters not
affiliated with an RTO oppose the
proposal to exempt RTOs from penalties
for late studies.811 Southern argues that
given that the Commission is seeking to
increase transparency in the system, the
Commission would undercut that goal
by omitting a significant segment of the
industry. TAPS argues that RTOs may
still fail to complete studies on a timely
basis due to competing internal
priorities or bureaucratic indifference.
Progress notes that the Commission has
found that RTOs and ISOs should be
subject to penalties for failure to meet
reliability standards. Salt River argues
that RTOs should be subject to
operational penalties because the
impact on the customer is identical if
the request processing deadline is not
810 E.g., MISO, MISO/PJM States, TDU Systems,
and Indianapolis Power Reply.
811 E.g., Southern, TAPS, Progress Energy, Salt
River, and Xcel.
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12439
met regardless of the type of provider
conducting the study. Xcel notes that,
historically, transmission owners need
to complete facility studies in concert
with RTOs, thereby giving the customer
the most up-to-date and coordinated
analysis. Consequently, Xcel believes it
is imperative that both transmission
owners and RTOs operate under the
same rules, reporting obligations, and
performance metrics in the OATT.
1337. In its reply comments, WPS
disagrees with the Commission’s
proposal to exempt RTOs from penalties
for their repeated failure to meet the 60day due diligence requirements. WPS
asserts that the Commission should
impose penalties and prohibit the
recovery of associated revenue where
appropriate. WPS argues that RTO
independence does not guarantee RTO
competence or compliance in every
instance. WPS believes imposing
reporting obligations and penalties for
failure to comply with tariff
requirements, particularly tariff
deadlines, will help to motivate
compliance by ensuring that RTOs
devote resources to tariff compliance.
WPS acknowledges that a non-profit
RTO has no dividends to cancel and
likely no property to liquidate to cover
these shortfalls, yet believes that such
organizations can exercise cost-cutting
measures, especially regarding rewards
for employee performance, and thereby
bear some financial responsibility and
accountability for their operational
violations. In the event of a penalty,
WPS believes the Commission could
require an RTO to take steps to cover its
penalty-related revenue shortfall by
cutting its budget, eliminating
management bonuses and
demonstrating that it has taken
reasonable corrective steps before the
Commission permits recovery of the
remaining penalty revenue from its
members and customers. To the extent
some portion of an RTO’s penalties are
passed through to its market
participants, including transmission
owners, WPS argues that those market
participants would be in a position to
take actions similar to the actions taken
by shareholders of a publicly traded
company to motivate the RTO either by
changing the RTO’s processes or its
Board of Directors.
1338. TAPS states that some
adaptation of the penalties may be
necessary to make them appropriate and
effective in the non-profit RTO/ISO
context, for example, by requiring a
reduction in management
compensation. TDU Systems
recommend that RTOs be subject to the
notification filing requirement that is
part of the Commission’s penalty
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proposal, regardless of whether RTOs
are subject to pay penalties. TDU
Systems believe this reporting
requirement would provide an objective
measure of RTO efficiency. APPA
believes steps should be taken to
remedy tardy RTO processing of service
requests, suggesting that performance
incentives for RTO employees, if
carefully designed, could be useful. In
its reply comments, Duke argues that
although transmission owners in RTOs
should not pay the price for RTOs
failures to abide by the tariff, RTOs lack
of performance should be addressed by
the Commission, perhaps in a separate
proceeding.
1339. Transmission providers that
have retained an independent tariff
administrator suggest that these
independent entities should also be
exempt from operational penalties
related to study completion times.812 In
their view, these independent entities
also have no incentive to discriminate
when completing service request
studies. Similarly, NorthWestern argues
that a transmission provider without an
affiliate that could benefit from a delay
in completing service request studies
also should be exempt from paying the
proposed operational penalties.
Commission Determination
1340. The Commission adopts the
NOPR proposal to subject transmission
providers to operational penalties when
they routinely fail to meet the 60-day
due diligence deadlines prescribed in
sections 19.3, 19.4, 32.3 and 32.4 of the
pro forma OATT. Transmission
providers must have a meaningful stake
in meeting study time frames. As
discussed above, a transmission
provider will be required to make a
notification filing with the Commission
indicating that it has not completed
request studies on a timely basis and
may present evidence that extenuating
circumstances prevented it from
completing studies on a timely basis.
The transmission provider then will be
subject to an operational penalty if the
transmission provider continues to be
out of compliance with the deadlines
prescribed in the pro forma OATT for
each of the two quarters following its
notification filing and the Commission
determines that no extenuating
circumstances exist to excuse the
transmission provider’s noncompliance. The transmission provider
will be deemed to be out of compliance
if it completes 10 percent or more of
non-affiliates’ system impact studies
and facilities studies outside of the
deadlines prescribed in the pro forma
812 E.g.,
Duke, MidAmerican, and TranServ.
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OATT. The operational penalty will be
assessed on a quarterly basis, starting
with the quarter following the
notification filing and continuing until
the transmission provider completes at
least 90 percent of all studies within 60
days after the study agreement has been
executed. For any system impact study
or facilities study completed during that
quarter and more than 60 days after the
study agreement was executed, the
penalty will equal $500 for each day the
transmission provider takes to complete
the study beyond 60 days. For any
system impact study or facilities study
that is still pending at the end of the
quarter and that has been in the study
queue for more than 60 days, the
penalty will equal $500 for each day the
study has been in the study queue
beyond 60 days.
1341. The late study penalty regime
described in this Final Rule will become
effective at the same time as the rest of
the new pro forma OATT. The penalty
regime is designed so that the
transmission provider has to be out of
compliance for at least three quarters
before it is subject to late study
penalties. We believe nine months is
sufficient time for the transmission
provider to adjust its operations to the
new requirements in this Final Rule,
including penalties for late studies. That
is, we believe transmission providers
should be able to reallocate employees
to study requests for service and hire
new staff, to the extent these steps are
necessary, by the time the transmission
provider will be subject to civil
penalties.
1342. The procedures underlying the
operational penalty regime adopted in
this Final Rule ensure that the due
process rights of transmission providers
are protected. In their notification filing,
transmission providers will have the
right to document and describe any
unique complexities that particular
requests introduce into the study
process and that prevent the
transmission provider from completing
the study within a the 60-day due
diligence time frame. Thus the 60-day
time frame will continue to be a flexible
deadline, especially given that the
transmission provider is not required to
complete all studies within 60 days.
These due process rights provide a de
facto case-by-case review of the
transmission provider’s efforts to
complete studies on a timely basis.
1343. On review of a notification
filing, we will waive operational
penalties if a transmission provider
establishes that its non-compliance is
the result of factors or events that are
truly beyond its control, including
delays caused by the transmission
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customer. We will not, however, exempt
all transmission projects that cross
seams from operational penalties, as
CREPC urges. We will consider the
specific facts surrounding studies of
such projects based on a transmission
provider’s notification filing. In
response to TDU Systems, we
acknowledge that the procedures for
addressing a transmission provider’s
failure to conform to the 60-day time
frame are not the same as the
procedures applicable to a transmission
customer that is assessed an operational
penalty under the pro forma OATT. We
believe such different procedures are
justified in this instance. The other
operational penalties in the pro forma
OATT are assessed for failure to remain
in compliance with strict requirements,
while the study time frame is based on
the transmission provider using its due
diligence to complete studies within 60
days. The Commission recognizes that
the transmission provider must have
flexibility, within reason, to complete
studies outside of this time frame. At
the same time, the notification and
penalty procedures we adopt in this
Final Rule will ensure that this
flexibility is not abused.
1344. We do not find the remaining
comments in opposition to the
operational penalty for late studies to be
compelling, particularly given the
flexibility built into our penalty regime.
We would not expect a transmission
provider to prematurely deny a request
for service simply to avoid an
operational penalty. According to
section 17.5 of the pro forma OATT, a
transmission provider must either grant
service or offer the transmission
customer a system impact study. The
transmission provider does not have the
option to simply deny the request for
service. We therefore interpret
comments that the transmission
provider may prematurely deny a
request to mean that the transmission
provider will not explore all possible
system upgrades or redispatch options
as required by section 19.3 of the pro
forma OATT or any conditional firm
options discussed in section V.D.1.
Such behavior would be a tariff
violation that should be brought to our
attention. The transmission provider is
required under the pro forma OATT to
provide a complete study and
corresponding work papers to the
transmission customer. If a transmission
customer feels a system impact study is
incomplete, it has recourse to call the
Commission’s Enforcement Hotline or
file a formal complaint with the
Commission.
1345. We also do not expect a
transmission provider to accept a
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transmission service request to the
detriment of system reliability simply to
meet the study time frame. First, the
transmission provider is not required to
complete every request study within 60
days. Second, to the extent our new
requirements that the transmission
provider consider conditional firm
options and participate in regional
planning cause study delays, the
transmission provider can document
and describe such delays in its
notification filing. Finally, the
transmission provider has been required
to consider redispatch in the system
impact study since Order No. 888 was
issued, so the 60-day due diligence time
frame should continue to be consistent
with the long standing requirement to
consider redispatch in the system
impact study.
1346. As we discuss below, we
believe NAESB’s queue hoarding and
queue flooding business practices, as
well as additional reforms adopted in
this Final Rule, will address the
problem surrounding the submission of
multiple requests. With regard to
requests for a technical conference or
further procedures to consider the effect
of our operational penalty regime, we
believe the commenters’ proposals
would largely provide anecdotal
information and speculation on the
impacts of the new planning and
coordination requirements. Our
experience from the last ten years, and
the comments provided in response to
the NOI and NOPR, provide a sufficient
basis to develop a penalty regime. In
addition, the very requirement that
transmission customers post
performance metrics and submit
notification filings prior to assessment
of operational penalties will provide
actual experience with the new regime.
As explained above, the notification
procedures adopted today will ensure
that we will not assess a penalty for late
studies unless justified by the
circumstances. We can propose
additional changes to the study process
or penalty regime based on the actual
experience under this Final Rule if our
experience warrants it.
1347. As described above, we adopt
the proposal to set the operational
penalty for late studies equal to $500
per day per late study. We believe $500
per day per late study is in line with the
cost the transmission provider would
incur to focus additional resources on
processing requests studies. In addition,
the penalty for being one month late,
$15,000, is in line with the overall cost
of the study. We conclude that the $500
per day per late study penalty is high
enough to provide the incentive to
transmission providers to comply with
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study processing deadlines in the pro
forma OATT, while not being
unnecessarily punitive. We believe that
a penalty in the range of $10,000 per
day per late study would be
unnecessarily punitive. The proposal to
set the penalty equal to the higher of the
lost opportunity cost to the customer
resulting from the delay, if any, or
$1,000 for each day is administratively
cumbersome and could result in
administrative costs that are not
justified. Finally, we believe the due
process afforded the transmission
provider is an important element of the
penalty regime, so we decline to impose
penalties automatically, without a
notification filing to the Commission.
1348. As indicated in the NOPR, we
may order other remedial actions in
addition to the operational penalties
described above, consistent with the
Policy Statement on Enforcement. We
will determine any other remedial
action on a case-by-case basis. The
decision to order other remedial actions
will be based, among other things, on
whether we believe the transmission
provider is using the same due diligence
to complete studies for non-affiliated
customers as it uses to complete studies
for itself. We do not believe it would be
appropriate, as a general matter, to
require a transmission provider to
engage an independent transmission
administrator to the extent its posted
performance metrics are not accurate.
As a threshold matter, Commission
audit staff may audit the accuracy of a
transmission provider’s posted metrics.
If we are concerned about the accuracy
of a transmission provider’s metrics, we
will evaluate the use of third-party
audits at that time. We will not prejudge
which remedial actions we will
consider if a transmission provider
persistently fails to adhere to the
relevant timelines. Rather, we will
review each such instance on a case-bycase basis and determine the
appropriate remedial action consistent
with the Commission’s Policy Statement
on Enforcement.
1349. We clarify that a transmission
provider is not subject to operational
penalties if it can make a showing that
its failure to meet the compliance
threshold following its notification
filing is due to extenuating
circumstances, as we agree that the
transmission provider should not be
penalized for factors out of its control.
The submission of a notification of
extenuating circumstances will not,
however, suspend the obligation of a
transmission provider to process at least
90 percent of the study requests within
the proposed deadlines, until such time
as the Commission issues a final
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12441
determination on the notification of
extenuating circumstances. At the same
time, we will not require the
transmission provider to distribute its
operational penalty while we are still
considering the transmission provider’s
notification filing. The transmission
provider nonetheless remains liable for
paying the operational penalty for all
request studies completed or
outstanding after the notification filing
and not completed within 60 days. This
timing will balance the transmission
provider’s due process rights with the
need to provide an incentive to the
transmission provider to complete
studies on a timely basis.
1350. We clarify that the processing
time is measured from the point that the
customer returns its executed study
agreement to the transmission provider.
By the time the transmission provider
offers a system impact study agreement,
it should have all the information it
needs to complete the study. Pursuant
to section 17.4 of the pro forma OATT,
the transmission provider can deem a
transmission service request deficient if
the transmission customer does not
provide all information the transmission
provider needs to evaluate the request
for service. We expect the transmission
provider to use informal means to
communicate the information it needs
from the transmission customer before it
deems a transmission service request
deficient.
1351. We adopt the NOPR proposal to
have the transmission provider
distribute the operational penalty for
late studies to all non-affiliated
transmission customers, as discussed in
section V.C.5.b of this Final Rule. We
believe that a transmission provider that
is not processing studies on a timely
basis potentially harms all transmission
customers, not just those with requests
in the study queue. For instance, a
transmission customer may decide
against requesting service that it
believes will require a system impact
study if the transmission provider is not
processing transmission service requests
on a timely basis. Therefore, we will not
adopt suggestions to distribute penalty
revenue only to transmission customers
that have request studies that are not
completed within 60 days. We clarify
that the penalty is $500 per day per late
study, with the resulting total penalty
revenue distributed to unaffiliated
transmission customers as discussed in
section V.C.5.b of this Final Rule. We
clarify that the transmission provider
will propose a method to determine
how unaffiliated transmission
customers will receive operational
penalty payments, as discussed in
section V.C.5.b of this Final Rule.
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1352. We will not alter the 60-day
study completion timeframe currently
embodied in sections 19.3, 19.4, 32.3
and 32.4 of the pro forma OATT. We
continue to believe, absent concrete
evidence to the contrary, that the
existing timeframe adequately balances
the need for expeditious resolution of
request studies and the need to ensure
that the transmission provider can
reliably accommodate the transmission
service reserved. Moreover, we believe
the penalty regime defined in this Final
Rule protects the transmission provider
in the event studies take longer to
complete due to the new planning
requirements defined in section V.B of
this Final Rule or the new requirement
to consider conditional firm options as
defined in section V.D.1 of this Final
Rule. We will not adopt the suggestion
to restart the 60-day due diligence
period for any study that experiences a
delay that can not properly be attributed
to the transmission provider. We
reiterate that the transmission provider
is not subject to penalties for late
studies if it can establish that delays are
due to factors the transmission provider
cannot control.
1353. The Commission declines to
adopt the NOPR proposal to exempt
RTOs from operational penalties for
completing studies on an untimely
basis. We agree with those commenters
that argue that RTO independence does
not guarantee RTO competence or
compliance in every instance and that
RTOs may fail to complete studies on a
timely basis due to competing internal
priorities or staffing issues. Imposing
penalties for failure to comply with the
due diligence timeframe for completing
studies will provide RTOs an
appropriate incentive to comply with
the pro forma OATT requirements and
ensure that they devote adequate
resources to tariff compliance. Finally,
we note that subjecting RTOs to
operational penalties for late studies is
consistent with the Commission’s
decision to subject RTOs and ISOs to
penalties for failure to meet reliability
standards.813 We believe that all
transmission providers, including RTOs,
should operate under the same rules,
reporting obligations, and performance
metrics in the OATT. We will
nonetheless keep in mind the nature of
an RTO’s operations and the RTO’s
813 Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of
Electric Reliability Standards, Order No. 672–A, 71
FR 19814 (Apr. 18, 2006), FERC Stats. & Regs.
¶ 31,212 at P 56 (2006) (‘‘It is not arbitrary and
capricious to treat all operators alike, including
RTOs and ISOs, in terms of their liability for
violation of a Reliability Standard.’’).
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unique characteristics when we
consider whether penalties would be
appropriate. We agree that RTOs do not
have an incentive to discriminate
(which is one of the bases for this
policy) and we agree that imposing a
penalty raises the issue of cost recovery,
as most RTOs are not-for-profit entities.
We will therefore consider these and all
other relevant factors in exercising our
discretion whether to impose a penalty
in a given circumstance.
1354. Consistent with the treatment of
RTOs, we will not exempt independent
entities that provide tariff
administration from penalties for late
completion of studies. As with RTOs,
independence does not guarantee
competence or compliance in every
instance. Independent entities have a
similar incentive to limit the personnel
committed to processing request studies
in an effort to reduce overhead costs.
We believe that all entities
administering the tariff should operate
under the same rules, reporting
obligations, and performance metrics in
the pro forma OATT.
(4) Fee for Multiple Self-Competing
Transactions
NOPR Proposal
(3) Recovery Through Rates
1358. In the NOPR, the Commission
sought comment on a fee structure that
could provide a disincentive for
transmission customers to submit
duplicative requests without penalizing
transmission customers that have
legitimate requests for transmission
service. The Commission asked for
detailed recommendations, including
any proposed tariff language, regarding
the standards it should use to identify
requests that would be subject to a fee.
The Commission also sought
recommendations on the level of a fee
that balances its policy goals to
discourage requests for transmission
service that the transmission customer
does not intend to confirm while not
discouraging legitimate requests for
transmission service. Finally, the
Commission sought comment regarding
the circumstances, if any, under which
the processing fee would be refunded to
or credited to the transmission
customer.
NOPR Proposal
Comments
1355. The Commission proposed that
a transmission provider cannot recover
for ratemaking purposes any operational
penalty it pays for failing to process
transmission service studies on a timely
basis.
1359. A number of commenters
express support for a fee for duplicative
requests.814 CREPC believes that queue
blocking behavior should be
discouraged so that legitimate requests
lower in the queue are not
disadvantaged. MISO believes the
transmission provider should be
allowed to charge a fee that is small
enough to not create a barrier to entry
yet high enough to ‘‘add up’’ for anyone
wishing to flood the queue. MISO and
Seattle suggest that the fee be based on
the transmission provider’s cost to
review a request and handle the initial
processing. MISO also believes the
transmission provider should be able to
charge a fixed dollar amount for any
accepted requests that the customer
wants to retract. Southern suggests that
the Commission consider a procedure
whereby transmission customers place a
deposit with transmission providers to
cover a certain number of requests that
is forfeited once the requests reach a
certain threshold and are deemed selfcompeting. TranServ suggests that the
fee apply to requests for long-term firm
transmission service and be based on
duration of the request and not capacity
requested as an incentive to the
transmission customer to submit fewer
combined requests where possible.
TranServ suggests this fee could be
Comments
1356. CREPC noted that, while it may
be reasonable for an investor-owned
utility to pay penalties without being
allowed to recover the penalties in rates,
this approach will be problematic for
utilities that do not have shareholders.
Commission Determination
1357. We will prohibit all
jurisdictional transmission providers
from recovering penalties for late
studies from transmission customers.
We believe that all entities
administering the tariff should operate
under the same rules, reporting
obligations, and performance metrics in
the pro forma OATT. Non-profit
transmission providers have other
sources of money to pay penalties
beyond the revenue they collect for
sales of transmission service. Therefore,
we require non-profit transmission
providers to pay operational penalties
for late studies from their other sources
of money. This notwithstanding, we
may consider factors such as an entity’s
financial ability to absorb a penalty in
determining whether to impose
penalties in the first instance.
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814 E.g., MidAmerican, MISO, Seattle, Southern,
TranServ, TAPS, and CREPC.
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waived if the service request is
submitted pre-confirmed.
1360. Most of the transmission
customers and some transmission
providers oppose the creation of a fee
structure for duplicative requests for
transmission service.815 Several
commenters argue that the Commission
should determine whether the newlyadopted NAESB business practices and
other reforms proposed in the NOPR can
reduce the number of requests that the
transmission customer does not intend
to confirm.816 Nevada Companies and
Great Northern assert that the current
deposit requirement serves to
discourage multiple self-competing
requests. Constellation asserts that the
Commission should focus on narrowlytailored penalties to deter market
participants from intentionally jamming
the queue.
1361. Several commenters suggest
that a transmission provider that makes
a showing that it is experiencing a
significant problem with respect to
customers’ submission of multiple
competing requests should be allowed
to propose a fee to combat the
problem.817 MISO notes that the
Commission has rejected a fee for
unconfirmed requests in the past.818
1362. TAPS believes the fee revenue
should be shared with network
customers on a load-ratio share basis.
TAPS also suggests that the fee apply to
the transmission provider’s merchant
arm in a meaningful way.
1363. CREPC urges the Commission to
adopt a simple, straightforward standard
for determining duplicative requests,
such as the same points of receipt and
delivery, same source and sink, same
time frame, and same firmness, as well
as the same project at multiple
locations. Powerex recommends that the
Commission be very specific in
describing the types of multiple
transmission requests it believes to be a
problem and the fee structure that
would be applied to such problematic
requests. For example, Powerex believes
the Commission should clarify that
requests subject to the fee must be
multiple, not pre-confirmed, and with
identical quantity, point of receipt,
point of delivery, start time, end time,
and firmness. In its reply comments,
815 E.g., EEI, Nevada Companies, Powerex, and
Suez Energy NA.
816 E.g., EEI, Powerex, Suez Energy NA, and
Entegra.
817 E.g., EEI and TAPS.
818 See Midwest Independent Transmission
System Operator, Inc., 97 FERC ¶ 61,269 (2001)
(rejecting a proposal to include a fee for nonconfirmed transmission service requests for firm
point-to-point transmission service of one week or
longer).
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Santa Clara disagrees with Powerex.
Santa Clara urges the Commission to
examine the practice of queue hoarding
and punish those entities that are acting
in an anticompetitive and manipulative
manner. Further, Santa Clara urges the
Commission to refrain from being too
specific in its ruling, as a more general
explanation of the behavior to be
avoided would go a long way in
preventing entities from making an endrun around a ruling against queue
hoarding.
1364. MidAmerican believes that if a
fee is imposed, the fee should not be
refunded as the administrative costs and
difficulty of administering the refunds
would be an unreasonable burden on
the transmission provider. CREPC
believes refunding or crediting the
processing fee would defeat the purpose
of having one in the first place, although
the processing fee could be refunded if
the duplicative service request attached
to it actually comes to fruition. Suez
Energy NA suggests that the processing
fee be refunded whenever the
transmission provider exceeds the 60day request study due diligence
deadline. TAPS suggests that the fee be
structured to provide for exceptions
where the failure to confirm reflects a
legitimate purpose, not jamming. TAPS
cites as examples transmission requests
associated with requests for proposals,
alternative sites for planned generation,
and the inability to secure timely
confirmation of all legs of a multisystem path. TAPS notes that the
current pro forma OATT accommodates
multiple submissions in relation to the
same competitive solicitation in
sections 19.2(ii) and 32.2(ii).
Commission Determination
1365. The Commission will not
require transmission providers to charge
a fee for duplicative requests for
transmission service. We will instead
first consider whether the newly
adopted NAESB queue flooding and
queue hoarding business practices
reduce the number of requests that the
transmission customer does not intend
to confirm. We are concerned that
benefits to market participants would
not justify the administrative costs of a
new fee if the NAESB business practices
can effectively discourage transmission
service requests the transmission
customer does not intend to confirm.
We also believe that the current deposit
mechanism in section 17.3 of the pro
forma OATT should have the same
effect as a fee based on the transmission
provider’s cost to process the request for
transmission service, like the fee MISO
and CREPC propose. Pursuant to section
17.3, in the event a transmission
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12443
customer retracts or withdraws a
request, the transmission provider is
allowed to deduct from the transmission
customer’s deposit the costs the
transmission provider incurred to
process the request. As a result, we do
not believe any other fee structure is
necessary to make the transmission
provider whole when a transmission
customer submits a transmission service
request it does not expect to confirm.
1366. A transmission provider that
continues to experience problems
related to submission of multiple
duplicative requests for transmission
service is free to file a tariff modification
that includes a fee to combat the
problem. This filing should explain why
the transmission provider is unable to
handle the submission of multiple
duplicative requests for transmission
service through NAESB’s queue
hoarding and queue flooding business
practices.
(5) Clustering Transmission Service
Request Studies
NOPR Proposal
1367. In the NOPR, the Commission
sought comment regarding whether a
transmission provider should be
required to study requests for
transmission service in a group if the
transmission provider fails to complete
studies on a timely basis. If so, the
Commission sought comment on the
circumstances that should trigger such a
requirement and the appropriate
method of implementing the
requirement. The Commission sought
further comment regarding whether
transmission providers should be
required to study requests for
transmission service in a group if all the
transmission customers in the group
agree to cluster their requests. Finally,
the Commission sought comment
regarding how to select the requests that
belong to a cluster so that transmission
customers cannot ‘‘cherry-pick’’ clusters
to avoid transmission system upgrade
costs.
Comments
1368. A few commenters, primarily
transmission customers, believe
transmission providers should be
required to study requests for
transmission service in a group.819
CREPC believes transmission providers
should have the discretion to develop
the criteria for clustering so that
transmission customers do not have the
opportunity to ‘‘cherry pick’’ study
clusters. If transmission providers are
required to study requests in a group,
Powerex believes customers should be
819 E.g.,
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given the option of paying the
transmission provider to perform an
individual study. Suez Energy NA
believes studying requests that are
clustered voluntarily will partially
incorporate the value of counterflows in
the study process. PGP believes
transmission customers should have the
opportunity to join a cluster, but only if
the customer is bound to accept the
study results.
1369. A number of commenters,
primarily transmission providers, state
that transmission providers should be
allowed, but not required, to study
requests for transmission service in a
group.820 Bonneville argues that the
transmission provider is in the best
position to determine whether requests
should be studied individually or in
groups. EEI asserts that clustering does
not necessarily ensure timely
completion of transmission studies.
FirstEnergy believes each transmission
service request should stand on its own
merits and be directly assigned costs
associated with its own request so that
requests in one part of the request queue
do not end up subsidizing requests in
another part of the request queue. MISO
believes giving the transmission
provider discretion to cluster requests
will address the Commission’s concerns
with respect to transmission customers
cherry-picking clusters to avoid paying
upgrade costs. Arkansas Commission
and East Texas Cooperatives suggest
that the Commission allow clustering
through an open season procedure
similar to the procedure SPP currently
uses pursuant to Attachment Z of SPP’s
OATT.
Commission Determination
1370. The Commission will not
require transmission providers to study
transmission requests in a cluster,
although we encourage transmission
providers to cluster request studies
when it is reasonable. We do, however,
require transmission providers to
consider clustering studies if the
customers involved request the cluster
and the transmission provider can
reasonably accommodate the request.
We believe clustering request studies
offers potential benefits as the needed
transmission upgrades are frequently
large enough that the upgrade can
accommodate more than one
transmission service request. In
addition, jointly modeling transmission
service requests can allow the
transmission provider to more
efficiently design transmission system
upgrades. Clustering also allows the
820 E.g., Bonneville, EEI, MISO, Nevada
Companies, Southern, Entegra, and PNM–TNMP.
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transmission provider to include, to the
extent it is consistent with good utility
practice, the potential counterflows
created by the clustered requests. We do
not agree, as suggested by commenters,
that clustering necessarily leads to one
set of transmission customers
subsidizing another set of transmission
customers.
1371. We therefore require each
transmission provider to include tariff
language in its compliance filing that
describes how it will process a request
to cluster request studies and how it
will structure the transmission
customers’ obligations when they have
joined a cluster. We will give the
transmission provider discretion to
determine whether a transmission
customer can opt out of a cluster and
request an individual study. We are
giving each transmission provider
discretion to develop the clustering
procedures it will use because we
believe the transmission provider is in
the best position to determine the
clustering procedures that it can
accommodate. We also believe that the
transmission provider is in the best
position to develop a clustering
procedure that prevents a transmission
customer from strategically selecting the
clusters in which it participates in an
attempt to avoid responsibility for
needed transmission system upgrades.
(6) Standardization of Business
Practices for Study Queue Processing
NOPR Proposal
1372. In the NOPR, the Commission
sought comment on whether additional
standardization of request queue
processing is necessary. If so, the
Commission sought comment on the
specific issues commenters believe are
not clearly prescribed in Order No. 676
or the NOPR and that require additional
mandatory queue processing business
practices.
Comments
1373. Several commenters identified
issues where a transmission customer
needs coordinated responses across
several transmission systems in order to
serve its load.821 Seattle and NRECA
suggest that the Commission amend the
pro forma OATT so that a customer’s
applications for service across multiple
systems that are intended to serve a
single sink from an identified resource
will be considered a single application
for purposes of establishing the
deadlines for rendering an agreement for
service, revising queue status, eliciting
deposits and finally commencing
service. Seattle believes the Commission
821 E.g.,
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should permit coordination and
implementation of these requirements
by a third party such as wesTTrans.net
and sub-regional planning
organizations. At a minimum, these
commenters ask the Commission to
develop business practices to protect a
transmission customer caught between
two systems with uncoordinated
deadlines.
1374. Exelon states that the
Commission should require all
transmission providers to allow
transmission customers to link
consecutive requests for service (e.g.,
monthly firm service requests for
December, January and February) and to
evaluate such request as a single
request. Exelon argues that this service,
which is currently provided by some
transmission providers, would increase
uniformity and use of the transmission
system, and enhance competitiveness
without burdening transmission
providers or adding administrative
complexity.
1375. TDU Systems indicate that
several of its members have experienced
difficulty related to the lack of
standardized business practices,
particularly in practices related to
timing, application requirements, and
requirements relating to methods of
proving that a network customer has
executed a power purchase agreement
prior to designating the power purchase
agreement as a network resource.
1376. PNM–TNMP does not believe
that additional clarity or business
practices are necessary beyond those
already provided in Order No. 676.
However, to the extent additional issues
arise, PNM–TNMP believes NAESB’s
WEQ forum is the appropriate place to
address them. Similarly, NorthWestern
recommends that transmission
providers work together within regional
groups to develop a common set of
business practices that will be followed
by all transmission providers within
each region, instead of the Commission
using the NOPR comments it receives to
develop a prescriptive set of business
practices by which all transmission
providers must abide. In its reply
comments, Powerex argues that either
the entire transmission process has to be
integrated via an RTO, or coordination
of requests across multiple control areas
has to be done transmission provider by
transmission provider. Powerex suggests
that NorthWestern’s suggestion for
regional development of business
practices may be a more pragmatic
approach to address concerns about
coordination of requests across multiple
systems.
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Commission Determination
1377. The Commission agrees that
transmission requests across multiple
transmission systems should be
coordinated by the relevant
transmission providers. We will not,
however, amend the pro forma OATT to
require such coordination. Rather, we
require transmission providers working
through NAESB to develop business
practice standards related to
coordination of requests across multiple
transmission systems. In order to
provide guidance to NAESB, we will
articulate the principles that should
govern processing across multiple
systems. All the transmission providers
involved in a request across multiple
systems should consider a request that
requires studies across multiple systems
to be a single application for purposes
of establishing the deadlines for
rendering an agreement for service,
revising queue status, eliciting deposits
and commencing service. In order to
preserve the rights of other transmission
customers with studies in the queue, the
priority for the single application
should be based on the latest priority
across the transmission providers
involved in the multiple system request.
We note that regional entities like
wesTTrans are already coordinating
requests across multiple transmission
systems and we believe such
coordination is an acceptable solution to
this issue.
1378. We interpret Exelon’s request
that we require all transmission
providers to allow transmission
customers to link consecutive requests
for firm point-to-point transmission
service and to evaluate such requests as
a single request as asking us to (1) allow
transmission customers to require the
transmission provider to either grant
service for the entire period, deny
service for the entire period, or offer the
same partial quantity for the entire
period and (2) require the transmission
provider to consider the full duration of
the linked requests when determining
reservation priority pursuant to sections
13.2 of the pro forma OATT (short-term
firm point-to-point transmission
service). We require transmission
providers working through NAESB to
develop business practice standards to
allow a transmission customer to rebid
a counteroffer of partial service so the
transmission customer is allowed to
take the same quantity of service across
all linked transmission service requests.
Transmission providers need not
implement these business practice
standards until NAESB develops
appropriate standards. We note that the
transmission customer should not be
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required to take the same quantity of
service across consecutive transmission
service requests, it should simply have
the option to do so. On the second issue,
we reiterate that, according to existing
NAESB business practice standard 001–
4.16, the transmission provider is
required to consider the full duration of
the linked requests when determining
reservation priority pursuant to section
13.2 of the pro forma OATT.
1379. We believe most of the
standardization issues TDU Systems
raise (application requirements,
requirements relating to methods of
proving that a network customer has
executed a power purchase agreement
prior to designating the power purchase
agreement as a network resource, and
timing) have been addressed in this
Final Rule. In particular, we describe
the information a network customer is
required to provide when designating a
new network resource in section V.D.6.b
of this Final Rule. We also indicate in
section V.D.6.b that the transmission
provider is not allowed to require a
network customer to provide contract
terms and conditions when it designates
a power purchase agreement as a
network resource. The network
customer is required to provide a
statement that attests, among other
things, that it has executed a power
purchase agreement prior to confirming
its request to designate a new network
resource. We will continue to give
transmission providers discretion in
determining whether to impose
restrictions on the earliest time at which
it will accept a request for transmission
service. We believe the transmission
provider is in the best position to
determine whether it needs to restrict
the time at which it will accept requests
for transmission service in order to
process transmission service requests in
an orderly fashion consistent with the
requirements in the pro forma OATT.
(7) Additional Processing Proposals
Comments
1380. A number of commenters
propose changes to queue processing
requirements that were not addressed in
the NOPR.
1381. Powerex believes that OASIS
practices should be modified to ensure
that short-term firm and non-firm pointto-point service requests are processed
based on the ATC posted at the time the
requests were queued. Powerex argues
that a transmission provider should not
be permitted to grant transmission
service requests at a time when its
OASIS indicates there is no ATC. In its
view, any such requests should be
automatically denied. Powerex also
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12445
suggests that confirmation time periods
be shortened for short-term firm pointto-point service requests to discourage
behaviors that have the effect of
delaying queue processing. In its reply
comments, Powerex asserts that
requiring transmission provider
responses to be based on posted ATC, as
well as increasing standardization in
transmission provider response time for
short-term transmission requests, would
enhance a transmission customer’s
ability to manage multiple transmission
provider requests within the context of
the pro forma tariff.
1382. Occidental suggests in reply
that the Commission should introduce
meaningful tariff-based sanctions for
unauthorized deviations from the
standards and modeling assumptions it
proposes to include in Attachment C of
the pro forma OATT, the transmission
provider’s description of its ATC
calculation methodology.
1383. Several commenters make
suggestions to allow the transmission
provider to terminate idle transmission
service requests. TDU Systems
recommends that the Commission
provide a sunset date by which all
requests not pursued by the
transmission customer would be
terminated. MidAmerican and
Northwest IOUs ask the Commission to
clarify in the Final Rule that the
transmission provider may deem a
transmission service application
withdrawn and terminated if a customer
revises its application or if such
customer fails to timely pay the annual
reservation fee pursuant to section 17.7
of the pro forma OATT.
1384. Constellation asks the
Commission to require transmission
providers to release study results as
soon as a study is completed, rather
than holding them until the end of the
60 days.
1385. NorthWestern believes an
appropriate modification to the study
process would be to allow the
transmission provider to have an
opportunity to verify and correct the
system impact study results at the
beginning of the facilities study and
again before construction begins.
1386. With the exception of very
short-term transmission service (for
which a bid-based system is impractical
to manage), LDWP suggests that the
queue process be transformed into a
competitive process in which awards of
transmission service are allocated in a
manner similar to the provisions in
section 4.4 of Order No. 638.
1387. TranServ notes that OASIS
standards allow the customer to turn a
request into a pre-confirmed request,
but not vice versa. If the Commission’s
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proposal on granting priority to preconfirmed requests is adopted, TranServ
believes this capability should be
removed from OASIS as it would seem
to invite gaming and confuse
transmission providers attempting to
process requests in proper queue order.
1388. PGP states that OASIS platforms
should be accessible from different
computer platforms using a variety of
browsers, not just one operating system/
browser combination (Windows/
Explorer), which is currently the case.
Commission Determination
1389. We will not adopt Powerex’s
proposal to require the transmission
provider to accept or deny in all cases
non-firm and short-term firm point-topoint transmission service requests
solely based on posted ATC. The issue
Powerex raises is ultimately a question
of how the transmission provider is
going to exercise its discretion under the
tariff. Under the pro forma OATT, the
transmission provider can use its
knowledge of the system to exercise its
discretion to offer transmission service
even if posted ATC is not sufficient to
accommodate the requested service.
Alternatively, the transmission provider
can use its discretion to update posted
ATC in response to a transmission
customer’s verbal request to update
ATC.822 In both situations, the
transmission provider may provide
transmission service in instances when
posted ATC is not sufficient to
accommodate a transmission service
request at the time the transmission
customer requests service. We do not
wish to discourage transmission
providers from making transmission
service available at times when posted
ATC is not accurate. Therefore, we will
continue to allow the transmission
provider to accept transmission service
requests in instances when posted ATC
is not sufficient but the transmission
provider believes it can accommodate
the service. The transmission provider
must use its discretion to grant service
when posted ATC is not sufficient on a
non-discriminatory basis. In order to
ensure that it does so, we expect the
transmission provider to log such
instances as an act of discretion and
post the log as required in section
37.6(g)(4) of the Commission’s
regulations.823
1390. We will not modify the pro
forma OATT to address requests to
allow the transmission provider to
terminate idle transmission service
requests. NAESB’s business practice
822 See, e.g., Florida Power Corp., 111 FERC ¶
61,243 at P 5 (2005).
823 18 CFR 37.6(g)(4).
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001–4.11 allows the transmission
provider to retract a request if the
transmission customer does not respond
to an acceptance within the time
established in NAESB business practice
standard 001–4.13. Therefore, we
interpret TDU Systems comments to
refer to circumstances when a
transmission customer fails to respond
to the transmission provider’s request
for additional information during the
course of a request study. As discussed
above, by the time the transmission
provider offers a system impact study
agreement, it should have all of the
information that it needs to complete
the study. Pursuant to section 17.4 of
the pro forma OATT, the transmission
provider can deem a transmission
service request deficient if the
transmission customer does not provide
all of the information the transmission
provider needs to evaluate the request
for service. We will revise section 17.7
of the pro forma OATT so that the
transmission provider is able to
terminate a request for transmission
service if a transmission customer that
is extending the commencement of
service does not pay the required annual
reservation fee within 15 days of
notifying the transmission provider that
it would like to extend the
commencement of service. We will not
change the pro forma OATT to allow the
transmission provider to terminate a
transmission service request if the
transmission customer changes its
application for service. We believe the
existing pro forma OATT is sufficient to
allow a transmission provider to manage
situations where the transmission
customer modifies its application for
service to the point that the customer is
requesting transmission service that is
meaningfully different than its initial
request.
1391. We clarify that sections 19.3
and 32.3 of the pro forma OATT require
the transmission provider to release
study results as soon as a study is
completed, rather than holding them
until the end of the 60 days.
1392. Commenters also suggest
changes to the OASIS protocols,
including prohibiting transmission
customers from changing a request into
a pre-confirmed request and requiring
OASIS platforms to be accessible on
non-Windows/Explorer computers. We
believe these issues are best addressed
by NAESB.
1393. Commenters proposed a
number of additional modifications to
the pro forma OATT that we do not
believe are necessary. These proposals
would (1) allow the transmission
provider to verify and correct studies
between each step in the study process,
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(2) transform the queue process into
competitive process, (3) shorten the
confirmation time periods for short-term
firm point-to-point service requests and
(4) introduce penalties when the
transmission provider deviates from the
ATC calculation procedures detailed in
Attachment C of the pro forma OATT.
We believe the pro forma tariff is just
and reasonable without such
modifications and the commenters have
not demonstrated that reforms in these
areas are required at this time to prevent
the exercise of undue discrimination.
b. Reservation Priority
1394. Section 13.2 of the pro forma
OATT requires transmission providers
to process requests for long-term firm
point-to-point service on a first-come,
first-served basis and to process requests
for short-term firm point-to-point
service on a first-come, first-served basis
conditional on the duration of the
request. Section 14.2 of the pro forma
OATT requires transmission providers
to process requests for non-firm pointto-point service on a first-come, firstserved basis conditional on the duration
of the request to the extent transmission
capacity beyond that needed by native
load customers, network customers and
firm point-to-point transmission
customers is available. In the NOPR, the
Commission made a number of
proposals and requested comment
regarding various aspects of the
reservation priority rules.
(1) Priority for Pre-confirmed Requests
NOPR Proposal
1395. In the NOPR, the Commission
proposed to change the priority rules to
give priority to pre-confirmed requests
for firm point-to-point transmission
service. Specifically, the Commission
proposed that a pre-confirmed shortterm request for firm transmission
service would preempt any non-preconfirmed short-term requests,
regardless of duration. Similarly, the
Commission proposed that a preconfirmed request for long-term firm
transmission service would preempt a
request for long-term transmission
service that is not pre-confirmed. Under
the Commission’s proposal, a preconfirmed request for short-term
transmission service would not preempt a non-pre-confirmed request for
long-term transmission service.
Comments
1396. A number of commenters
generally support the Commission’s
proposal to give priority to pre-
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confirmed requests.824 Commenters who
support the proposal note that giving
reservation priority to pre-confirmed
requests for transmission service could
help alleviate the problems that arise
when a transmission customer submits
multiple identical requests for service
with no intention of confirming all
accepted requests.825 Supporters of the
proposal also note that the proposal
would allow the transmission provider
to focus its attention on those requests
that appear most likely to result in an
actual reservation of transmission
service.826 Although Nevada Companies
do not oppose the proposal, they note
that concerns regarding withdrawal of
pre-confirmed requests might otherwise
be alleviated by requiring a nonrefundable deposit on requests.
1397. Several commenters suggest
that establishing reservation priority
first based on pre-confirmation status
and then based on duration would
ultimately result in transmission
customers with relatively shorter term
requests getting transmission service
instead of transmission customers with
relatively longer term requests.827 EEI
asserts that this result would be
inconsistent with the Commission’s
desire to promote longer-term uses of
the transmission system. Several
transmission providers suggest that the
Commission modify its proposal to
ensure that longer duration requests
continue to have a priority over shorter
duration requests.828 EEI suggests that
the Commission should use preconfirmation as a tie-breaker for shortterm requests for transmission service
with the same duration. Southern argues
further that a pre-confirmed daily or
hourly request should not preempt a
weekly request that has not been preconfirmed.
1398. Opponents of the proposal
identify a number of operational
difficulties in implementing a system
that gives priority to pre-confirmed
requests. Several commenters note that
transmission customers are not bound to
take service because they pre-confirm a
request for transmission service.829
They argue, for instance, a transmission
customer is not bound to take service in
the event the transmission provider
offers a study or counteroffers the
request with a partial quantity of
service. Similarly, MidAmerican notes
that a transmission customer may
824 E.g., Nevada Companies, Seattle, LDWP, PGP,
PNM–TNMP, Salt River, and Suez Energy NA.
825 E.g., Ameren, Santa Clara, Entegra, Entergy,
and TVA.
826 E.g., Ameren and NorthWestern.
827 E.g., CREPC and EEI.
828 E.g., Entergy, Southern, and NorthWestern.
829 E.g., Bonneville and EEI.
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withdraw a pre-confirmed request for
transmission service at any time prior to
acceptance by a transmission provider.
Opponents also argue that giving
priority to pre-confirmed requests
would disrupt the study process.830
This disruption would occur when a
transmission provider receives a preconfirmed request for transmission
service while it is actively studying a
request for service that has not been preconfirmed. Under these circumstances,
the transmission provider would be
required to suspend the study of one
request in order to study a request with
a higher reservation priority. In its reply
comments, Indianapolis Power asks the
Commission to clarify if this
interpretation of the NOPR proposal is
accurate. TranServ, suggesting that the
Commission has not proposed to give a
priority to pre-confirmed requests for
non-firm transmission service, asserts
that having different priority rules for
firm and non-firm transmission service
introduces unnecessary complexity.
Finally, Southern believes that a preconfirmed service request submitted
within close proximity to the actual
commencement of service should not
preempt an existing non-pre-confirmed
request, if doing so would be disruptive
to the operations of the transmission
provider or to the reliability of the
system itself.
1399. Opponents also argue that
giving a priority to pre-confirmed
requests would unfairly disadvantage
transmission customers who are not in
a position to pre-confirm their requests,
such as those requesting service in
response to a request for proposals.831
EEI notes that the Commission
addressed this issue when it issued
Order No. 638 and decided that giving
priority to pre-confirmed requests
would disadvantage customers who are
requesting service from multiple
transmission providers.832 In the event
the Commission decides to proceed
with its proposal, TAPS suggests that
the Commission limit the priority for
pre-confirmed requests to non-firm and
short-term firm requests for
transmission service.
1400. Several commenters question
whether a request that has been
accepted but not confirmed would be
pre-empted by a new pre-confirmed
request.833 In a similar vein, TDU
Systems suggests that the Commission
830 E.g.,
Bonneville, EEI, and MidAmerican.
EEI, MISO, TAPS, Constellation, and
TDU Systems.
832 Open Access Same-Time Information System
and Standards of Conduct, Order No. 638, 65 FR
17370, FERC Stats. & Regs., ¶ 1996–2000 ¶ 31,093
at 31,439 (2000).
833 E.g., MidAmerican and TranServ.
831 E.g.,
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12447
include a time window between
acceptance of a request and
confirmation of the request, during
which a request can not be preempted
by a pre-confirmed request for
transmission service.
Commission Determination
1401. The Commission generally
agrees with those commenters that argue
that giving a priority to pre-confirmed
requests can increase the efficient
utilization of the system by giving
priority to customers who are
committed to purchase service over
those who have not so committed,
including customers that submit
multiple requests without any intent to
take service if each request is granted.
However, we are mindful of concerns
that doing so could undermine the
Commission’s desire to promote longerterm uses of the transmission system,
disrupt the study process, or
disadvantage transmission customers
that are not in the position to preconfirm their requests. As a result, we
will modify the NOPR proposal and give
priority only to pre-confirmed non-firm
point-to-point transmission service
requests and short-term firm point-topoint transmission service requests. In
addition, longer duration requests for
transmission service will continue to
have priority over shorter duration
requests for transmission service, with
pre-confirmation serving as a tie-breaker
for requests of equal duration. This
policy will still give an advantage to
pre-confirmed requests without
imposing substantial implementation
difficulties or undermining the
Commission’s goals to encourage longerterm uses of the transmission system.
Our revised policy on priority for preconfirmed requests thus addresses the
comments that we should preserve the
priority of longer duration requests for
transmission service over shorter
duration requests for transmission
service. For instance, a pre-confirmed
daily or hourly request will not preempt
a weekly request that has not been preconfirmed. Pre-confirmed short-term
service requests therefore will not have
a priority superior to that of long-term
service requests that have not been preconfirmed.
1402. We acknowledge that our
revised policy on priority for preconfirmed requests may be less effective
than the NOPR proposal in alleviating
the problems that arise when
transmission customers submit multiple
identical requests for service. However,
we have taken other steps—notably
accepting the NAESB business practices
on queue flooding and queue
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hoarding 834—that we believe will
substantially reduce the instances of
multiple identical requests for service.
1403. The Commission also
acknowledges the concerns expressed
regarding operational difficulties caused
by giving priority to pre-confirmed
requests and clarify our policy as
follows. First, we will prohibit
transmission customers from
withdrawing pre-confirmed non-firm
and short-term firm point-to-point
transmission service requests prior to
when the transmission customer is
offered service or a system impact
study. This policy will address
MidAmerican’s concern that a
transmission customer may withdraw a
pre-confirmed request for transmission
service at any time prior to acceptance
by a transmission provider. We believe
prohibiting withdrawal of a preconfirmed request is less
administratively burdensome than the
non-refundable deposit on requests
proposed by Nevada Companies and
achieves the same goals. The
Commission will allow transmission
providers to invalidate a pre-confirmed
request at the request of the
transmission customer in the very near
term following submittal of the request,
in the event the transmission customer
makes an inadvertent error in
submitting its request. We expect the
transmission provider to log such
occurrences as an act of discretion so we
can verify that transmission customers
are not abusing this flexibility.
1404. Second, while the Commission
recognizes that a customer submitting a
pre-confirmed request is not bound to
take service when the transmission
provider counteroffers the transmission
customer’s initial request, we do not
believe this fact alone warrants
reversing our proposal to give a priority
to pre-confirmed requests. We are
satisfied that a transmission customer
that pre-confirms its request is obligated
to take full service in the event the
transmission provider offers the service
requested.
1405. The Commission also believes
the revised priority policy will address
Southern’s comment that a preconfirmed service request submitted
within close proximity to the actual
commencement of service should not
preempt an existing non-pre-confirmed
request if doing so would be disruptive
to the operations of the transmission
provider or to the reliability of the
system itself. A pre-confirmed request
for transmission service will not preempt an equal duration request that has
already been confirmed. Therefore, the
834 See
Order No. 676 at P 19.
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effects of the priority for pre-confirmed
requests will be resolved prior to the
time when the transmission provider
would require an accepted request to be
confirmed. Handling priority for preconfirmed requests should be no more
disruptive than giving a transmission
customer time to confirm an accepted
request.
1406. Excluding long-term requests
for transmission service will mitigate
many of the concerns expressed by
commenters who argued that giving a
priority to pre-confirmed requests will
unfairly disadvantage transmission
customers who are requesting service in
response to a request for proposals and
are therefore not in a position to preconfirm their requests. Such requests for
proposals typically involve long-term
contracts for energy and/or generating
capacity and, therefore, would be linked
most likely to long-term transmission
service requests. We disagree, however,
with EEI’s characterization of the
Commission’s decision in Order No. 638
to give a priority to pre-confirmed
requests for non-firm service only if the
request offers a higher price. The
Commission’s decision in that
proceeding was driven by its
interpretation that the proposed
business practice addressed in the part
of Order No. 638 cited by Southern was
not consistent with the relevant section
of the pro forma tariff. In addition, the
Commission’s experience since Order
No. 638 and the comments received to
the NOPR proposal indicate the value of
giving a priority to pre-confirmed
requests, despite concerns that some
transmission customers are not in a
position to pre-confirm their requests
for transmission service.
1407. In response to requests for
clarification from MidAmerican and
TranServ, we clarify that a new preconfirmed request for transmission
service would preempt a request of
equal duration that has been accepted
by the transmission provider but not yet
confirmed by the transmission
customer. Thus, we decline to adopt
TDU Systems’ suggestion that the
Commission include a time window
between acceptance of a request and
confirmation of the request, during
which a request can not be preempted
by a pre-confirmed request for
transmission service. This is consistent
with our desire to give transmission
service first to those customers that are
committed to taking the transmission
service if it is granted. In the case of
monthly firm point-to-point
transmission service, the transmission
customer has up to four days to confirm
an accepted request. This is a
potentially long delay when there is
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another transmission customer that is
willing to commit to take the same
service. Moreover, this policy is
consistent with NAESB business
standard 001–4.25, which allows a preconfirmed request for non-firm point-topoint transmission service to preempt a
request of equal duration and lower
price that has been accepted but not
confirmed.835
(2) Price as a Tie-Breaker
NOPR Proposal
1408. The NOPR also proposed to add
price as a tie-breaker in determining
reservation queue priority when the
transmission provider is willing to
discount transmission service. Under
the Commission’s proposal, price would
serve as a tie-breaker after preconfirmation for those requests that are
not yet confirmed.
Comments
1409. All of the commenters who
address the Commission’s proposal to
add price as a tie-breaker support the
proposal, although some request that it
be modified or clarified. Several
commenters ask the Commission to
clarify that an otherwise higher queued
request has a right to match the price
offer of a request with a higher price.836
With regard to short-term service,
WAPA believes that the Commission’s
proposal to add price as a tie-breaker
would overly complicate matters after
taking into account the many complex
timing restrictions on short-term
service. As a result, WAPA proposes
that the Commission limit application of
its proposal to requests for long-term
transmission service. MISO/PJM States
suggest that the Commission consider
requiring point-to-point transmission
customers to offer a reservation price at
which they would be willing to sell
their transmission service.
Commission Determination
1410. The Commission adopts the
NOPR proposal to add price as a tiebreaker in determining reservation
queue priority when the transmission
provider is willing to discount
transmission service. As a result, price
will serve as a tie-breaker after preconfirmation for those requests that
have not yet been confirmed by the
transmission customer or have not yet
been evaluated by the transmission
provider. Consistent with the principles
currently embodied in the pro forma
OATT and articulated in Order No. 638,
we clarify that, in the event a later
queued short-term request for
835 See
Order No. 676.
EEI and MidAmerican.
836 E.g.,
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transmission service preempts a
conditional confirmed short-term
request for transmission service based
on price, then the conditional confirmed
request has a right to match the price
offer of the later queued request.837
1411. We disagree with WAPA’s
proposal to limit application of the
NOPR proposal to requests for long-term
transmission service. We believe the
addition of price as a tie-breaker for
discounted firm point-to-point
transmission service is an economically
efficient policy for both short-term and
long-term firm point-to-point
transmission service. We recognize that
adding another element to the
reservation priority criteria adds
additional complexity. However, we
believe that the efficiency gains warrant
any additional complexity in the few
cases in which transmission customers
bid for transmission service.
1412. We do not agree with MISO/
PJM States’ suggestion that the
Commission require point-to-point
transmission customers to offer a
reservation price at which they would
be willing to sell their transmission
service. The transmission provider may
already make unscheduled firm
transmission service available to other
customers on a non-firm basis and we
have adopted proposals that we believe
will encourage transmission customers
to voluntarily offer to sell firm point-topoint transmission service on the
secondary market as described in
section V.C.4 of this Final Rule. As a
result, we see no reason to require a firm
point-to-point customer to offer its
reserved capacity for sale.
(3) Five-Minute Window for Requests
sroberts on PROD1PC70 with RULES
NOPR Proposal
1413. In the NOPR, the Commission
responded to comments that
transmission customers that have the
financial resources to purchase software
and employ staff to continually monitor
OASIS sites have an unfair advantage
under a first-come, first-served approach
by seeking comment on whether any
such advantage would be mitigated if all
requests submitted within a five-minute
window were deemed to have been
submitted simultaneously. The
Commission also sought comment on
whether transmission customers could
game a five minute equivalent priority
standard to request transmission service
only after another transmission
customer has made a request. The
Commission further sought comment on
how to allocate limited transmission
capacity among equivalent priority
837 See
Order No. 638 at 31,442.
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requests of equal duration, in the event
a five minute equivalent priority
standard is adopted.
Comments
1414. Many of the commenters in the
West support the proposal to treat
transmission requests submitted within
some specified period of time as
submitted simultaneously. Supporters
of a time window within which all
requests would be deemed to have been
submitted simultaneously argue that the
proposal would give transmission
customers who are less sophisticated
and have fewer financial resources
equal access to transmission service.838
Other supporters argue that such a time
window would be particularly
appropriate in circumstances when a
tariff calls for requests to be submitted
‘‘no earlier than’’ a specific deadline.839
In its reply comments, NRECA argues
that a customer attempting to plan a
request under such circumstances may
miss being the first in time by a matter
of seconds because its computer is
slower than another customer’s
computer.
1415. Supporters of the proposal
suggest a number of modifications to the
Commission’s suggested five-minute
window. A number of commenters
suggest a window longer than five
minutes.840 For instance, Bonneville
proposes a system similar to PJM’s 30
minute window for monthly service. On
the other hand, Manitoba Hydro
suggests a shorter window and a limit
on the number and size of requests,
claiming this would reduce the
potential for gaming and/or anticompetitive behavior. A number of
commenters also suggest that such a
system should be limited to short-term
transmission service 841 and/or should
not apply to requests for transmission
service submitted close to the hour that
service commences.842 In its reply
comments, PNM–TNMP asserts that, if
the Commission implements a fiveminute window policy, then the policy
should not be limited to long-term
transactions. In its reply comments,
NRECA argues that requests submitted
within a five-minute window should
not be publicly available until the
window has closed in order to prevent
competitors from requesting the same
service simply to disrupt the
transmission service procurement
process. Similarly, Bonneville suggests
that the reservation process should be
838 E.g.,
Bonneville and Santa Clara.
TDU Systems and NRECA.
840 E.g., Bonneville and CREPC.
841 E.g., Bonneville and Nevada Companies.
842 E.g., Bonneville and NRECA.
839 E.g.,
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12449
conducted like a blind auction, so that
requests are not visible on OASIS until
the window closes.
1416. Many of the large power
marketers and transmission providers in
the East oppose the notion of a
submittal window. Opponents of a time
window within which all requests
would be deemed to have been
submitted simultaneously suggest that
the proposal is an unnecessary
complication and may actually be
counterproductive to the Commission’s
ultimate goal due to issues regarding
how transmission service would be
allocated among simultaneous
requests.843 EEI notes that there is no
limit on how far in advance a
transmission customer may submit
requests for firm transmission service,
so the likelihood that any two requests
are submitted within the same five
minute period is low. Powerex argues
that the simplicity of the first-come, first
served approach limits the number of
disputes. In its reply comments,
Powerex argues that none of the
commenters that favor a five-minute
window addressed the operational
problems that such a proposal would
generate.
1417. Some commenters argue that a
pro rata allocation of simultaneous
requests of equal duration will result in
all transmission customers acquiring
less transmission service than they need
to complete their wholesale
transactions.844 As a result, these
commenters suggest that the need to
provide transmission customers with
usable quantities of transmission service
will necessarily lead to developing an
allocation protocol in addition to
allocating based on time submitted and
duration of request.845 Powerex argues
that any system that creates a time
window within which all requests
would be deemed to have been
submitted simultaneously will lead
transmission customers to inflate the
quantity of service they request in order
to get quantity of service they actually
desire. Other commenters make
suggestions regarding the manner by
which transmission service should be
allocated among simultaneously
submitted requests. Bonneville believes
that each transmission provider should
develop an allocation method
appropriate to its system. CREPC
suggests that price be used as a
secondary tie-breaker after duration.
TDU Systems argue that using duration
843 E.g., EEI, MidAmerican, Ameren,
Constellation, Entergy, NorthWestern, PNM-TNMP,
WAPA, Powerex, and Indianapolis Power Reply.
844 E.g., Powerex and TranServ.
845 Id.
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as a tie-breaker for simultaneous
requests could discriminate against
purchased power contracts that are
designated as network resources.
Commission Determination
1418. Based on the comments
received, it appears that the desire for a
time window within which all requests
would be deemed to have been
submitted simultaneously is largely
limited to market participants in the
Western Interconnection. With one
exception, we will not mandate a
change to our current first-come, firstserved policy to address an issue that
appears to be regional in nature. Rather,
we will allow transmission providers to
propose a window within which all
transmission service requests the
transmission provider receives will be
deemed to have been submitted
simultaneously. Transmission providers
will have discretion to determine which
transmission services will be subject to
a submittal window policy. We believe
the transmission provider is in the best
position to determine whether it can
accommodate a submittal window for a
specific transmission service and the
need for such a window.
1419. In order to ensure that
transmission service is not awarded in
an arbitrary fashion and to ensure that
transmission customers who are less
sophisticated and have fewer financial
resources have equal access to
transmission service, we will require
transmission provider who set a ‘‘no
earlier than’’ time for request submittal
to treat all transmission service requests
received within a specified period of
time as having been received
simultaneously. We agree with those
commenters that argue that a time
window within which all requests
would be deemed to have been
submitted simultaneously is particularly
appropriate in circumstances when a
tariff or business practice calls for
requests to be submitted no earlier than
a specific deadline. As NRECA argues,
there is no meaningful difference
between requests for transmission
service that are identical in all respects
except that one request is received by
the transmission provider seconds
ahead of another request because one
customer’s computer is slower than
another customer’s computer. EEI is
correct that NAESB’s uniform business
practices do not limit how far in
advance a transmission customer may
submit requests for firm transmission
service.846 However, a number of
transmission providers have modified
846 See
NAESB Business Practice Standard 001–
4.13.
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their tariffs or adopted business
practices that mandate that requests can
be submitted no earlier than a specific
deadline.847 In these instances, multiple
requests for transmission service can be
submitted at approximately the same
time. We generally agree with Powerex’s
assertion that the simplicity of the
current first-come, first served approach
limits the number of disputes. However,
when a transmission provider
establishes a ‘‘no earlier than’’ deadline,
submittals that are received by the
transmission provider within a matter of
seconds cannot be meaningfully
differentiated. A transmission provider
with such a business practice or tariff
provision will be required to modify its
tariff to include its proposed specified
period of time. We will evaluate each
proposal on a case-by-case basis, as
described below.
1420. We will allow transmission
providers to propose the period of time
within which all requests would be
deemed to have been submitted
simultaneously. We believe the
transmission provider is in the best
position to identify the window it can
operationally accommodate. We expect
the submittal window to be open for at
least five minutes unless the
transmission provider can present a
compelling rationale to justify a shorter
submittal window.
1421. We agree with NRECA and
Bonneville’s suggestion that requests
submitted within a specified window
should not be publicly available until
the window has closed in order to
prevent competitors from requesting the
same service simply to disrupt the
transmission service procurement
process.
1422. We will require each
transmission provider that is required
to, or decides to, deem all requests
submitted within a specified period as
having been submitted simultaneously
to propose a method for allocating
transmission capacity if sufficient
capacity is not available to meet all
requests submitted within the specified
time period. We agree with Bonneville
that the transmission provider is in the
best position to determine an allocation
that is appropriate to its system and that
847 For instance, Idaho Power Company has
adopted a business practice that requests for
monthly firm transmission service cannot be
submitted earlier than 11 months prior to operation.
Portland General Electric has adopted a business
practice that Daily Firm ATC on the CaliforniaOregon Intertie will be posted at or about 7:11 a.m.
Pacific on the day prior to operation and that
requests that are submitted prior to ATC being
posted will be refused. SPP has modified its tariff
so that requests for monthly firm transmission
service cannot be submitted more than 90 days
prior to the first day of operation.
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cannot be gamed in the manner
suggested by Powerex and TranServ. We
believe that transmission providers will
be able to develop allocation methods,
like the method PJM uses to allocate
monthly firm point-to-point
transmission service, that address the
operational issues Powerex and
TranServ raise.
(4) Right of First Refusal and
Preemption
1423. While not specifically
addressed in the NOPR, a few
commenters use the Commission’s
proposed introduction of hourly firm
service, discussed above, to argue that
the Commission should take the
opportunity to clarify or revise the right
of first refusal for short-term
transmission service requests.
1424. To understand commenter
concerns, it is useful to note the relevant
components of the reservation and
scheduling process in the pro forma
OATT. Reservations for short-term firm
point-to-point transmission service are
available on a first-come, first-served
basis and are conditional based upon
the length of the requested transaction
as explained further below. If the
transmission system becomes
oversubscribed, longer-term service may
preempt shorter-term service, up to a
specified period. The shorter-term
reservation holder has a right of first
refusal to match the longer-term
reservation, but such right must be
exercised within 24 hours of being
notified of the competing reservation, or
earlier to comply with the scheduling
deadline.
Comments
1425. Salt River argues that the time
required to administer the right of first
refusal—which includes contacting
customers and allowing time to exercise
the right of first refusal—is
overwhelming. Salt River argues that the
current OASIS business practices do not
permit adequate time to implement
these rules, and the industry lacks the
software to either streamline the effort
or ensure quality control. Salt River
contends that for hourly, daily, and
weekly requests, the complexity and
potentially unjust results of
administering preemption and the right
of first refusal rules outweighs any
potential benefits. Accordingly, Salt
River recommends revisions to the pro
forma OATT that make the right of first
refusal available only to monthly
requests for service.
1426. To address the complications
arising from preemption and the right of
first refusal, Duke proposes several
revisions to the pro forma OATT: only
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pre-confirmed requests would trigger
preemption; confirmed requests could
not be displaced by longer-term
requests; only monthly customers
subject to preemption would be given a
right of first refusal (Salt River proposes
a similar OATT revision); and, profiled
requests (i.e., requests for transmission
that may have different MW values for
each hour of the day, and may even
include some hours where the MW
value is zero) would not be granted
priority over confirmed reservations.
TranServ also asks the Commission to
provide guidance establishing the
earliest and latest submission times and
maximum successive or consecutive
terms of service required. TranServ
contends it is unreasonable that a
request for daily firm service could be
submitted years in advance and then
have a right of first refusal to match any
longer-term request for service.
1427. To eliminate the potential for
more complexity, TranServ requests that
the Commission eliminate the
conditional nature of short-term pointto-point service under the OATT.
Whether the Commission adopts this
recommendation, TranServ further
recommends that the Commission revise
the timing provisions for requesting
short-term point-to-point service to
reduce overlap for submission of
requests that would trigger the need for
preemption. TranServ and Duke
recommend a reservation or bidding
process in which one increment of
service (monthly, weekly, daily, and
hourly) is available at a time, with each
successive shorter increment of service
becoming available after the reservation
or bidding window for the preceding
longer increment has closed.
1428. NorthWestern requests that the
Commission clarify whether the terms
‘‘reservation’’ and ‘‘request’’ used in
section 13.2 (Reservation Priority) are
used interchangeably. If they are not
used interchangeably, and ‘‘reservation’’
is meant to be a confirmed request,
while ‘‘request’’ is a queued request that
has not been confirmed, NorthWestern
suggests that the sentence that includes
the two uses of ‘‘reservation’’ creates
confusion because, if both requests are
confirmed, then either sufficient
capacity exists to accept both requests,
or the transmission provider accepted
requests that exceed the ATC. To avoid
confusion, then NorthWestern
recommends that the second use of
‘‘reservation’’ should be changed to
‘‘request.’’ If so, to avoid the suggestion
that the section is attempting to
distinguish between requests that have
been confirmed from those simply
queued, NorthWestern recommends that
the Commission consider changing all
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of the ‘‘reservation’’ references to
‘‘request.’’
Commission Determination
1429. Based on the issues raised in
comments, we find that changing the
‘‘first come, first served’’ nature of the
reservation process and right of first
refusal process is not warranted at this
time. The ‘‘first-come, first-served’’
principle facilitates the administration
of the reservation process and benefits
customers because there can be little
confusion about how to comply with it.
1430. The remaining concerns
regarding administering the right of first
refusal are addressed below. First, when
a longer-term request seeks capacity
allocated to multiple shorter-term
requests, the shorter-term customers
should have simultaneous opportunities
to exercise the right of first refusal.
Duration, pre-confirmation status, price,
and time of response would then be
used to determine which of the shorterterm requests will be able to exercise the
right of first refusal, consistent with the
Commission’s tie breaking provision in
section 13.2(ii). Second, to minimize the
potential for gaming, a preempting
longer request must be for a fixed
capacity over the term of the request.
1431. We agree with NorthWestern’s
assertion that the sentence in section
13.2(iii) of the pro forma OATT that
includes the two uses of ‘‘reservation’’
creates confusion. Therefore, we clarify
that the terms ‘‘reservation’’ and
‘‘request’’ are not used interchangeably;
‘‘reservation’’ is meant to be a confirmed
request, while ‘‘request’’ is a queued
request that has not been confirmed. To
clarify the distinction between use of
the terms ‘‘request’’ and ‘‘reservation’’
in section 13.2(iii), we will revise that
section so that the sentence ‘‘Before the
conditional reservation deadline, if
available transfer capability is
insufficient to satisfy all Applications,
an Eligible Customer with a reservation
for shorter-term service has the right of
first refusal to match any longer-term
reservation before losing its reservation
priority’’ is replaced by the sentence
‘‘Before the conditional reservation
deadline, if available transfer capability
is insufficient to satisfy all Applications,
an Eligible Customer with a reservation
for shorter-term service has the right of
first refusal to match any longer-term
request before losing its reservation
priority.’’
6. Designation of Network Resources
a. Qualification as a Network Resource
1432. Taken together, the following
sections of the pro forma OATT
describe the resources a network
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12451
customer can appropriately designate as
a network resource. Section 30.1 of the
pro forma OATT describes network
resources as all generation owned or
purchased by the network customer
designated to serve network load under
the tariff. Section 30.1 also indicates
that network resources may not include
resources that are committed for sale to
non-designated third-party load or
otherwise cannot be called upon to meet
the network customer’s network load on
a noninterruptible basis. Pursuant to
section 30.7 of the pro forma OATT, the
network customer must demonstrate
that it owns or has committed to
purchase generation pursuant to an
executed contract in order to designate
a generating resource as a network
resource. Alternatively, the network
customer may establish that execution
of a contract is contingent upon the
availability of network service. Section
29.2 requires the network customer to
provide the following information about
a power purchase agreement that is to
serve as a new designated network
resource: source of supply, control area
location, transmission arrangements and
delivery point(s) to the transmission
provider’s transmission system.
1433. As the Commission noted in the
NOPR, a number of orders address what
types of resources meet the criteria set
out in sections 30.1 and 30.7 of the pro
forma OATT. In MSCG, the Commission
stated that network resources must be
generating resources owned by the
network customer or purchases of
noninterruptible power under executed
contracts that require the network
customer to pay for the purchase.848 In
WPPI, the Commission found that a
network customer can designate as a
network resource a system purchase that
is not backed by a specific generator.849
The Commission found that Wisconsin
Public Service Corporation (WPS) had
appropriately designated a power
purchase as a network resource, even
though the power purchase agreement
did not require WPS to take energy
around the clock and allowed WPS to
convert its energy purchase to a
discounted product that could be
interrupted.850 In addition, the
Commission stated that, because the pro
forma OATT requires a power purchase
to be noninterruptible, third-party
transmission arrangements to deliver
the resource to the network have to be
848 Morgan Stanley Capital Group v. Illinois
Power Co., 83 FERC ¶ 61,204 at 61,911–12 (1998),
order on reh’g, 93 FERC ¶ 61,081 (2000) (MSCG).
849 Wisconsin Public Power Inc. v. Wisconsin
Public Service Corp., 84 FERC ¶ 61,120 at 61,650–
51 (1998) (WPPI).
850 Id.
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noninterruptible as well.851 In Illinois
Power, the Commission found that a
firm purchase need not be backed by a
capacity purchase to qualify as a
network resource.852
NOPR Proposal
1434. In the NOPR, the Commission
proposed to maintain its current policy
regarding the power purchase
agreements that network customers may
designate as network resources. In
particular, the Commission proposed
that a network customer would continue
to be able to designate resources from
system purchases not linked to a
specific generating unit, provided the
power purchase agreement is not
interruptible for economic reasons, does
not allow the seller to fail to perform
under the contract for economic
reasons, and requires the network
customer to pay for the purchase. In
addition, the Commission reiterated that
third-party transmission arrangements
to deliver the purchase to the network
must be noninterruptible.
1435. Regarding seller’s choice
contracts, the Commission explained
that a power purchase agreement that is
structured so that a network customer
cannot specify all of the information
required by section 29.2(v) of the pro
forma OATT cannot be designated as a
network resource. Specifically, the
Commission reiterated that a request to
designate a new network resource must
provide the information including the
source of supply, control area location,
transmission arrangements, and delivery
point(s) to the transmission provider’s
transmission system. The Commission
proposed that, when designating a
system purchase as a new network
resource, a network customer must
identify the resource as a system
purchase as well as the control area
from which the power will originate.
1436. In response to suggestions that
liquidated damages (LD) products
should not be designated network
resources because they are interruptible
for economic reasons, the Commission
proposed to clarify that network
customers may not designate as network
resources those power purchase
agreements that give the seller a
contractual right to compensate the
buyer instead of delivering power even
if the seller is able to deliver power. For
instance, the Commission proposed that
a network customer may not designate
as a network resource a purchase
agreement that allows the seller to
851 Id.
at 61,660.
Power Co., 102 FERC ¶ 61,257 at P 14
(2003), reh’g denied, 108 FERC ¶ 61,175 (2004)
(Illinois Power).
852 Illinois
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interrupt sales under the purchase
agreement for reasons other than
reliability, but allows the buyer to force
delivery at a higher price. In addition,
the Commission proposed that a
network customer may not designate as
a network resource a purchase
agreement that requires a seller to pay
the buyer’s cost of replacement power
when the seller chooses not to deliver
energy for economic reasons.
Comments Overview
1437. Most commenters argue that the
Commission must provide further
clarification than given in the NOPR,
particularly with regard to the eligibility
of firm LD power products and the
information required by section 29.2(v)
of the pro forma OATT for seller’s
choice contracts. Various commenters
also argue that the Commission’s
precedent on this issue is contradictory
and that the Commission’s policy with
respect to designation of network
resources may violate section 217 of the
FPA and conflict with state jurisdiction.
(1) LD Contracts
Comments
1438. Many commenters express
general support for some or all of the
Commission’s clarifications in the
NOPR with regard to ineligibility of
resources which are interruptible for
economic reasons and/or that allow the
seller to compensate the buyer instead
of delivering power even if the seller is
able to deliver power.853 However,
many commenters express concern
about the clarity of the policy.854
1439. In particular, several parties
contend that it is in fact the firmness of
the contract and not the mere existence
of an LD provision describing the
remedies in case of a failure to perform
that determines the eligibility of a
power purchase agreement to be
designated as a network resource.855
TAPS argues that, in order to determine
the firmness of a purchase, one must
look at the criteria for excusing a failure
to supply. AMP-Ohio, MISO, and NCPA
also express support for this position,
pointing to the Commission’s finding in
853 E.g., Ameren, BART, Constellation, Duke,
Entegra, Entergy, Morgan Stanley, MISO,
NorthWestern, Progress Energy, Sempra Global,
Southern, Suez Energy NA, and TranServ.
854 E.g., AMP-Ohio, APPA, Duke, EEI, Entergy,
Fayetteville, Morgan Stanley, NCPA, Northwest
IOUs, Northwest Parties, MISO/PJM States, PGP,
Pinnacle, PNM–TNMP, Salt River, Sempra Global,
Southern, TAPS, Utah Municipals, and WSPP.
855 E.g., AMP-Ohio, Northwest IOUs, NRECA
Reply, PGP, Pinnacle, Sempra Global, Strategic
Energy Reply, and TAPS.
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Dynegy 856 that the inclusion of an LD
provision in EEI’s Master Power
Purchase and Sale Agreement’s Firm LD
product (EEI’s Firm LD Product) does
not inherently make that product less
firm.
1440. Several commenters argue that,
when the Commission in Dynegy
considered the acceptability of EEI’s
Firm LD Product as a designated
network resource, it neglected to
consider the presence of a provision
which appears to contradict its
decision.857 They point to the
Commission’s statement in Dynegy that
EEI’s Firm LD Product ‘‘does not permit
the power to be interrupted for
economic reasons, or at the discretion of
either party, but only if a force majeure
occurs.’’ 858 Some contend that the
Commission’s conclusion ignored the
fact that EEI’s Firm LD Product actually
allows power to be interrupted for any
reason, including economic reasons,
after which the agreement then provides
LDs as a remedy if the interruption was
not due to a force majeure event.859
Duke and EEI note that contracts under
EEI’s Firm LD Product agreement or
similar agreements have become
commonplace since the Commission’s
Dynegy decision and that clarification
regarding their use as network resources
is required to address industry
confusion.
1441. Several commenters disagree
that the EEI Firm LD Product gives
parties the right to interrupt for any
reason, including economic reasons,
provided that LDs are paid by the nonperforming party.860 Hoosier argues on
reply that EEI and Southern have
misunderstood the Commission’s intent
in Dynegy. Hoosier contends that the
Commission correctly found in Dynegy
that the EEI Firm LD Product does not
permit power to be interrupted for
economic reasons, or at the discretion of
either party, but only if a force majeure
event occurs. Thus, Hoosier argues, the
EEI Firm LD Product does not give the
seller a right to interrupt for any reason
other than force majeure, and any seller
that interrupts for economic reasons is
clearly in breach of its obligations to
perform under the contract and must
856 Dynegy Midwest Generation, 101 FERC
¶ 61,295 (2002), reh’g dismissed, 108 FERC ¶ 61,175
(2004) (Dynegy).
857 E.g., Duke, Dynegy Reply, EEI, and Southern.
858 Dynegy at P 21.
859 E.g., Duke, EEI and Southern. EEI notes that
its Firm LD Product is distinct from its ‘‘System
Firm’’ and ‘‘Unit Firm’’ products in its Master
Power Purchase and Sale Agreement, each of which
excuses a failure to perform only for force majeure
and neither of which permits a party to fail to
perform and pay liquidated damages.
860 E.g., Hoosier Reply, Strategic Energy Reply,
and Utah Municipals.
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pay damages. Hoosier acknowledges
that a seller always has the choice of not
performing its obligations and paying
damages, but that is not peculiar to the
EEI Firm LD Product. Hoosier maintains
that any party to any contract has the
ability, but not the right, to breach its
obligations under the contract and pay
damages. According to Hoosier, the only
difference in the case of the EEI Firm LD
Product is that the parties have
stipulated beforehand as to the measure
of the damages required of a seller in
breach, in order to minimize litigation
over damages. This stipulation, Hoosier
argues, conveys no additional
substantive rights on either party.
1442. Several parties note that firm
LD contracts account for a significant
number of currently utilized products
and that disallowing these product to be
designated as network resources may
create significant disruption.861
Commenters supporting continued use
of firm LD contracts as designated
network resources argue that allowing
products structured on EEI’s Firm LD
Product has not created reliability
problems.862 Southern argues that the
Commission should not set criteria that
would place in jeopardy an array of
products that have a firm LD dimension.
Southern further states that such
products are among the most reliable in
instances where market prices are very
high (where LDs could be quite
substantial) and that just about any
power purchase/sale contract can be
financially settled in real-time or for a
given period in lieu of physical delivery
during that period. The fact that some
contracts set out in advance the terms of
such settlement (so to render commerce
more efficient and liquid) does not,
Southern argues, render those contracts
any less qualified for designation as
network resources. Thus, Southern
encourages the Commission to
reconsider its revised guidance
regarding the ineligibility of contracts
structured after EEI’s Firm LD Product.
Utah Municipals agrees, and similarly
requests that contracts under EEI’s Firm
LD Product be allowed to qualify as
network resources.
1443. Morgan Stanley argues that the
notion that firm LD contracts do not
contribute as much to resource
adequacy as contracts tied to individual
physical resources is inaccurate. Morgan
Stanley contends that the incentive to
ensure performance is far greater with a
firm LD obligation than with unit
contingent and system firm contracts.
Morgan Stanley explains that unit
861 E.g., APPA, Hoosier Reply, NCPA, Southern,
Strategic Energy Reply, and Utah Municipals.
862 E.g., EEI, Hoosier Reply, Southern and NCPA.
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contingent and system firm contracts
require delivery if the unit or group of
units performs and excuses delivery if
they do not, while a Firm LD obligation
requires delivery so long as it is
physically possible to achieve delivery,
regardless of the cost of doing so. Thus,
according to Morgan Stanley, firm LD
products can enhance supply security
because they are not dependent upon
the performance of an individual unit or
units, but rather put the burden and
opportunity on the supplier to use
multiple physical resources to meet its
obligations.
1444. APPA also requests
reconsideration of this issue, arguing
that its members are often presented
with power purchase agreements based
on EEI’s Firm LD Product and that they
are not always successful in negotiating
amendments to such agreements with
suppliers. APPA argues that an LSE can
use a diverse resource portfolio,
including firm LD power purchase
agreements, to serve its load
economically, while meeting reliability
requirements and advancing other
important policy objectives (diverse fuel
mix, use of renewable energy, etc.).
APPA urges the Commission to allow
such use if it is consistent with the
commercial practices in a region.863
1445. NCPA also opposes forbidding
firm LD products without looking more
fully into their merits and the potential
safeguards that could be built into them.
NCPA recognizes that firm LD contracts
raise certain issues under the pro forma
OATT and also pose issues for planning
where a specific resource is not
designated, but these problems are not
significantly different from the problems
of a large transmission owner
designating its entire fleet as network
resources for its entire load. Rather than
ban LD contracts from an important
segment of the market, several
commenters suggest that the
Commission convene a separate
proceeding or conference to further
investigate the issue.864
1446. Other commenters argue against
allowing the designation as network
resources of contracts that permit the
interruption of power sales for reasons
other than reliability as long as LDs are
paid.865 Detroit Edison argues in its
reply comments that a seller’s decision
to pay the ‘‘costs of ‘cover’ ’’ under these
contracts is of no value to an LSE that
lacks deliverable alternatives. Detroit
Edison further claims that, contrary to
863 MISO/PJM States similarly argue that whether
a particular contract with LD provisions can serve
as a designated resource should be decided within
the RTO stakeholder process.
864 E.g., APPA Reply, Morgan Stanley, and NCPA.
865 E.g., Duke, Dynegy, and Detroit Edison Reply.
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Southern’s assumption that a failure to
deliver under a firm LD contract would
result in substantial non-delivery
penalties, one would expect a supplier
afforded the option to divert power to a
higher priced market that produces a net
financial gain would elect to interrupt
service under the power sales contract
and pay the LDs. Detroit Edison
contends that purchasers would be left
hanging during periods of supply
shortage when firm physical supply is
most critical.
1447. In its reply comments, Duke
asserts that allowing firm LD products
to be designated as network resources
would result in network customers
leaning on its system. Although it has
doubts about whether the EEI Firm LD
Product actually contains language that
prohibits interruptions for economic
reasons, Duke would find the inclusion
of such language in purchased power
agreements to provide sufficient
firmness to allow the contract to be
designated as a network resource. In its
reply comments, Dynegy argues that
allowing designation of firm LD
products is simply inconsistent with the
existing OATT requirements that a
transmission customer either own,
purchase or have rights to generation.
1448. Northwest IOUs request that the
Commission clarify whether the
limitations for qualification of a network
resource, such as the presence or
absence of an LD clause, would prevent
a transmission provider from using such
a resource for service to its bundled
native load customers. Northwest IOUs
state that, if the non-rate terms and
conditions do not apply directly by
requirement of the Final Rule, but only
under a comparability test where there
is a comparison to network customers,
then that position should be made clear.
They further note that some
transmission providers have no
comparable network service, or no
service involving generating units
within the transmission provider’s
control area. Accordingly, Northwest
IOUs request that the Commission
clarify whether, in those instances, the
limitations for qualification of a network
resource would apply.
1449. Many commenters also argue
for the eligibility of service provided
under the WSPP Service Schedule C
(Schedule C) agreement.866 In
particular, WSPP argues that its
Schedule C product satisfies the
Commission’s requirements for
designation as a network resource
because it requires the seller to deliver
power except under very limited
866 E.g., APPA, EEI, Entergy, Northwest Parties,
Salt River, Utah Municipals, and WSPP.
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circumstances, such as force majeure,
and that the agreement itself clearly
provides that it is a firm product.
However, WSPP notes that its product,
like most if not all wholesale power
sales contracts, contains a damages
provision which could be characterized
as an LD provision. WSPP contends that
such provision is used simply to avoid
the need to litigate damages and not to
permit a seller to ignore its delivery
obligations by financially settling a firm
power sale. WSPP states that it is not
intended that sellers be allowed to
refuse to deliver for economic reasons.
Therefore, WSPP requests clarification
that its Schedule C product is eligible
for designation as a network resource,
and notes the potential for significant
disruptions in the market and WSPP
member sales of firm products if its
Schedule C product is not considered
eligible for designation as a network
resource.
1450. EEI and Northwest Parties note
that, in some instances, both the sellers
and buyers of the Schedule C product
designate that product as a network
resource, since it appears to meet the
pro forma OATT definition of a network
resource for both parties because the
agreement allows interruptions to serve
native loads. If only one party is found
to be able to designate the Schedule C
product as a network resource, EEI
argues that the other party would run
the risk of civil penalties for making an
incorrect attestation and may also lose
the transmission rights that it needs to
serve its native load or network load.
Northwest Parties request specific
clarification as to whether power
purchased under Schedule C from a
seller with public utility or statutory
obligations to its customers is to be
considered power available to meet the
purchaser’s network load on a noninterruptible basis, given that the seller
may interrupt service under the power
sales contract to meet its public utility
or statutory obligations. If the
Commission decides that the Schedule
C transactions cannot be designated as
network resources, Northwest Parties
asks the Commission to state whether
such transactions would be eligible if
the WSPP service agreement requires
the seller to give the purchaser advance
notice of an interruption. Salt River also
asks that, if Schedule C is found to be
ineligible, the Commission identify the
specific changes needed to that contract
to allow for designation.
1451. Beyond the eligibility of
contracts with LDs to be designated as
network resources, EEI and Duke also
argue that there is a conflict between the
policy guidance given in Dynegy (that a
power purchase agreement which is
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interruptible for reasons other than
reliability is not eligible for designation
as a network resource) and the guidance
given in WPPI 867 (that a power
purchase agreement which permits
curtailment to serve the seller’s native
load is eligible for designation as a
network resource). Duke argues that,
since the type of contracts contemplated
in WPPI are clearly interruptible for
reasons other than reliability, WPPI
should no longer be deemed valid case
law in light of the Commission’s
proposed clarifications in the NOPR.
Duke argues that allowing such
contracts to be designated as network
resources creates reliability risks and
likely permits two entities to designate
the same generation as network
resources. While Duke acknowledges
that exceptions to this rule may be
necessary in the Western
Interconnection, it does not support an
exception for the Eastern
Interconnection. EEI argues that the
conflict between the Dynegy and WPPI
standards has resulted in different
transmission providers and customers
using different standards for designation
of network resources. EEI therefore asks
the Commission to clarify precisely
what contracts qualify as a network
resource before it implements its
proposed attestation requirement.
Commission Determination
1452. Many commenters seek
clarification of the eligibility of power
purchase agreements with LD provision
to be designated as network resources.
In clarifying our policy concerning firm
LD products, we turn first to the
apparent confusion surrounding the
Commission’s findings in Dynegy. Duke,
Dynegy, EEI, and Southern argue that
the Commission incorrectly found in
Dynegy that the EEI Firm LD Product
could not be interrupted for economic
reasons. These parties argue that the EEI
Firm LD product actually allows power
to be interrupted for any reason,
including economic reasons, after which
LDs are assessed if the interruption was
not due to a force majeure event. We
disagree. As Hoosier points out, the EEI
Firm LD Product does not permit power
to be interrupted for economic reasons.
While any party to any contract can
choose to fail to perform, that does not
convey a contractual right to fail to
perform. The EEI contract clearly
obligates the supplier to provide power,
except in cases of force majeure. Thus,
the contract does not allow interruption
for economic reasons. The presence of
an LD provision in the EEI Firm LD
Product does not permit the seller to
867 WPPI,
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violate the terms of the contract, but
rather merely specifies the damages that
must be paid if the seller fails to
perform under the contract. As noted by
many commenters, it is the firmness of
a power purchase contract, and not
simply the presence or absence of an LD
provision, that determines the eligibility
of that power purchase to be designated
as a network resource.
1453. We conclude, however, that the
firmness of an obligation to provide
under a contract with an LD provision
is informed by the particular terms of
the LD provision. The type of LD
provision commonly seen in firm LD
products, such as the EEI Firm LD
Product, obligates the supplier, in the
case of interruption for reasons other
than force majeure, to make the
aggrieved buyer financially whole by
reimbursing them for the additional
costs, if any, of replacement power. In
contrast to this ‘‘make whole’’ type of
LD provision, other types of LD
provisions establish penalties at a fixeddollar amount, cap penalties at some
level, or are otherwise not equivalent to
a general ‘‘make whole’’ type provision.
Under these other types of LD
provisions, suppliers only need to
compare their savings from interrupting
with the specified LD penalty when
deciding whether to interrupt power
sales. Because such a consideration may
not take into account the cost of
replacement power, such LD provisions
could lead to inefficient supplier
interruption and economic harm to the
buyer.
1454. We find that a ‘‘make whole’’
LD provision, such as that found in the
EEI Firm LD Product and in the WSPP
Schedule C agreement, does not create
incentives that are incompatible with
the firmness of the overall product.
‘‘Make whole’’ LDs require the seller to
consider the price of the replacement
power, if it is available, to its original
buyer if the seller fails to perform under
the contract. There could, of course, be
situations where the supplier is still
presented with a net financial gain and
has an incentive to interrupt, but those
incentives would seem to be the same
incentives faced by a designated
network resource that is a specific
generating plant owned by the network
customer. In such an instance, the
network customer may determine, from
time to time, that it is more economic
to substitute power from an alternate
source in order to allow the originally
designated resource to either shut down
or to sell its output into the wholesale
market. We find no reason to create
financial incentives that make
purchased power designated as a
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network resource financially ‘‘more
firm’’ than owned generation.
1455. Accordingly, we find that the
inclusion of a ‘‘make whole’’ LD
provision in a power purchase
agreement does not disqualify that
agreement from being designated as a
network resource. However, other types
of LD provisions may create incentives
that are incompatible with the firmness
of a power purchase agreement. Thus, as
of the effective date of this Final Rule,
power purchase agreements designated
as network resources may only contain
LD provisions that are of the ‘‘make
whole’’ type. Conversely, power
purchase agreements containing LD
provisions that provide penalties of a
fixed amount, that are capped at a fixed
amount, or that otherwise do not require
the seller to pay an aggrieved buyer the
full cost of replacing interrupted power,
are not acceptable. Any contract which
contains an unacceptable LD provision,
but otherwise qualifies for designation
as a network resource and has been
properly designated as a network
resource prior to the effective date of
this Final Rule, will be grandfathered
only until the earlier of (1) the
expiration of the current term of the
power purchase agreement or (2) an
indefinite termination 868 of the power
purchase agreement as a designated
network resource pursuant to section
30.3 of the pro forma OATT. In response
to the many comments received, we
confirm that the LD provisions in both
the EEI Firm LD Product and the WSPP
Schedule C agreement are acceptable.869
1456. Detroit Edison argues that a
seller’s obligation to pay the cost of
replacement power under firm LD
contracts is of no value to an LSE that
lacks deliverable alternatives. Detroit
Edison appears to assume that, as long
as an LSE purchasing power had no
deliverable alternatives from which to
procure power, a designated supplier
would not be liable for damages if it
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868 As
discussed below, in section V.D.6.c,
termination of network resource status may either
be temporary or indefinite. A firm LD contract that
does not have a ‘‘make whole’’ LD provision and
which is grandfathered here may continue to be
temporarily terminated in order to make third-party
sales without jeopardizing its eligibility to be
redesignated after a third-party sale. However, once
a network resource is indefinitely terminated, it
must comport with the requirements for LD
provisions, and all other requirements for
designation of network resources, before it can be
redesignated.
869 As discussed below, however, we otherwise
find that the WSPP Schedule C agreement does not
comply with the requirements for designation as a
network resource because it allows for interruption
for reasons other than reliability. We therefore do
not need to address requests to clarify that both the
buying and selling party to a WSPP Schedule C
contract can designate network resources associated
with the contract.
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chose to interrupt power sales to the
buyer for reasons other than force
majeure. We disagree. Detroit Edison is
addressing the fairly unusual
circumstance where a power supply is
interrupted, there are no available
alternatives in the market, and firm load
therefore must be interrupted. We fail to
see why this circumstance, and the
difficulty of calculating damages for lost
load when it occurs, provides a reason
why a particular network resource (an
LD contract) should not qualify under
the pro forma OATT as a network
resource.
1457. We also disagree with Dynegy’s
argument that allowing the designation
of firm LD products is inconsistent with
the existing OATT requirement that a
transmission customer own, purchase or
have rights to generation. As discussed,
firm LD contracts that meet the
Commission’s requirements for
designation do create for the buyer a
contractual right to generation and do
not contain damage provisions which
make the actual incentives under such
contracts incompatible with those
present in owned generation.
1458. In response to Northwest IOUs’
request, we also clarify that the presence
or absence of an LD provision does not
prevent a transmission provider from
using such a resource to serve its
bundled native load customers. Rather,
as we explain above, it is the type of LD
provision that is controlling. A power
purchase contract with a ‘‘make whole’’
remedy could be used to serve native
load customers.
1459. We disagree with Duke and
EEI’s argument that there is a conflict
between the policy guidance given in
Dynegy (that a power purchase
agreement which is interruptible for
reasons other than reliability is not
eligible for designation as a network
resource) and the guidance given in
WPPI (that a power purchase agreement
which permits curtailment to serve the
seller’s native load is eligible for
designation as a network resource). We
reiterate the Commission’s finding in
WPPI that a power purchase agreement
properly designated as a network
resource may permit curtailment to
serve the seller’s native load. Consistent
with the long-standing definition in
Order No. 888, ‘‘curtailment’’
contemplates a reduction in service as a
result of system reliability conditions,
not economic reasons.
1460. Although we find that the LD
provision contained in the WSPP
Schedule C agreement does not impair
the firmness of that agreement, we note
that the agreement otherwise allows
interruptions in generation service ‘‘to
meet [the] Seller’s public utility or
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12455
statutory obligations to its customers.’’
Thus, the WSPP Schedule C agreement
appears to allow interruptions for
reasons other than reliability and, as a
result, would not be eligible for
designation as a network resource under
the Dynegy or WPPI precedent. We find
that the provision in the WSPP
Schedule C agreement allowing for
interruption of generation service in
order to serve native load would need
to be revised to explicitly prohibit
interruptions for reasons other than
reliability of service to native load in
order for that provision to meet the
requirements established under Dynegy
and WPPI.
1461. Maintaining the standard for
eligibility established in Dynegy and
WPPI will further the Commission’s
goals of preventing undue
discrimination, promoting comparable
treatment of customers, and increasing
the accuracy of ATC calculations.
However, we acknowledge that some
may currently be relying on the WSPP
Schedule C agreement in designating
network resources and that there may be
disruption if we were to invalidate the
designations of the existing WSPP
Schedule C resources. Thus, we exercise
our discretion not to invalidate existing
designations of the WSPP Schedule C
agreements as a result of noncompliance
with this particular requirement until
the earlier of the following: (1) The
expiration of the current term of a
power purchase agreement or (2)
redesignation of a previously designated
WSPP Schedule C resource following a
period of temporary or indefinite
termination pursuant to sections 30.2
and 30.3 of the pro forma OATT.
Alternatively, parties may voluntarily
reform the offending contract terms in
order to preserve their eligibility for
network service.
(2) Off-System Resources
Comments
1462. Many commenters request
clarification or reconsideration of the
information that is required to be
specified in section 29.2(v) of the pro
forma OATT in order to designate a
seller’s choice contract or system sale as
a network resource. Northwest Parties
agree with the proposal in the NOPR
that system sales may be designated by
providing the control area from which
the sale is made, transmission
arrangements, and delivery points to the
transmission provider’s transmission
system.870 For system sales, Northwest
870 Northwest Parties request similar clarification
for designation of purchase contracts from one or
more specified, individual resources.
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Parties argue that unit-specific
information is not needed because such
sales are, by definition, from a variety of
resources and, in any event, the
resource-specific information is
typically not available to the purchaser.
This is particularly true, they argue, for
sales from large hydroelectric systems,
which are operated as one
interconnected unit. For purchase
contracts, they argue that unit-specific
information is not needed because it is
provided in the generation
interconnection agreement to the
control area where the resource is
located. Northwest Parties contend that
not requiring unit-specific information
for purchase of power, including
purchases of system power, is consistent
with the Commission’s description in
the NOPR of the requirements to
designate a network resource.
1463. Pinnacle argues that the Final
Rule should recognize that the level of
detail required by section 29.2(v) may
vary depending on circumstances and
permit the transmission provider to
determine the level of information
necessary for the evaluation of the
network resource. In some cases, a
power purchase agreement may, they
argue, appropriately refer to more
general information than a specific
single control area or single source of
supply.
1464. In cases where a power
purchase agreement is being sourced by
generating units from an external
control area, Entergy contends on reply
that simply identifying the control area
is sufficient for purposes of studying the
deliverability of that resource. However,
in cases where the power is sourced by
generating units internal to the
transmission provider’s control area,
Entergy argues that identifying only the
control area does not provide sufficient
information to study deliverability. In
that case, Entergy argues that the
customer must provide the specific
information required by section 29.2(v)
of the pro forma OATT, including the
location of the specific generating units.
If such information is not available at
the time of the network resource
designation, Entergy argues that the
customer should still be able to
designate the agreement as a network
resource, but that the customer would
have to confirm resource deliverability
prior to actually scheduling the service.
1465. TDU Systems argue in their
reply comments that specifying the
control area and the interface over
which power will enter the transmission
provider’s transmission system from a
designated network resource in an
external control area is sufficient for
purposes of studying the deliverability
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of that resource. TDU Systems also
argue that, for competitive reasons, an
LSE should never be required to identify
the generator or the transmission zone
where the generator is located.
1466. In contrast, EEI requests that the
Commission modify section 29.2(v) to
clearly state that the transmission
provider has the discretion to require
the network customer to identify the
location of the generator with more
specificity than simply specifying the
control area in which the network
resource is located, since the location
will affect the flowgate over which the
energy will be transmitted. EEI argues
that it is necessary to narrow the
location of the source of a power
purchase to the system of a particular
transmission owner, rather than a
control area. PNM-TNMP and Duke also
support requirements that network
customers provide more information
concerning the location of off-system
network resources and purchase
agreements so that the transmission
provider can properly evaluate the
impact on its system. Duke states that
Duke Carolinas are now receiving
requests to designate as network
resources power purchase agreements
that list the point of delivery as ‘‘the
PJM control area’’ or ‘‘into Southern.’’
1467. Dynegy argues in its reply
comments that the Commission has
never explained how a transmission
customer designating a firm LD contract
as a network resource could ever
comply with section 29.2 of the pro
forma OATT, which requires specific
information about the generation
resource being designated. Dynegy
contends that, just like a seller’s choice
contract, a customer is not entitled to
any information about particular
generating assets when entering a firm
LD purchase contract such as the EEI
Firm LD Product. As a result, Dynegy
states that it is unclear how a network
customer would ever be able to
legitimately designate such contracts as
a network resource.
1468. In order to help ensure that all
network resources are in fact backed by
capacity, Dynegy argues that the
Commission should require
identification of more than just the
control area when designating a network
resource. Dynegy argues that the
Commission should require the
generation owner or trading agent for
the generation to positively verify that
capacity was sold to the entity
designating that particular generator as
a network resource, and that the
designation is appropriate pursuant to
the parties’ agreement, as is currently
required in PJM.
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1469. Because some regions of the
country determine ATC using a flowbased methodology and other regions
use a rated path methodology, EEI
argues that section 29.2(v) should be
modified to permit transmission
providers to require a network customer
to designate the point to which the
energy is delivered and from which the
transmission provider will provide
network service if it is not delivered at
the generator bus.
1470. Duke requests that the
Commission resolve an inconsistency
between the NOPR’s statement at P 408
that ‘‘when a network customer is
designating a system purchase as a new
network resource, the source
information required in section 29.2(v)
should identify that the resource is a
system purchase and should identify the
control area from which the power will
originate,’’ and the statement in the very
next sentence that a ‘‘power purchase
agreement that is structured so that a
network customer cannot specify all of
the information required by section
29.2(v) cannot be designated as a
network resource.’’ Duke notes that
significantly more information is
required by section 29.2(v) (unit size,
VAR capability, operating restrictions,
variable generating cost for redispatch
computations, etc.) than the ‘‘control
area from which the power will
originate.’’
1471. Morgan Stanley contends that
the information required in section
29.2(v) must not disallow designation of
seller’s choice contracts as network
resources. They assert that transmission
providers use security constrained
economic dispatch under which the
source of supply in a contract is
generally irrelevant from a planning or
operational perspective and is therefore
not needed. Morgan Stanley also argues
that, if the underlying network
customer’s contract permits the seller to
curtail its dispatch and substitute a
source from the market, the
transmission provider would never
actually know the location where a
network customer’s power is coming
from and, thus, it is unclear why the
specification of that source should be a
requirement. Therefore, Morgan Stanley
requests that the Commission consider
revising 29.2(v) to eliminate the
inclusion of information that is not
necessary or make the provision of such
information required ‘‘to the extent
practicable.’’
1472. Duke replies that Morgan
Stanley accurately portrays what
typically happens under seller’s choice
contracts, but reaches the wrong
conclusion about a remedy. Duke argues
that, if network customers are permitted
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to designate as network resources
contracts that may be relatively longterm, but under which the seller has no
obligation to identify the source of the
power any sooner than on a day-ahead
basis, then ATC may be reserved even
though there is no intent to use it. Duke
also argues that allowing seller’s choice
contracts would hamper the
transmission provider’s ability to plan
its system. In Duke’s view, it would be
appropriate to permit a seller’s choice
contract to be a designated network
resource at the time transmission
service is granted for the period such
transmission service lasts, as at that
point the customer will have designated
a source and sink.
1473. Fayetteville recognizes that
there are problems related to modeling
and reliability in contracts for energy
which do not specify particular units as
sources, but argues that these problems
are exactly the same as those that exist
within any vertically integrated utility
which names its generation fleet as
network resources for its native load.
Commission Determination
1474. Many comments were received
with respect to seller’s choice and
system purchases. Some comments refer
not only to seller’s choice and system
purchases, but also to other possible offsystem transactions, including sourcing
from owned generation located offsystem. We therefore use the term ‘‘offsystem resources’’ here to refer to all
such resources.
1475. The existing requirements in
section 29.2(v) are intended to ensure
that the network customer designating
resources on other transmission systems
provides sufficient information to allow
the local transmission provider to
determine the effect on ATC.
Conversely, network customers should
not be permitted to designate off-system
resources which are so vaguely defined
that the effects on ATC cannot be
determined. In light of the requests that
the Commission clarify exactly what
information must be provided in order
to designate network resources located
off-system, and what information
required by section 29.2(v) must be
posted on OASIS, we will revise section
29.2(v) of the pro forma OATT to
specify exactly what information is
required.
1476. As revised by the Final Rule,
section 29.2(v) of the pro forma OATT
will require the following information to
be provided with the request and posted
on OASIS when designating an offsystem resource: (1) Identification of the
resource as an off-system resource; (2)
amount of power to which the customer
has rights; (3) identification of the
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control area(s) from which the power
will originate; (4) delivery point(s) to
the transmission provider’s
transmission system; and (5)
transmission arrangements on the
external transmission system(s).
Additionally, section 29.2(v) is revised
to require that the following information
be provided with such designation, but
such information must be masked on
OASIS to prevent the release of
commercially sensitive information
including (1) any operating restrictions
(periods of restricted operation,
maintenance schedules, minimum
loading level of resource, normal
operating level of resource); and, (2)
approximate variable generating cost
($/MWH) for redispatch computations.
Requests to designate off-system
network resources submitted on or after
the effective date of this Final Rule must
include all of the information listed
above.
1477. We direct transmission
providers to develop OASIS
functionality to (1) allow all of the
information required for a request to
designate network resources to be
provided electronically, (2) mask
information about operating restrictions
and generating cost on OASIS, and (3)
allow for queries of all information
provided with designation requests in
accordance with section 37.6 of the
Commission’s regulations.871 As
provided in paragraph 385, we also
direct transmission providers to work in
conjunction with NAESB to develop
business practice standards describing
procedural requirements for submitting
designations over any new OASIS
functionality. Transmission providers
need not implement this new OASIS
functionality and any related business
practices until NAESB develops
appropriate standards. Prior to
implementation of this new OASIS
functionality, any information that
cannot be provided electronically may
be submitted by transmitting the
information to the transmission
provider by telefax or providing the
information by telephone over the
transmission provider’s time recorded
telephone line.
1478. Duke argues that there is an
inconsistency between the following
statements in P 408 of the NOPR: (1)
‘‘when a network customer is
designating a system purchase as a new
network resource, the source
information required in section 29.2(v)
should identify that the resource is a
system purchase and should identify the
control area from which the power will
originate’’; and (2) the statement in the
871 18
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Frm 00193
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very next sentence that a ‘‘power
purchase agreement that is structured so
that a network customer cannot specify
all of the information required by
section 29.2(v) cannot be designated as
a network resource.’’ We disagree. The
first statement only provided guidance
on what could be provided in lieu of the
source of supply information (as
required in the last bullet of section
29.2(v) of the existing pro forma OATT)
and was not intended to excuse
customers from providing all of the
relevant information for an off-system
purchase other than the specific source
of supply. However, the revisions to
section 29.2(v) we adopt in this Final
Rule remove any confusion.
1479. We disagree with Dynegy’s
argument that no firm LD contracts
would be able to meet the requirements
for designation. We note that all of the
information required for off-system
resources should be available for a
seller’s choice contract. Even firm LD
contracts have variable generating costs
(energy cost) and may have maintenance
and other operating constraints. If no
such constraints are contractually
specified, or if no such constraints are
relevant to an owned generation
resource being designated, then that
should be reflected in the information
posted on OASIS.
1480. We reject Dynegy’s request that
the Commission require additional
verification by sellers that capacity was
in fact sold to an entity designating that
particular generator as a network
resource and that the network resource
designation is appropriate pursuant to
the parties’ agreement. As the
Commission explained in Illinois
Power,872 a firm energy purchase need
not be backed by capacity to qualify as
a designated network resource.
1481. We disagree with commenters
who argue that more specific
information than the control area must
be provided with each request to
designate system purchases or seller’s
choice contracts as network resources.
In particular, we disagree with EEI’s and
Duke’s argument that customers
designating seller’s choice contracts as
network resources must be required, on
a generic basis, to identify the specific
transmission system, rather than the
more general control area, in which the
physical resources are located. EEI
argues that such specificity is required
for transmission providers to identify
the individual flowgates over which the
power will flow into their system. The
existing section 29.2(v) of the pro forma
OATT requires that customers
designating network resources identify
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the ‘‘delivery point(s) to the
transmission provider’s transmission
system.’’ We agree with Entergy and
TDU Systems that providing both the
control area in which off-system
resources are located as well as the
delivery point(s) to the transmission
provider’s transmission system is
usually sufficiently specific to allow a
transaction to be evaluated for its effect
on the ATC of the local transmission
system. However, we acknowledge
Duke’s concern about receiving requests
to designate as network resources
purchase agreements that list the point
of delivery as only vague statements
such as ‘‘the PJM control area’’ or ‘‘into
Southern.’’ If any transmission provider
believes that it faces unique
circumstances that require deviations
from the pro forma OATT in order to
allow them to determine the effects of
designations of network resources on
ATC, it can, in a filing pursuant to FPA
section 205, propose terms and
conditions that it demonstrates are
consistent with or superior to the pro
forma OATT.
1482. Because some regions of the
country determine ATC using a flowbased methodology and other regions
use a rated path methodology, EEI
argues that section 29.2(v) should be
modified to permit transmission
providers to require a network customer
to designate the point to which the
energy is delivered and from which the
transmission provider will provide
network service if it is not delivered at
the generator bus. It is unclear what
specific changes EEI is requesting. We
note that, with respect to off-system
purchases, section 29.2(v) of the pro
forma OATT already requires that the
delivery point(s) to the transmission
provider’s transmission system be
included in the description of the
network resource.
1483. In response to Entergy’s request,
we clarify that a customer may not
designate as a network resource a
seller’s choice power purchase
agreement which is sourced by
generating units internal to the
transmission provider’s control area,
since evaluating the effect on ATC
would be problematic. We disagree with
Entergy that a customer should be able
to designate such a resource, even
without specifying the location of the
specific generating units, provided that
the customer’s network service from
those units is contingent upon
confirming resource deliverability prior
to actually scheduling the service,
because such a policy would still
significantly obscure the evaluation of
ATC. If a customer wishes to have a
choice of resources that are internal to
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the particular transmission provider’s
control area from which to dispatch
power, it must designate each of the
resources as network resources.
1484. We disagree with Morgan
Stanley’s unsupported comments that
the source of supply in a contract is
irrelevant. We find that location of
resources is a critical factor to the
transmission provider’s ATC
calculations and its ability to model and
evaluate the proposed network resource,
regardless of whether the transmission
providers use security constrained
economic dispatch.
(3) Ability To Serve Native Load
Comments
1485. Many parties contend that the
Commission’s policy with regard to the
qualification of network resources
affects their ability to serve native load.
EEI argues that energy purchases are an
integral part of the resources many
utilities use to serve their loads, yet
often such projected energy purchases
are not under contract until shortly
before the power is needed. According
to EEI, the requirement that a purchase
contract be executed to qualify as a
network resource jeopardizes the ability
of such utilities to serve their native
loads because they will not be able to
reserve transmission capacity and other
users may receive all of the ATC before
their contracts are executed.
1486. APPA, EEI and Nevada
Companies argue that restrictions on the
types of generation and power supply
arrangements that qualify for network
service may violate section 217 of the
FPA. EEI notes that section 217 provides
that LSEs are entitled to use firm
transmission rights to deliver the output
of their generators or purchased energy
to meet their service obligations to their
loads. In EEI’s view, section 217
requires the Commission to exercise its
authority in a manner that enables LSEs
to secure firm transmission rights on a
long term basis for long term power
supply arrangements made, or
‘planned,’ to meet such needs and,
therefore, a requirement that network
customers and transmission providers
not reserve transmission capacity to
serve their network loads and native
loads unless they either own generation
or have executed contracts that specify
the source of the energy is inconsistent
with section 217. APPA notes that
section 217 does not distinguish among
the types of power supply arrangements
that an LSE must enter into to be
protected and that section 217(b)(1)(A)
refers to a broad universe of owned or
contracted generation that would
suffice, so long as the power supplies
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are for the purpose of meeting a service
obligation.
1487. Newmont Mining disagrees that
the Commission’s requirements for
designation of network resources are
contrary to the new FPA section
217(b)(2). Newmont Mining argues the
legislative history of section 217(b)(2)
shows that it was intended essentially to
codify Order No. 888 873 and that the
resource designation requirements do
not deny LSEs any right to use their
transmission, but rather prescribe how
they are to implement that right.
1488. EEI, Nevada Companies, PNMTNMP and South Carolina E&G on reply
also argue that the Commission’s
requirements for eligibility for
designation as a network resource may
impermissibly conflict with statemandated procurement plans. EEI and
South Carolina E&G contend that, by
imposing restrictions on the ability of
LSEs to serve their native load, the
Commission is indirectly asserting
jurisdiction over state-regulated
procurement practices, which they
further argue is prohibited under
Northern States Power Co. v. FERC.874
1489. Nevada Companies argue that
the type of contracts that the
Commission has determined to be
eligible for qualification as network
resources tend to be the most expensive.
They point out that state regulatory
agencies might determine that other
types of contracts are more cost-effective
without unnecessarily jeopardizing
reliability. Even more troubling, they
argue, is the problem created when
transmission providers have peak loads
that can more effectively be served by
purchasing power on a short-term
period (i.e., less than one year). To
reserve the transmission required to
serve a needle peak that can occur
anytime within a four month period
would require the purchase of
thousands of megawatt hours of power
that Nevada Power knows it will not
need, resulting in a disallowance by the
Public Utility Commission of Nevada,
which approves all open positions,
options and hedges for Nevada Power.
1490. Nevada Companies contend that
the network designation process should
not be changed on systems where the
process works reasonably well,
873 In its reply comments, Newmont Mining cites
(through reference to its own NOI reply comments)
the statement in H.R. Rep No. 108–65 at 171 (2003)
that ‘‘[t]his section is intended to be consistent with
the Commission’s Order No. 888,’’ as well as the
statement in S. Rep. No. 109–78 at 50 (2005) that
section 217 ‘‘does not affect the Commission’s
authority under sections 205 and 206 [of the FPA]
to ensure that rates are just and reasonable and not
unduly discriminatory or preferential.’’
874 176 F.3d 1090, 1096 (8th Cir. 1999), cert.
denied, 528 U.S. 1182 (2000).
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particularly on systems where
transmission providers are required to
make significant purchases of power to
meet their retail loads. Nevada
Companies argue that the Commission
should therefore give transmission
providers the option of instituting a
reservation-based contract demand
service similar to that previously
approved in Florida Power.875
1491. Newmont Mining replies that
Nevada Companies proposal is not
similar to the Florida Power proposal or
other approved contract demand
network service arrangements, as those
services were offered at the request of a
network customer; designed to deal
with a particular circumstance of the
network customer; and offered as an
option to, not as a replacement for,
standard network integration services.
Utah Municipals in their reply
comments agree that utilities should not
be permitted to unilaterally impose a
contract demand ‘‘reservation based’’
methodology on its network customers.
1492. Newmont Mining argues that
Nevada Companies’ request to maintain
an open position for a portion of their
resource portfolio, in accordance with
their required resource planning
process, does have some basis, but that
Nevada Companies’ proposal is not the
right solution. If the Commission is
inclined to provide some relief to
Nevada Companies, Newmont Mining
argues that such relief should come, if
at all, only after an investigation of how
similar problems are handled on other
systems and that such relief should be
limited. The limitations Newmont
Mining suggests include, among other
things, excusing Nevada Companies
from the requirement, if at all, only to
the extent that a specific open portfolio
position is contained in a resource plan
approved in accordance with applicable
law; requiring that the reservation be
posted on OASIS; not granting a
reservation to Nevada Companies over a
competing application for network
service by a potential network customer
that actually has a designated network
resource; and permitting other network
customers to hold similar open
positions.
Commission Determination
1493. We generally disagree with
arguments that the Commission’s
restrictions on the designation of
network resources may violate section
217 of the FPA. Congress did not require
that LSEs be able to take transmission
service without limitations of any kind
in order to serve their native load, and
875 Florida Power Corp, 81 FERC ¶ 61,247 (1997)
(Florida Power).
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nothing in section 217 suggests that
LSEs should not be required to comply
with reasonable requirements that are
necessary to prevent undue
discrimination and maintain a reliable
transmission system. The conditions
that have been established for taking
network transmission service are
reasonable and support these goals, and
we therefore disagree that such
conditions are inconsistent with the
requirements of section 217.
Furthermore, as Newmont Mining
points out, the legislative history of
section 217(b)(2) supports the
interpretation that section 217 was
intended to be consistent with the
Commission’s authority under sections
205 and 206 of the FPA to ensure that
rates are just and reasonable and not
unduly discriminatory or preferential,
under which the designation
requirements in Order No. 888 were
adopted.
1494. We also disagree with
commenter arguments that the
Commission’s requirements for
eligibility for designation as a network
resource impermissibly conflicts with
state-mandated procurement plans. We
point out that, with the exception of
some clarifications on the types of LD
provisions that are acceptable in
designated firm LD products and what
information a customer designating a
system purchase or a seller’s choice
contract must provide, the requirements
for designation of network resources are
not new. Order No. 888 has long
required that contracts be executed and
imposed reasonable restrictions on the
types of resources that may be
designated as network resources.
1495. To the extent that individual
transmission providers have unique
circumstances or needs that justify a
variation from the pro forma OATT,
those parties can request such a
variation and explain why their
proposed variation is consistent with or
superior to the requirements of the pro
forma OATT in a section 205 filing. In
particular, Nevada Companies’ request
for approval of a contract demand
service in order to address certain issues
presented by their unique situation
would properly be made in the context
of a section 205 filing requesting a
deviation from the pro forma OATT. We
agree with Newmont Mining and Utah
Municipals that approved variations, if
any, must be applied on a comparable
basis to both the transmission provider’s
merchant function and the other
network customers.
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(4) General
Comments
1496. A number of commenters raised
other general concerns regarding the
designation of network resources. TAPS
requests that the Commission clarify
that conditional firm transmission
service is sufficiently firm to meet the
requirement that third-party
transmission arrangements to deliver a
designated purchase to the network be
noninterruptible. TAPS also requests
that the Commission provide for
designation of network resources within
the control area on a conditional firm
basis.
1497. In its reply comments, South
Carolina E&G request clarification of the
content and process of making
information postings in accordance with
section 29.2 of the pro forma OATT.
South Carolina E&G argues that, taken
literally, section 29.2 requires that
everything in an application for network
service be posted. South Carolina E&G
contends, however, that the contents of
an application do not fit on OASIS as
currently configured, and that making
such information available on OASIS is
not necessary for the Commission’s
purposes, particularly given the
Commission’s representations in favor
of preserving the integrity of customer
confidential information. South
Carolina E&G suggests the Commission
require only the following information
to be posted on OASIS: identification of
the service type as ‘‘network’’;
identification of the source by name of
the generator or system; identification of
the sink by name of the network
customer’s load; identification of the
point of receipt by specification of the
interface at which the network customer
intends to deliver to the resource into
the transmission provider’s
transmission area; and identification of
the point of delivery and sink.
1498. South Carolina E&G also
requests clarification on how designated
network resources are to be posted.
South Carolina E&G asks, for instance,
whether the Commission expects
transmission providers to develop an
OASIS template that network customers
can update, as necessary, for network
resources to simply be posted in PDF
format, or be accomplished via the
comment section of an OASIS
reservation. South Carolina E&G argues
that posting via the comment section of
OASIS allows for operational ease, but
provides limited transparency and
includes administrative challenges due
to character limitations and formatting
constraints. Alternatively, South
Carolina E&G argues, new functionality
on OASIS that allows customers to post,
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modify and update network resources
would satisfy the Commission’s
requirements, but would involve added
costs and time.
1499. TranServ seeks clarification as
to the minimum term, if any, that the
transmission provider must honor for
designation of new network resources.
TranServ requests that network
resources be allowed to be designated
for the same minimum time periods
used for firm point-to-point service, i.e.,
daily or hourly service. Conversely,
South Carolina E&G argues in its reply
comments that requiring transmission
providers to update their list of
designated network resources on an
hourly basis is too burdensome. South
Carolina E&G requests that the
Commission allow alternative methods
of designating network resources on a
short-term basis, such as adding
comments to the appropriate comment
field on either eTags or OASIS
reservations.
1500. TDU Systems argue that the
designation of network resources
(explicit or implicit) by some
transmission providers is automatic,
while network customers are required to
pay for elaborate studies of every
conceivable path affected by the
addition of the resource. TDU Systems
request that the Commission clarify that
the process of network resource
designation should be the same for all
network users.
1501. APPA, Fayetteville, NCPA,
Northwest Parties, TAPS, and
Wolverine request that clarifications
made to the Commission’s policy for
qualification as a network resource
apply prospectively and/or that
sufficient time be allowed after the
adoption of the Final Rule such that the
necessary products, information systems
and business practices can be
developed. Such commenters contend
that the designated network resources
they currently rely upon were acquired
and designated consistent with prior
Commission precedent, so that changes
to the network resource criteria
established in this proceeding should
not invalidate the continued use of such
resources. Because there may be many
existing designated network resources
that do not meet the standards that the
Commission eventually sets, Duke
suggests on reply that the Commission
may need to permit existing contractual
designated network resources that do
not qualify under the new standard to
retain their designated status until the
earlier of the expiration data of the
transaction or the expiration date of any
necessary transmission service
supporting that network resource.
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1502. In its reply comments, Dynegy
disagrees with request to grandfather
existing designated network resources,
and argues that the Commission’s
holding in Dynegy was erroneous and
should be remedied in its entirety,
without the creation of yet another class
of grandfathered entities.
Commission Determination
1503. The Commission agrees with
TAPS that firm point-to-point
transmission service provided on a
conditional firm basis is sufficiently
firm to be used for transmission to
import a designated network resource.
Firm point-to-point transmission service
provided on a conditional firm basis
meets the existing requirement that
transmission arrangements in other
control areas delivering power
purchases designated as network
resources to the network customer’s
transmission provider must not be
interruptible for economic reasons, as
explained further in section III.F of this
Final Rule. With respect to TAPS’
second request for clarification to allow
for designation of network resources
within the control area on a conditionalfirm basis, we note that such
designation of network resources within
the control area will not be allowed, as
discussed further in section III.F.
1504. In response to South Carolina
E&G’s request, we reiterate that not all
of the information required by section
29.2 of the pro forma OATT for
designation of a network resource will
be made publicly available on OASIS.
As discussed above, information about
operating restrictions and generating
cost will be masked to protect
commercially sensitive information.
South Carolina E&G has also requested
clarification of the Commission’s intent
with respect to how designated network
resource information is posted. Our
existing regulations specify the view,
download, and query requirements for
information posted regarding network
resource designations.876 The details of
how those informational postings are
accomplished are best left to be
determined as part of the NAESB
standards development process.
1505. TranServ requests that the
Commission clarify the minimum term,
if any, that a transmission provider must
honor for designations of new network
resources. We agree with TranServ that
the minimum term should be the same
as the minimum time period used for
firm point-to-point service (i.e., daily),
unless otherwise demonstrated by the
876 See
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Frm 00196
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transmission provider and approved by
the Commission.877
1506. In response to TDU Systems’
request for clarification that the process
of network resource designation should
be the same for all users, we note that
section 28.2 of the pro forma OATT
already provides that ‘‘[t]he
Transmission Provider, on behalf of its
Native Load Customers, shall be
required to designate resources and
loads in the same manner as any
Network Customer under Part III of this
Tariff.’’ We encourage parties to utilize
the Commission’s Enforcement Hotline
to report suspected abused of this
process.
b. Documentation for Network
Resources
NOPR Proposal
1507. In the NOPR, the Commission
noted that transmission providers are
responsible for verifying that the
network customer has provided all the
information required in section 29.2, but
that transmission providers are not
responsible for verifying that the
generating units and power purchase
agreements network customers
designate as network resources satisfy
the requirements in sections 30.1 and
30.7 of the pro forma OATT. However,
the Commission also explained that the
transmission provider continues to have
the responsibility to verify that thirdparty transmission arrangements to
deliver the purchase to the transmission
provider’s system are firm.
1508. The Commission proposed to
require the transmission provider’s
merchant function as well as network
customers to include a statement with
each application for network service or
to designate a new network resource
that attests that, for each network
resource identified in the application for
service, (1) the transmission customer
owns or has committed to purchase the
designated network resource, and (2) the
designated network resource comports
with the requirements for designated
network resources.
1509. If the network customer does
not include an attestation when it
confirms its request, the Commission
proposed that the transmission provider
will notify the network customer within
15 days of confirmation that its request
is deficient and that, wherever possible,
the transmission provider will attempt
to remedy deficiencies in the request
through informal communications with
the network customer. If such efforts are
unsuccessful, the Commission further
877 See, e.g., Entergy Services, Inc., 105 FERC
¶ 61,318 (2003), reh’g denied in relevant part, 109
FERC ¶ 61,216 (2004).
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proposed that the status of the request
on OASIS will be changed to
‘‘retracted’’ and the network customer’s
request will be terminated without
prejudice to the network customer
submitting a new request that includes
the required attestation, after which the
network customer will be assigned a
new priority consistent with the date of
the new request.
1510. In the event that the
transmission provider or any network
customer designates a network resource
that it does not own or has not
committed to purchase, or that does not
otherwise comport with the
requirements for designated network
resources, the Commission proposed
that it will deem the network customer
to be in violation of the pro forma
OATT and will consider assessing civil
penalties on a case-by-case basis
consistent with the Commission’s Policy
Statement on Enforcement. The
Commission encouraged the
transmission provider and other market
participants to use the Commission’s
Enforcement Hotline to report instances
when they believe a network customer
has designated as a network resource a
resource that does not meet the criteria
for network resources.
Comments
1511. Several commenters support the
overall proposed changes involving
attestation requirements, claiming the
proposal should help to eliminate
abuse, including the practice of some
utilities denying transmission requests
in order to accommodate its merchant
function’s plans to engage in future
short-term purchases to serve native
load.878 Entegra explicitly supports the
Commission’s proposal to treat failures
to comply as violations of the pro forma
OATT subject to enforcement. Pinnacle
notes that customers should make such
attestations in good faith, such that an
inadvertent error or omission would not
automatically result in recourse to a
legal remedy if it can be corrected
without adverse impacts.
1512. Dynegy argues in its reply
comments that transmission customers
who knowingly provide false or
inaccurate information in their network
resource designations not only
jeopardize reliability, but are essentially
engaging in theft. Dynegy argues that
such parties should be subject to the
sanctions and penalties under the
Market Behavior Rule,879 including
revocation of the violator’s market-based
878 E.g., Ameren, Entegra, Pinnacle, Public Power
Council, and Southern.
879 See Investigation of Terms and Conditions of
Public Utility Market-Based Rate Authorizations,
105 FERC ¶ 61,218 (2003).
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rate authority. APPA and TAPS argue
that the new attestation requirements
should be consistently applied to all
network customers, including the
transmission provider’s merchant
function and affiliates.
1513. Several commenters support the
Commission’s determination that
transmission providers are not required
to independently verify the accuracy of
an application for network service.880
Some commenters request that the
Commission clarify that transmission
providers or transmission owners can
voluntarily seek information which
verifies that contractual terms meet the
requirements in section 30.1 and 30.7 of
the pro forma OATT.881 In its reply
comments, Duke argues that, without
the ability to request the contracts
supporting the compliance with the
requirement that the designated network
resources are firm enough, the
Commission may not have authority to
require that the network customer
support its designation in situations
where the network customer is
nonjurisdictional.
1514. Pinnacle disagrees with the
NOPR proposal that transmission
providers should continue to be
responsible for verifying the firmness of
the network customers’ transmission
arrangements on other systems. Instead,
Pinnacle contends that the transmission
customer should have the obligation to
ensure that their transmission
arrangements meet the requirements
needed to ensure that their resources
qualify as designated network resources.
In its reply comments, Detroit Edison
also requests that the Commission
require proof that network customers
have obtained the requisite transmission
service on external systems.
1515. Dynegy, in its reply comments,
requests that network resource
information and validity of designation
be verified not only by the designating
customer, but also by the seller or owner
of the generation, in order to help
ensure that all network resources are in
fact backed by capacity. Entegra
similarly suggests that the Commission
require that entities designating network
resources make periodic OASIS postings
that will permit verification that the
entity designating a generating facility
as a network resource actually has rights
to power from that facility.
1516. EEI and Entergy allege that the
Commission’s NOPR attestation
proposal may have unintended
consequences. Some commenters
880 E.g., Ameren, EEI, Suez Energy NA, Nevada
Companies, and Utah Municipals.
881 E.g., Ameren, Duke Reply, Entergy, and
Pinnacle.
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12461
contend that the gap between the
Commission’s interpretation of the
qualifications of network resources and
current procurement practices creates a
significant possibility that, if the
Commission enforces its policies, it
could cause substantial disruptions of
service to network and native loads,
reduce supply options, or expose
network customers and transmission
providers to increased liability.882 EEI
asserts that this is because a significant
number of network customers and
transmission providers are serving their
network loads and native loads using
resources, particularly power purchase
contracts, that may not meet the
Commission’s requirement for
designation as network resources. Some
commenters request that the
Commission engage in a comprehensive
review of power purchase practices
before implementing its proposed
attestation requirement, and apply any
change in policies only to power
purchases entered into after the effective
date of the Final Rule and after the
industry has had time to develop new
products that meet the Commission’s
requirements.883
1517. Entegra replies that the
expressed concern about the attestation
requirement by EEI is puzzling and
troubling, because the NOPR did not
propose to change the current
requirements of the pro forma OATT
regarding the qualification of network
resources. Entegra argues that the
widespread non-compliance alleged by
EEI makes adoption of an attestation
requirement more important and that
EEI’s allegations may, at most, suggest
that the Commission consider some sort
of amnesty for network customers and
transmission providers willing to selfreport and commit to full compliance
with the network resource rules going
forward.
1518. To ensure that network
customers can submit requests for new
network service without a final,
executed contract, Entergy requests that
an attestation to designate a new
network resource should not be required
until the service request is confirmed. If
the request is pre-confirmed, Entergy
suggests that the attestation should be
provided at the time the request is
submitted.
1519. SPP requests that the
Commission not require it to police the
additional restrictions on the
designation of network resources
proposed in the NOPR. SPP states that
it has neither the data nor the personnel
882 E.g., EEI, TDU Systems, Indianapolis Power
Reply, and South Carolina E&G Reply.
883 E.g., EEI and Indianapolis Power Reply.
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necessary to perform this function and
that the Commission should rely on
network customer verification, subject
to Commission audits. TranServ
suggests that the exact nature of how the
customer would make the newly
required attestation, as well as the
treatment of OASIS requests failing to
provide the required attestation, should
be determined in the NAESB forum at
the time when the technical
requirements for processing network
service requests on OASIS are
established.
1520. Several commenters request
that the Commission amend section 30.2
of the pro forma OATT to require
network customers that designate
network resources in an external control
area also provide a certification from
that control area’s administrator that the
resource being designated is not
counted as a designated resource for
another load on or off of the system.884
TDU Systems disagree, arguing on reply
that the Commission should not require
these types of certifications. TDU
Systems recommend, in the alternative,
that LSEs on multiple systems should
not have to undesignate network
resources to serve off-system load,
which would eliminate the need for
such control area certification for such
transactions. TDU Systems also argues
that, in the absence of any evidence of
abuse, the Commission should not
further complicate a process that most
market participants would agree is
already overly complicated and
burdensome.
Commission Determination
1521. The Commission adopts the
NOPR proposal that transmission
providers continue to be responsible for
verifying that third-party transmission
arrangements to deliver the purchase to
the transmission provider’s system are
firm, but that transmission providers are
not responsible for verifying that the
generating units and power purchase
agreements network customers
designate as network resources satisfy
the requirements in sections 30.1 and
30.7 of the pro forma OATT. We also
adopt the proposal to require both the
transmission provider’s merchant
function and network customers to
include a statement with each
application for network service or to
designate a new network resource that
attests, for each network resource
identified, that (1) the transmission
customer owns or has committed to
purchase the designated network
resource and (2) the designated network
884 E.g.,
MISO, Indianapolis Power Reply, and
Detroit Edison Reply.
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resource comports with the
requirements for designated network
resources. The network customer should
include this attestation in the
customer’s comment section of the
request when it confirms the request on
OASIS.
1522. If the network customer does
not include the attestation when it
confirms the request, the transmission
provider must notify the network
customer within 15 days of
confirmation that its request is deficient,
in accordance with the procedures in
section 29.2 of the pro forma OATT.
Whenever possible, the transmission
provider shall attempt to remedy
deficiencies in the request through
informal communications with the
network customer. If such efforts are
unsuccessful, the transmission provider
shall terminate the network customer’s
request and change the status of the
request on OASIS to ‘‘retracted.’’ This
termination shall be without prejudice
to the network customer submitting a
new request that includes the required
attestation. The network customer shall
be assigned a new priority consistent
with the date of the new request.
1523. In the event that the
transmission provider or any other
network customer designates a network
resource that it does not own or has not
committed to purchase or that does not
comport with the requirements for
designated network resources, we will
deem the network customer to be in
violation of the pro forma OATT and
will consider assessing civil penalties
on a case-by-case basis, consistent with
the Commission’s Policy Statement on
Enforcement.885 We encourage the
transmission provider and other market
participants to use the Commission’s
Enforcement Hotline to report instances
where they believe a network resource
has been designated that does not meet
the Commission’s requirements.
1524. In response to Pinnacle’s
request that an inadvertent error or
omission should not automatically
result in a penalty if it can be corrected
without adverse impacts, we reiterate
the policy established in the
Commission’s Policy Statement on
Enforcement that enforcement actions
will not be imposed ‘‘automatically.’’
Enforcement actions are instead
considered on a case-by-case basis after
consideration of a number of factors
which may result in penalties being
reduced or eliminated.886 Among the
many factors to be considered pursuant
to the Policy Statement on Enforcement
885 See
supra note 75.
886 Policy Statement on Enforcement at P 13.
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is whether the violation is willful.887 At
the same time, consideration is
provided for other factors that may
weigh for assessing civil penalties, even
in circumstances of inadvertent
violations. For instance, the
Commission considers whether the
violator has a history of violations and
whether the actions were recklessly or
deliberately indifferent to the results.888
While enforcement actions will not be
automatic, and the inadvertence of a
violation would be a consideration
when determining what, if any, penalty
to impose, there may be some instances
where inadvertent violations would be
found, after consideration as established
in the Policy Statement on Enforcement,
to warrant a penalty.
1525. Dynegy also requests that
transmission customers who knowingly
provide false or inaccurate information
in their network resource designations
be subject to the sanctions and penalties
under the Market Behavior Rules,889
including revocation of the violator’s
market-based rate authority. We
reiterate that violations will be dealt
with on a case-by-case basis in
accordance with the Policy Statement
on Enforcement.
1526. We reject requests to allow the
transmission provider to voluntarily
seek information which verifies that
contractual terms meet the requirements
in sections 30.1 and 30.7 of the pro
forma OATT. Allowing transmission
providers to verify terms and conditions
of power purchase agreements would
put transmission providers in the
position of interpreting contracts and
accepting or rejecting designations
based on their interpretations. We
believe such authority is unnecessary in
light of the new attestation requirements
and that instances of non-compliance
are better handled by the Commission’s
enforcement staff in the context of
audits and Enforcement Hotline reports.
This applies equally to jurisdictional
and nonjurisdictional customers. Every
transmission customer must satisfy the
requirements of the transmission
provider’s OATT in order to take
service. The Commission thus has
authority to require that all network
customers support their designations.
1527. We disagree with Pinnacle’s
argument that transmission providers
should not be responsible for verifying
the firmness of the network customer’s
transmission arrangements on other
systems. We find that having
887 Id.
at P 20.
888 Id.
889 Investigation of Terms and Conditions of
Public Utility Market-Based Rate Authorizations,
105 FERC ¶ 61,218 (2003).
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transmission providers verify firmness
of such transmission arrangements
provides a significant benefit to the
system and is not unduly burdensome.
The confirmation or lack thereof of
service on the third-party’s system
should be readily available on OASIS. If
firm third-party service is not confirmed
in OASIS, the transmission provider
should attempt to remedy any
information deficiency in the request
through informal communications with
the network customer. If such efforts are
unsuccessful, the transmission provider
should find the request to designate the
network resource deficient. Because this
information is available on OASIS, we
disagree with Detroit Edison’s request
that the Commission require proof that
customers have obtained requisite
transmission service on external
systems.
1528. We also disagree with SPP’s
argument that it should not be required
to police the additional restrictions on
the designation of network resources,
since it has neither the data nor the
personnel necessary to perform this
function. The only ‘‘additional’’
restrictions that the transmission
provider is called upon to police is that
network customers submit the
appropriate attestations when
requesting designation of a network
resource, which places a particularly
small burden on the transmission
provider. We also do not expect the
requirement that transmission providers
verify the firmness of the network
customer’s transmission arrangements
on other transmission systems to require
any additional data or personnel.
1529. We reject Dynegy’s request that
the validity of network resource
designations be verified not only by the
designating customer, but also by the
seller or owner of the generation, in
order to help ensure that all network
resources are in fact backed by capacity.
Similarly, we deny Entegra’s request
that the customer be required to make
additional, periodic OASIS postings to
demonstrate that it has rights to the
power from a designated resource. We
find that such additional verifications
are unnecessary in light of the new
attestation requirements.
1530. With regard to arguments that
requiring an attestation may disrupt
service, the alleged confusion over the
Commission’s requirements for
designation of network resources seems
primarily concerned with whether the
EEI Firm LD Product and similar
products were eligible to be designated
as network resources and whether
certain resources can be designated both
to serve native load and other network
customers. As we have addressed both
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of these questions above, we believe that
many of the concerns about the
attestation requirement are resolved.
Commenters have not supported claims
that the attestation requirement will be
either burdensome or that the
requirement will require substantial
time to comply. As noted above, the
minimal additional network resource
designation requirements impose in this
Final Rule beyond the existing
requirements are not expected to be
unduly burdensome. While exceptions
may be appropriate in cases of
legitimate emergencies, we disagree
with the implication that a customer
should be granted general flexibility to
designate a network resource that
otherwise may not be eligible.
1531. In response to Entergy’s request,
we agree that attestations will not be
required to be submitted until the
service request is confirmed. However,
if the request is pre-confirmed, we agree
that the attestation must be provided at
the time the request is submitted.
1532. In response to TranServ’s
request that the exact nature of how the
customer would make an attestation
should be determined in the NAESB
forum, we note that the contents and the
specific information that is required to
be provided with the attestation are
specified in the pro forma OATT, and
we are requiring that the attestation be
submitted through OASIS with each
request to designate a new network
resource. The appropriate subject for
transmission providers to coordinate
with NAESB to resolve is limited to the
appropriate formatting of such
information to be provided in OASIS. In
response to TranServ’s request that
NAESB should also determine the
treatment of OASIS requests where the
customer fails to provide the necessary
attestation, we point out that we have
already directed that such requests are
to be found deficient by the
transmission provider and treated in
accordance with the procedures in
section 29.2 of the pro forma OATT.
1533. We reject requests to require
network customers designating network
resources in an external control area to
provide certification from that control
area’s administrator that the resource
being designated is not counted as a
designated resource for another load on
or off the system. We find that, in
absence of any evidence that the
Commission’s new attestation
requirements will be insufficient, this
requested verification appears
unnecessary.
c. Undesignation of Network Resources
1534. Section 28.2 of the pro forma
OATT requires the transmission
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12463
provider, on behalf of its native load
customers, to designate resources and
loads in the same manner as any
network customer under Part III of the
pro forma OATT (Network Integration
Transmission Service). The information
provided by the transmission provider
must be consistent with the information
it uses to calculate ATC. Section 30.3 of
the pro forma OATT previously allowed
the network customer to terminate the
designation of all or part of a generating
resource as a network resource at any
time, but stated that the network
customer should provide notification to
the transmission provider as soon as
reasonably practicable.
1535. In Order No. 888–B, the
Commission clarified that the pro forma
OATT allows network customers to
designate network resources over
shorter time periods. The Commission
indicated that a network customer that
seeks to engage in firm sales from its
currently designated network resources
may terminate the generating resource
(or a portion of it) as a network resource
pursuant to section 30.3 of the pro
forma OATT and request that, as set
forth in section 29 of the pro forma
OATT, the same generation resource be
designated as a network resource
effective with the end of its power
sale.890
NOPR Proposal
1536. In the NOPR the Commission
proposed to continue to allow network
customers to ‘‘undesignate’’ 891 a portion
of their network resources on a shortterm basis to make off-system sales. The
Commission reiterated that a network
customer may redesignate the resource
by making a request to designate a new
network resource. Additionally, the
Commission reiterated that the
transmission provider and all network
customers must designate their network
resources and are prohibited from
making firm third-party sales from
designated network resources. The
Commission stated that, to the extent
the transmission provider or a network
customer wants to make a firm sale from
a network resource, it must undesignate
the resource pursuant to section 30.3 of
the pro forma OATT. The network
customer, including the transmission
provider itself, could request to
redesignate the resource by making a
request to designate a new network
resource pursuant to section 30.2 of the
pro forma OATT.
890 Order
No. 888–B at 62,093.
general term ‘‘undesignation’’ refers to
both temporary terminations and indefinite
terminations of network resource status, as
discussed below.
891 The
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1537. The Commission also sought
comment on the amount of time prior to
operation that the transmission provider
and other network customers should be
required to terminate a network
resource to ensure that the appropriate
set of network resources are included in
the ATC calculation.
(1) Overview
Comments
1538. Most commenters appear to
support the Commission’s proposal to
continue to allow network customers to
undesignate a portion of their network
resources on a short-term basis to make
off-system sales. However, many
commenters request clarification that a
temporary undesignation will not cause
them to forfeit their rights to
transmission priority or ATC for any
other time period. Several commenters
also request that formal undesignations
not be required or that the process not
be burdensome. A wide range of
comments were received in response to
the Commission’s request for comments
on the amount of time prior to operation
that the transmission provider and other
network customers should be required
to terminate a network resource to
ensure that the appropriate set of
network resources are included in the
ATC calculation.
sroberts on PROD1PC70 with RULES
Commission Determination
1539. The Commission generally
adopts the NOPR proposal to continue
to require network customers and the
transmission provider’s merchant
function to undesignate network
resources or portions thereof in order to
make certain firm, third-party sales from
those resources. In particular, network
customers and the transmission
provider’s merchant function may only
enter into a third-party power sale from
a designated network resource if the
third-party power purchase agreement
allows the seller to interrupt power
sales to the third party in order to serve
the designated network load. Such
interruption must be permitted without
penalty, to avoid imposing financial
incentives that compete with the
network resource’s obligation to serve
its network load.
1540. We clarify that requests to
undesignate network resources that are
submitted concurrently with a request
to redesignate those network resources
at a specific point in time shall be
considered temporary terminations.
Conversely, requests to undesignate
network resources submitted without
any concurrent request to redesignate
those network resources shall be
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considered a request for indefinite
termination of those network resources.
1541. We direct transmission
providers to develop OASIS
functionality and, working through
NAESB, business practice standards
describing the procedural requirements
for submitting both temporary and
indefinite terminations of network
resources, to allow network customers
to provide all required information for
such terminations. Such OASIS
functionality should allow for electronic
submittal of the type of termination
(temporary or indefinite), the effective
date and time of the termination, and
identification and capacity of
resource(s) or portions thereof to be
terminated. For temporary terminations,
such OASIS functionality should also
allow for electronic submittal of (1)
effective date and time of redesignation,
following the period of temporary
termination; (2) information and
attestation for redesignating the network
resource following the temporary
termination, in accordance with section
30.2 of the pro forma OATT; and (3)
identification of any related
transmission service requests to be
evaluated concomitantly with the
request for temporary termination. In
response to TranServ’s request, we
clarify that the request for temporary
termination of the resource and the
requests for the related transmission
service identified in item (3), if any,
should be evaluated as a single request,
and approved or disapproved as such.
We specifically direct transmission
providers, working through NAESB, to
develop business standards describing
the procedures for submitting and
processing requests for concomitant
evaluations of transmission requests and
temporary terminations. When
processing such requests, the evaluation
of the transmission service requests
identified in item (3) should take into
account the undesignation of the
network resources identified in the
request for termination. However, the
evaluation of the transmission service
requests in item (3) should be processed
taking proper account of all competing
transmission service requests of higher
priority.
1542. Consistent with the
requirements for requests for
designation of new network resources,
the new OASIS functionality should
also allow for queries of requests to
undesignate and redesignate network
resources. In accordance with section
37.6 of the Commission’s regulations,892
such requests must be able to be queried
892 18
PO 00000
CFR 37.6.
Frm 00200
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by the publicly available information
posted on OASIS.
1543. Transmission providers need
not implement this new OASIS
functionality and any related business
practices until NAESB develops
appropriate standards. Prior to
implementation of this new OASIS
functionality, requests for temporary or
indefinite terminations of network
resources may be submitted by
transmitting the required information to
the transmission provider by telefax or
providing the information by telephone
over the transmission provider’s time
recorded telephone line.
(2) Risk to ATC Rights
Comments
1544. Most commenters request
clarification that a temporary
undesignation of a network resource
does not constitute a forfeiture of
priority followed by a new request to
designate the network resource, or
otherwise put in jeopardy the ATC
associated with the designation of that
resource for any period other than the
period of undesignation.893 Several
commenters argue that virtually no
network customers will ever make a
firm third-party sale if they are forced to
reapply for transmission service after a
period of undesignation of their
resource, since they would run the risk
of losing the ATC associated with the
resource.894 EEI and Entergy contend
that the result of such a policy would be
that the industry would no longer be
able to take advantage of the diversity of
peak loads to make firm sales and
purchases, and an almost immediate
shortage of firm energy sources to serve
network and native loads. Duke argues
that the approach of not compelling
network customers to risk losing the
ATC associated with their designated
resources beyond the period that the
resource is designated would be the
`
comparable approach vis-a-vis point-topoint customers seeking to temporarily
redirect their service.
1545. Southern argues that to treat a
redesignation as an entirely new
application for network resource
designation would appear to depart
from existing tariff requirements and
unnecessarily limit the reliability of
network customers’ service. It also
argues that such an approach would be
in contravention with section 217(b)(4)
of the FPA, which directs the
893 E.g., Duke, EEI, Entergy, Exelon, MDEA Reply,
Northwest Parties, Pinnacle, Progress Energy, South
Carolina E&G Reply, Southern, TDU Systems Reply,
TranServ, and WSPP Reply.
894 E.g., Duke, EEI, Entergy, Progress Energy,
South Carolina E&G Reply, and TranServ.
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Commission to act in a manner that
facilitates the planning and expansion
of facilities to meet the reasonable needs
of LSEs to satisfy the service obligations
of the LSEs. Southern contends that the
NOPR proposal would create
administrative burdens on transmission
providers, potentially treat network
service as an inferior product to long
term point-to-point transmission
service, and introduce a substantial
deterrent against optimization of
network resources by network
customers.
1546. On the other hand, Great
Northern initially requests that ATC not
be set aside for a former network
resource in anticipation that it might be
designated as a network resource at
some time in the future. In order to
ensure comparable treatment for all
transmission service customers, Great
Northern argues, the Commission
should place new requests to designate
network resources at the end of the
transmission queue, regardless of the
prior designation of those resources.
Great Northern clarifies on reply that,
while ATC should not be set aside for
former network resources in
anticipation that it might be designated
as a network resource at some
unspecified time in the future, it has no
objection to setting aside ATC to be
used by a formerly designated network
resource after a temporary, specified
period of undesignation such as one
month or one season.
1547. NorthWestern, in its reply
comments, disagrees with Great
Northern’s initial comments that new
designations be placed at the end of
transmission service queue regardless of
the prior designation of those resources.
NorthWestern argues that such a policy
would unduly discriminate against the
network customer who is paying for the
use of the entire transmission system
and grant an undue preference to the
point-to-point customer. NorthWestern
also argues that the proposal that ATC
not be set aside for an undesignated
network resource appears to conflict
with the Commission’s standard
interconnection procedures for large
and small generators. Once all upgrades
specified through the interconnection
process have been installed,
NorthWestern contends that the
generator can be specified as a network
resource by any customer, at the time of
commercial operation for the generator
or at any time in the future.
1548. TAPS appears to support a
requirement that transmission
customers get back in the queue when
re-designating resources, so long as the
rules apply to transmission providers as
well as network customers.
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Commission Determination
1549. In response to the many
requests and comments, we clarify that
a request for termination of a network
resource that is concurrently paired
with a request to redesignate that
resource at a specific point in time will
not result in the network customer
permanently forfeiting rights to use that
resource as a designated network
resource. Any change in ATC that is
determined by the transmission
provider to have resulted from the
temporary termination shall be posted
on OASIS during this temporary period.
We agree that requiring network
customers making temporary
terminations to permanently forfeit
rights to use this ATC would
significantly reduce or eliminate firm
third-party power sales. We emphasize,
however, that a request to terminate a
network resource that is not
accompanied with a request to
redesignate that resource at a specific
point in time is to be considered an
indefinite termination. After an
indefinite termination of a resource, the
network customer has no continuing
rights to the use of such resource and
future requests to designate that
resource would be processed consistent
with section 30.2 as a designation of
new network resource.
1550. We disagree with
NorthWestern’s argument that, once
upgrades specified through the
interconnection process have been
installed, the generator can be specified
as a network resource by any customer,
at the time of commercial operation of
the generator or at any time in the
future. The Commission has long noted
that the generator interconnection
process is separate and independent of
the acquisition of transmission service
for the same generator.895 The fact that
system upgrades may be required to
interconnect a generator does not mean
any network customer is entitled to the
use of that generator at all times, even
in the event that the network customer
indefinitely terminates the designation
of that resource. The integration of
network resources with different
network customers presents different
effects and flows on the transmission
system that must be evaluated by the
transmission provider.
(3) Minimum Lead-Time
Comments
1551. EEI and Entergy argue that the
Commission should not require
transmission providers or network
customers to undesignate a network
895 See,
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12465
resource for a specific amount of time
prior to the commencement of an offsystem sale. In many instances, EEI
argues, short-term firm power sales are
made with relatively little lead time,
particularly after events such as forced
outages or unusual weather conditions.
EEI and PNM–TNMP argue that
requiring transmission providers or
network customers to undesignate a
specific amount of time prior to an offsystem sale would foreclose the
possibility that firm sales could be made
with short lead times. That, EEI argues,
would adversely affect the sales market,
without having any impact on ATC on
the path used by the network resource
because the network resource would not
be undesignated. In EEI’s view,
imposing lead times on undesignations
of network resources would also result
in treating network and native load
customers less favorably than point-topoint customers. EEI points out that the
pro forma OATT does not impose any
minimum lead times on firm redirects of
point-to-point transmission service
pursuant to section 22 of the pro forma
OATT or reassignment of transmission
service pursuant to section 23 of the
OATT, despite the fact that advance
notice of redirects might make the
resultant ATC more marketable.
1552. Most commenters, however,
appear to support the establishment of
a minimum amount of time prior to
operation that the transmission provider
and other network customers should be
required to terminate a network
resource to ensure that the appropriate
set of network resources are included in
the ATC calculation, although they
express widely varying opinions on
what period of time would be
appropriate.
1553. Ameren and Pinnacle contend
that the amount of time prior to
operation that the transmission provider
and other network customers should be
required to terminate a network
resource should be linked to the
frequency of the calculation that gets
standardized in the ATC process.
Pinnacle contends that, if the
undesignation and redesignation are
performed on OASIS as they propose,
ATC could be recalculated and posted
immediately following the
undesignation or redesignation. Ameren
contends that it cannot comment further
until the parameters of the ATC process
are defined. FirstEnergy states that the
amount of time should be consistent
with the time periods required in
markets, and that outside of markets,
times should be established that
coincide with such markets. Southern
argues that the current practice, under
which a resource is undesignated when
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1558. We find it unnecessary to
incorporate into the pro forma OATT
provisions relaxed rules for changing
the undesignation of network resources
at any time to handle system
emergencies, force majeure events,
forced outages or unusual weather
conditions, as suggested by some
commenters. Other procedures such as
those in NERC’s standard for Capacity &
Energy Emergencies, EOP–002–2, or the
possible use of capacity benefit margin,
are more appropriate to deal with
legitimate system emergencies. Outside
the context of legitimate system
emergencies, network customers should
rely on appropriate planning and
operation, rather than relaxed rules for
designation of network resources.
1559. We disagree with EEI’s
argument that requiring a minimum
lead-time will result in treating network
and native load customers less favorably
than point-to-point customers. In
particular, EEI is incorrect in its
statement that the OATT does not
impose any minimum lead times on
firm redirects of point-to-point
transmission service or reassignments of
transmission service. Firm point-topoint customers are also subject to
deadlines for scheduling redirects
pursuant to section 22.2 of the pro
forma OATT. Furthermore, we find that
EEI has provided no compelling
evidence to support its argument that
the adverse impacts on the market for
firm energy with short lead times
justifies having no minimum lead time.
Commission Determination
sroberts on PROD1PC70 with RULES
it schedules point-to-point transmission
service for an off-system sale, provides
adequate time to ensure that the
appropriate set of network resources is
included in the ATC calculation.
1554. PJM notes that, under its
system, a generator resource with excess
capacity can undesignate the excess
resource on a ‘‘day ahead’’ basis. PJM
believes that this is the proper amount
of time needed to ensure resource
adequacy. PJM argues that a generator
should not, under any circumstance,
change the designation of its resource
‘‘same day.’’
1555. TranServ argues that, at a
minimum, a request for undesignation
should be supplied no later than the
firm scheduling deadline so that
released capacity may be acquired on a
non-firm basis. If that data were
required to be submitted earlier than the
scheduled deadline, TranServ suggests
the transmission provider may be able
to offer incremental capacity for firm
sales. TranServ requests that the
Commission establish in the pro forma
OATT some nominal timeframe for
network customers to provide to the
transmission provider their planned use
of designated resources to serve loads.
1556. Nevada Companies requests
that, due to some system emergencies,
force majeure events, and hourly
scheduling of tie-line changes, they be
allowed to change undesignation of
network resources at any time to handle
these types of events.
(4) General
1557. Commenters presented many
alternative views in response to the
Commission’s request in the NOPR for
comments on the appropriate minimum
lead-time prior to operation that the
transmission provider and other
network customers should be required
to terminate a network resource to
ensure that the appropriate set of
network resources are included in the
ATC calculation. In consideration of
these comments, the Commission finds
that the appropriate requirement is that
network customers not be permitted to
make firm third-party sales from any
designated network resource without (1)
undesignating that resource for the
period of the third-party sale pursuant
to pro forma OATT section 30.3 and (2)
providing notice of such undesignation
before the firm scheduling deadline (10
a.m. the day before service commences).
We find that this requirement strikes the
appropriate balance, allowing
undesignated capacity to be acquired on
a non-firm basis but not creating an
undue adverse effect on third-party
sales.
Comments
1560. Several commenters argue that
the Commission should not require
network customers or the transmission
provider to make formal modifications
to their designations of network
resources when they make firm sales to
third parties from those resources.896
EEI and Southern argue that the practice
of most network customers and
transmission providers in the ten years
since the Commission issued Order No.
888 has been that a network resource is
undesignated for any period for which
the customer requests firm point-topoint transmission service from the
generator or a third party. This practice,
EEI argues, has not resulted in any
adverse impacts on reliability or on the
availability of transmission service and
that, to the contrary, selling energy from
network resources on a firm basis
instead of a non-firm basis frees up firm
transmission capacity that otherwise
would have to be reserved for the
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896 E.g., EEI, NRECA Reply, PNM–TNMP, and
Southern.
PO 00000
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network customer. EEI and NRECA
contend that requiring formal
undesignations is substantially more
cumbersome for network customers and
transmission providers making offsystem sales.
1561. Progress Energy and TranServ
argue that network customers should
not have to go through the process of
redesignating a network resource as new
when the network customer once again
needs to use this resource to serve
network load. TranServ argues that such
a transaction is exactly analogous to a
redirect of firm point-to-point service on
a firm basis and requests clarification of
whether the provider should evaluate a
request to undesignate a network
resource concomitantly with the
assessment of that same customer’s
point-to-point request, as is done with
redirects on a firm basis.
1562. NRECA states that the
undesignation requirement is too
burdensome and, therefore, the
Commission should adopt a
comparability requirement that would
allow network customers to utilize the
practice that many public utility
transmission providers use today: i.e.,
use designated resources for firm offsystem transactions or third party uses
without having to go through the
designation, undesignation and
redesignation process. NRECA argues
that existing scheduling procedures
have allowed transmission providers to
deliver power from their designated
network resources for off-system
merchant purposes reliably and should
perform equally well for network
customers, provided they still pay a
point-to-point charge for the
‘‘outbound’’ leg of a delivery to a
neighboring network to serve the
customer’s network load on the
neighboring network. NRECA argues in
its reply comments that, whatever the
Commission decides to do,
comparability is the most important
principle when considering the
undesignation policy and that
‘‘grandfathering’’ agreements which
would allow transmission providers to
essentially get around this requirement
would allow undue discrimination to
continue. EEI disagrees in its reply
comments with NRECA’s assertion that
transmission providers currently have
an advantage over network customers,
arguing that the same standards apply to
the transmission provider’s merchant
function and network customers when
they seek to make off-system sales from
network resources.
1563. PNM–TNMP contends that the
Commission has held that formal
undesignation and redesignation are not
required, so long as the transmission
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provider treats its own resources and
the network resources of network
customers comparably. PNM–TNMP
and Pinnacle further argue that to
require formal undesignation and
redesignation would appear to do
nothing more than impose an extra layer
of administration to the management of
network resources, making power sales
more difficult and potentially reducing
financial benefits to end use customers.
Bonneville argues that the
Commission’s proposals regarding the
use of network resources for surplus
sales are likely to raise the cost to
consumers.
1564. Duke requests that the
Commission clarify that any product
that is not ‘‘designatable’’ as a network
resource by a buyer may be sold by a
seller that happens to be a network
customer, without having to
undesignate any network resources.
1565. Suez Energy NA requests that
the Commission ensure that a utility
cannot use redesignation to hoard
transmission capacity in order to
deprive independent power producers
of access to the grid. It contends that a
utility could consistently hold
transmission to serve generation that
never runs for economic reasons and,
the day before power flows, redesignate
that transmission to accommodate a
third-party purchase, effectively using
its ability to redesignate network
transmission capacity to hoard scarce
ATC. In order to prevent potential
abuse, Suez Energy NA agrees with the
NOPR proposal to require transmission
providers to use the same OASIS
procedures to designate and terminate
network status for themselves that they
apply to network customers.
1566. If the Commission requires
formal designations and undesignations,
EEI asks the Commission to clarify
whether it is changing its policy that it
is not necessary to modify service
agreements in such circumstances in
order to avoid requiring transmission
providers to make numerous filings
amending service agreements.897 If
formal undesignations are required, EEI
argues on reply that each transmission
provider would be required to submit a
revised application for network service
under section 29.2 of the pro forma
OATT both at the time the resource was
undesignated and at the time that
resource was redesignated. EEI also
argues that formal undesignation would
require the execution and filing of
897 See
Virginia Electric and Power Co., 81 FERC
¶ 61,125 at 61,111–12 (1997), reh’g denied, 82 FERC
¶ 61,034 (1998).
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revised network service agreements
reflecting the changes.
1567. South Carolina E&G argues in
its reply comments that off-system sales
of firm power are typically in the form
of a slice-of-system sale. South Carolina
E&G requests that the Commission
provide guidance for how to treat such
a sale of power, suggesting that the
transmission provider be permitted to
undesignate a slice of a system
sufficient to support the firm power sale
and then, at the conclusion of the sale,
redesignate that slice of the system as a
network resource.
1568. While generally supporting the
Commission’s proposal to continue to
allow network customers and the
transmission provider, with respect to
its native load, to undesignate network
resources to allow them to make sales to
third parties, some commenters seek
certain changes, consideration, or
clarification by the Commission.898 EEI,
joined by TDU Systems on reply, argue
that the Commission should modify its
statement that network customers
should be permitted to undesignate
network resources ‘‘on a short-term
basis to make off system sales.’’ They
argue that nothing in Order No. 888, the
Commission’s decisions, or the public
interest requires that network resources
be undesignated only for short-term
sales. They further argue that such sales
need not be ‘‘off-system.’’ Progress
Energy argues that the Commission
should only allow transmission
customers to undesignate network
resources to make firm off-system sales
for a term which the transmission
customer has adequate generation
reserves to serve its network load. In its
view, the transmission provider also
must have the authority to deny the
designation or undesignation of the
network resources if the transmission
provider determines that it needs the
network resources to preserve the
reliability of its transmission system or
to ensure that there is sufficient
transmission capability to support the
requested changes. NRECA disagrees on
reply, arguing that granting transmission
providers the authority to deny
undesignation requests would give them
too much discretion and the perfect
opportunity to discriminate.
1569. Progress Energy agrees with the
Commission that network service
involves the entire transmission
provider’s system and does not involve
a contract path like point-to-point
service. It also agrees that the delivery
of a network resource once inside the
system does not need to be redirected.
Progress Energy notes that peaking
898 E.g.,
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resources have low capacity factors and,
therefore, their transmission
reservations are frequently
underutilized. They request that
network customers be given the ability
to optimize their transmission
purchases by bringing energy into the
host transmission provider’s system
from other designated network
resources in times when they are not
using their peaking designated
resources.
1570. MDEA, Progress Energy, and
Entergy request that, for reliability and
economic reasons, network customers
be given the flexibility to substitute new
designated network resources without
abandoning the original transmission
queue position of an existing designated
network resource.899 If the Commission
does not change its proposal in order to
provide network customers with this
flexibility, Progress Energy contends
that point-to-point service will be a
superior service to network service.
1571. Entergy states that it is
important for the Commission to
recognize that the undesignation of
network resources can be used by
network customers as a means of
allowing merchant generators the
opportunity to displace existing
resources in serving network and native
load. It argues that the Commission
should be wary of limiting the ability of
a network customer to undesignate
network resources, as any such
restriction will have broader
implications than just the ability of
network customers, including the
transmission provider’s wholesale
merchant function, to sell that resource
off-system with point-to-point service.
1572. Entergy also requests that the
Commission clarify that, while network
customers cannot redirect network
service, nothing in this prohibition
prevents transmission providers from
studying requests to designate new
network resources as displacements of
existing network resources. It argues
that preventing network customers from
using automated study functions would
significantly hinder the ability of these
customers to substitute their existing
long-term resources with short-term
purchases of energy and capacity from
merchant generators when it is
economical to do so.
1573. TDU Systems argue that
network customers (and transmission
providers to the extent they serve native
load on other systems) should be able to
schedule output on a firm basis from
899 In its reply comments, MDEA requests that
any such flexibility afforded to transmission
providers also be available to network customers on
a non-discriminatory basis.
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network resources on one system to
serve their network loads on
neighboring systems without having to
designate and redesignate network
resources among the various
transmission providers’ control areas.
TDU Systems state this would permit
LSEs that serve across multiple systems
to come closer to replicating the
economic dispatch of control area
operators, significantly reducing the
cost of discharging their service
obligations to the customers they serve.
1574. Xcel opposes requiring a
transmission customer to undesignate a
network resource even in a situation
where the resource is used only
transiently to provide off-system sales,
arguing that such policy would have
significant adverse consequences for
customers across the country. It points
out that it is native load customers that
frequently benefit from purchase of
economy energy and that, if an
undesignation was required to deliver
economy energy, most such transactions
likely would not occur. Xcel also argues
the NOPR concepts relating to
designation of network resources and
justification of economy energy
purchases are irrelevant in the context
of an RTO where energy is procured and
dispatched throughout the RTO on a
security constrained economic basis.
1575. EEI, joined by TDU Systems on
reply, requests that the Commission
clarify that any changes to the
procedures for designating and
undesignating network resources apply
only to designations made after the
Final Rule becomes effective, in order to
avoid substantial adverse impacts on the
reliability of service to network and
native loads. Duke and Pinnacle request
that the Commission require NAESB to
develop standards that address
undesignation and redesignation and
allow sufficient time for the NAESB
process and for OASIS tools to be
developed and approved, prior to the
implementation of a new policy.
TranServ asks that the undesignation of
network resources be supported on
OASIS.
Commission Determination
1576. We disagree with commenters
arguing that formal undesignations and/
or redesignations of resources used to
make firm third-party sales should not
be required. The undesignation and
redesignation requirements exists not
only to promote reliability, but also to
prevent undue discrimination, promote
comparable treatment of customers, and
increase the accuracy of ATC
calculations. We find that the interest in
advancing these policy goals overrides
the minimal burden and cost that
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submitting undesignations and/or
redesignations entails. We disagree with
Xcel’s argument that most economy
energy purchases that benefit its native
load customers likely will not take place
if undesignation of network resources is
required prior to firm, third-party sales.
First, the requirement to undesignate
network resources only applies to firm
sales, while typical non-firm economy
energy transactions would not require
undesignation. Second, undesignating a
network resource is not unduly
burdensome, consisting only of
electronically submitting several items
of information, as described above.
Therefore, we do not believe that a
transaction prevented purely as a result
of the requirement to undesignate
network resources would have provided
any significant economic value had it
taken place.
1577. We find that requests to allow
‘‘informal undesignations’’ appear to be
simply requests to not require
undesignations at all. Since the salient
feature of requiring an undesignation is
that the proper account is taken of the
effects on ATC, informal
undesignations, which do not take
proper account of the fact that a
resource is no longer a designated
network resource, appear to serve no
purpose.
1578. With regard to PNM-TNMP’s
argument that the Commission has held
that formal undesignation and
redesignation are not required, so long
as the transmission provider treats its
own resources and the network
customer’s resources comparably, we
believe PNM-TNMP misunderstands our
policies. We note that PNM-TNMP
provides no citation to Commission
precedent to support its statement.
1579. Duke requests clarification as to
whether a network customer must
undesignate a network resource in order
to make a third-party sale from that
resource if the third-party sale would
not itself qualify to be designated as a
network resource. We reiterate the
existing requirement that designated
network resources must not be
committed for sale to non-designated
third-party load or include resources
that otherwise cannot be called upon to
meet the network customer’s network
load on a noninterruptible basis. We
find that a resource is ‘‘committed for
sale to a non-designated third party
load’’ if a power purchase agreement for
the sale from that resource provides for
penalties if service to the third party is
interrupted in order to serve the
designated network load.
1580. In response to comments by
EEI, NRECA, and Suez Energy NA, we
reiterate that all parties, including
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transmission providers serving their
native loads, are subject to these
requirements for designation and
undesignation of network resources.
Section 28.2 of the pro forma OATT
clearly provides that transmission
providers are required to designate
resources and loads in the same manner
as any network customer. We encourage
parties suspecting that transmission
providers or other network customers
are not conforming to the requirements
for designating or undesignating
network resources to report their
concerns using the Commission’s
Enforcement Hotline.
1581. EEI has requested clarification
of whether the Commission is changing
its policy that transmission providers do
not need to modify network service
agreements when network resources are
undesignated and redesignated. We
have not proposed and do not intend to
begin requiring that network customers
file modified service agreements when
network resources are designated or
undesignated. As we explained in
Dayton Power and Light Co.,900
‘‘changes in network resources may
require the customer to file a request
under OASIS, but a change to the
information recorded initially in the
network service agreement is not a
requirement.’’ EEI also argues that, if
formal undesignations are required,
then each transmission provider would
be required to submit a revised
application for network service under
section 29.2 of the pro forma OATT,
both at the time the resource was
undesignated and the time that resource
was redesignated. We disagree. There is
no requirement that a transmission
provider submit a revised application
for network service every time a
resource is designated or undesignated.
1582. In response to a request by
South Carolina E&G, we clarify that firm
third-party sales may be made from an
undesignated portion of a network
customer’s network resources (i.e., a
‘‘slice-of-system sale’’), so long as all of
the applicable requirements are met. In
particular, the network customer must
submit undesignations for each portion
of each resource supporting the thirdparty sale. If the undesignation is
temporary, then the request must be
accompanied by a request to redesignate
the resource(s) on a specific date. When
the undesignation takes effect, the
network customer must update the
capacities specified in its list of
designated network resources posted on
OASIS.
1583. We agree with EEI and TDU
Systems’ comments that there should be
900 93
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no minimum term for undesignations.
We also agree with EEI and TDU
Systems’ arguments that network
customers should not be restricted to
temporarily undesignating network
resources only for use in off-system
sales, and clarify that network
customers are not so restricted.
1584. We agree with Progress Energy
that network customers should only
make firm third-party sales when they
have sufficient generation reserves to
serve their loads. However, the purpose
of the pro forma OATT is to provide
nondiscriminatory transmission access,
not to enforce generation adequacy
requirements.
1585. With regard to Progress Energy’s
request for flexibility to evaluate
potential impacts to the transmission
system related to the undesignation and
redesignation of network resources, we
find that situations where
undesignations cannot be
accommodated due to transmission
constraints should be extremely rare,
such as highly-extraordinary
counterflow situations. In such rare
situations, the transmission provider
should attempt to remedy the situation
without denying the undesignation. If it
is determined that the resource cannot
be undesignated without jeopardizing
reliability, then the transmission
provider may deny the request for
undesignation.
1586. We share NRECA’s concern that
allowing transmission providers to deny
undesignations for reliability reasons
could give a direct market competitor a
significant opportunity to discriminate,
but must weigh this concern against our
significant interest in preserving
reliability. We point out that
transmission providers denying requests
for service or changes to service because
of reliability concerns must post a
description of such denials in
accordance with section 37.6(e)(2) of the
Commission’s regulations.901 Again, we
encourage any parties with concerns
about denials of service or changes to
service by a transmission provider for
reasons of reliability to report their
concerns to the Commission’s
Enforcement Hotline.
1587. We deny requests by MDEA,
Progress Energy, and Entergy that
network customers be given the
flexibility to substitute new designated
network resources without abandoning
the original transmission queue position
of an existing designated network
resource. These parties seem to be
requesting that a network customer be
allowed to be ‘‘first in line’’ to use the
ATC freed up by an undesignation of a
901 18
CFR 37.6(e)(2).
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network resource, as long as the
network customer uses that ATC to
designate an alternate resource. We
disagree. Granting this request would,
without any apparent justification, put
point-to-point customers seeking ATC
freed up by an undesignation at a
disadvantage. We also disagree that, if
the Commission does not allow network
customers this flexibility, point-to-point
service will be a superior service to
network service. Progress Energy seems
to be arguing that the point-to-point
customer’s ability to engage in a redirect
affords that customer more flexibility
than the network customer. We point
out that redirects of point-to-point
service on a firm basis are only on an
‘‘as-available’’ basis. Firm point-to-point
customers cannot redirect unless ATC is
available to support such a redirect after
all higher-priority requests have been
accommodated.
1588. Entergy has requested
clarification that, while network
customers cannot redirect network
service, nothing in this prohibition
prevents transmission providers from
studying requests to designate new
network resources as displacements of
existing network resources. Although
Entergy’s request is unclear, we reiterate
that redirects are not allowed within the
context of network service and that
network customers are not ‘‘first in line’’
to use ATC freed up by their
undesignation of another network
resource. Such requests must be
processed taking proper account of all
competing transmission service requests
of higher priority.
1589. We disagree with TDU System’s
argument that network customers
should be able to schedule output on a
firm basis from network resources on
one system to serve their network loads
on neighboring systems without having
to designate and redesignate network
resources among the various
transmission providers’ control areas.
Allowing network customers to not
formally undesignate and redesignate
network resources, even only when
using those resources to serve their
network loads on neighboring systems,
will necessarily result in inaccurate
evaluations of ATC. We reiterate that
the burden associated with
undesignating and redesignating the
resources is particularly light and find
that requiring network customers to
make temporary undesignations when
making third-party firm sales is thus
justified in light of the ATC-related
benefits.
1590. Xcel argues that the concepts
relating to designation of network
resources are irrelevant in the context of
an RTO where energy is procured and
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12469
dispatched throughout the RTO on a
security constrained economic basis. We
agree that Day 2 RTOs do not use the
physical rights model contemplated
under the pro forma OATT and, hence,
not all the provisions discussed here are
directly applicable to Day 2 markets.
However, as we explain in section
IV.C.2, RTOs and ISOs must make the
necessary filings to comply with the
Final Rule, or demonstrate that their
existing tariff provisions are consistent
with or superior to the terms of the
revised pro forma OATT.
1591. We agree with parties arguing
that network customers should not be
required to use the new NAESB
processes and OASIS tools to be
developed in response to this section
until such time as the NAESB standards
and OASIS functionality have been
developed and implemented. However,
once the new standards and
functionality are in place, network
customers must use these new
procedures to undesignate (whether
temporarily or as part of an indefinite
termination) any network resources,
regardless of the date that those
resources were originally designated.
7. Clarifications Related to Network
Service
a. Secondary Network Service
1592. Section 28.4 of the existing pro
forma OATT allows a network customer
to deliver energy to its network load
from non-designated network resources
on an as-available basis without
additional charge, referred to as
secondary network service. In Order No.
888, the Commission described such
energy as non-firm economy energy
purchases used to displace firm network
resources.902
1593. The use of secondary network
service to deliver purchased power
when a network customer is making offsystem sales has been raised in several
Commission investigations and audits.
In Idaho Power, the Commission
accepted a settlement with Idaho Power
related to Idaho Power’s incorrect use of
the native load priority to access its
transmission system.903 In Idaho Power,
the utility’s wholesale merchant
function purchased power outside of
Idaho Power’s control area to facilitate
an off-system sale and used secondary
network service to bring the purchases
into Idaho Power’s control area.904 In
accepting the settlement, the
Commission stated that ‘‘[i]t is
axiomatic that the native load priority
902 Order
No. 888 at 31,751.
Power Co., 103 FERC ¶ 61,182 at P 2
(2003) (Idaho Power).
904 Id. at P 4.
903 Idaho
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cannot be used to complete sales that
are not necessary to serve native
load.’’ 905 In MidAmerican, the
Commission issued an audit report that
contained a finding that MidAmerican’s
wholesale merchant function used
network service instead of point-topoint service to deliver short-term
energy purchases to its control area that
were not used to serve MidAmerican’s
native load.906
NOPR Proposal
1594. In the NOPR, the Commission
proposed to clarify that a network
customer may not use secondary
network service to import energy onto
its system to support an off-system sale
if the purchased power does not
displace the customer’s own higher cost
generation. The Commission therefore
proposed to modify section 28.4 of the
pro forma OATT to state that a network
customer may use secondary network
service only to deliver economy energy
and to define ‘‘economy energy’’ as
energy purchased by a network
customer that displaces the customer’s
own higher cost generation for the
purpose of serving the customer’s
designated network loads. The
Commission further explained that all
participants engaging in purchases for
resale must compete on a comparable
basis and use point-to-point service to
complete all segments of a purchase for
resale off-system.
(1) Overview
Comments
sroberts on PROD1PC70 with RULES
1595. Several commenters agree with
the Commission and support the
proposed clarification regarding the use
of secondary network service.907 Alberta
Intervenors state that such a restriction
ensures fair competition among network
customers and preserves the entitlement
of native load customers.
1596. Other participants oppose the
proposal, arguing that it is too broad and
would interfere with legitimate activity
by network customers.908 EEI points out
that, if a network customer is using all
available network resources but is still
purchasing energy from non-designated
network resources to meet its peak
native load, the network customer
would need to rely on secondary service
to transmit this purchase. In EEI’s view,
the Commission’s proposal would
prevent this customer from using
905 Id.
906 MidAmerican Energy Co., 112 FERC ¶ 61,346
at P 6 (2005).
907 E.g., Alberta Intervenors, Southern, Suez
Energy NA, and TAPS.
908 E.g., EEI, Entergy, Northwest Parties, NRECA,
Pinnacle, PGP, Southern, and Xcel.
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secondary service for this non-economy
energy, thereby interfering with its
service obligations. To avoid such cases,
EEI, Pinnacle, and PGP recommend that
secondary service not be limited to
economy energy only. NRECA states
that the Commission’s proposed
limitation on the use of secondary
service would prevent network
customers from meeting their native
load obligations in cases of extreme
weather and power outages. NRECA
asks the Commission to state explicitly
in section 28.4 of the pro forma OATT
that secondary service may not be used
to facilitate off-system third party sales,
but rather must be used to import power
needed to serve network load
economically and efficiently. Entergy
suggests the Commission abandon the
limitation and specify simply that
secondary service cannot be used to
serve loads other than the network or
native load.
1597. Others argue that the restriction
of secondary service to only economy
energy would have unintended
consequences regarding the purchase of
renewable resources. Emerald, Flathead,
and the Northwest Parties state that, for
reasons of customer demand or
contractual obligation, network
customers may be required to purchase
renewable power that generally is more
expensive than traditional thermal or
hydro electric generation. These
purchases could displace less expensive
non-renewable resources, resulting in
the need for the network customer to
make off-system sales of the nonrenewable resources. Emerald, Flathead,
and Northwest Parties suggest that the
Commission revise the definition of
‘‘economy energy’’ to include an
exception for renewable energy. TAPS
raises a similar issue, asking the
Commission to clarify that economy
purchases as well as substitute
resources qualify for use of secondary
service.
1598. EEI argues that the proposed
limitation on secondary service would
require all network customers to engage
in a specific form of Commissionregulated economic dispatch, while
requiring transmission providers to
evaluate each resource and become
‘‘dispatch police.’’ Entergy, SPP, and
PGP agree. They assert that calculating
the ‘‘cost’’ of power is problematic,
inherently subjective and burdensome
because transmission providers lack the
necessary knowledge to perform this
analysis. EEI, Entergy, SPP, and PGP
instead suggest that the Commission
conduct periodic audits of secondary
service to ensure compliance with the
requirements of OATT section 28.4
rather than transmission providers.
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1599. Although Powerex supports the
Commission’s restriction on the proper
use of secondary service, it also states
that determining whether or not an
import would qualify as ‘‘economy
energy’’ would be difficult. Powerex
requests that the Commission
implement specific rules in advance of
such transactions to resolve uncertainty.
It suggests a capacity test to prevent
preferential acquisition of generation
capacity, a tariff prohibition on the use
by the network customer or its energy
affiliates of any export transmission
capacity made available on another
intertie, and the modification of
business practices governing
curtailment. In reply, Alberta
Intervenors agree with Powerex’s
proposed changes to curtailment
practices, but disagree with the other
two elements. Alberta Intervenors assert
that the tariff prohibition causes
inefficient use of ATC and that the
capacity test is not a stand-alone test
and, as a result, would only be helpful
as a supplement to the ‘‘economy
energy’’ test.
1600. Some participants raise other
issues not addressed in the NOPR.
South Carolina E&G asks that the
Commission clarify its policy on
purchases of economy energy, as well as
provide a clear definition of the
acceptable trading practices—notably
parking, hubbing, and lending—under
the current pro forma OATT. Emerald
and Flathead request the Commission to
revise the definition of ‘‘network load’’
in section 1.24 of the pro forma OATT
to allow point-to-point and network
service to the same discrete point of
delivery. Morgan Stanley asks that the
Commission explain why using
secondary service to make an off-system
purchase while there is any off-system
sale during the same interval is
improper and whether the Commission
will prohibit such activity only if the
off-system purchase and sale are part of
a single transaction. Finally, Xcel argues
that the concepts relating to designation
of network resources are irrelevant in
the context of an RTO where energy is
procured and dispatched throughout the
RTO on a security constrained economic
basis.
Commission Determination
1601. In general, the Commission
agrees with parties that favor an
expansion of the proper use of
secondary network service. Although
we affirm our finding in
MidAmerican,909 the Commission
909 MidAmerican Energy Co., 112 FERC ¶ 61,346
at P 6 (2005) (MidAmerican). Following an audit,
the Commission found that MidAmerican’s
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recognizes that there are instances
outside the proposed definition of
economy energy that warrant the use of
secondary service in order to serve
network loads reliably. The Commission
therefore declines to adopt the
definition of economy energy proposed
in the NOPR and, instead, will retain
the existing section 28.4 that permits
use of secondary network service ‘‘to
deliver energy to its Network Loads.’’
1602. With respect to Powerex’s
comments, we reject the requested
clarifications as Powerex has not fully
supported the use of its proposed
capacity test or other measures and has
not demonstrated that such test would
not preclude legitimate uses of this
priority as noted in the NOPR. If parties
suspect inappropriate use of secondary
network service, they may report the
suspected activity to the Commission’s
Enforcement Hotline or file a compliant
with the Commission pursuant to FPA
section 206. Furthermore, the
Commission’s staff will continue to
provide oversight of all tariff-related
activities through its enforcement
program.
(2) ‘‘On an as-available basis’’
1603. Section 28.4 of the existing pro
forma OATT allows a network customer
to use secondary network service to
deliver energy purchases to its network
load from non-designated resources ‘‘on
an as-available basis.’’ However, the
current pro forma OATT does not
specify how a network customer must
arrange for secondary network service.
NOPR Proposal
1604. In the NOPR, the Commission
proposed to modify section 28.4 of the
pro forma OATT to clarify that a
network customer does not need to file
an application for network service to
receive secondary service. Instead, the
customer must merely request such
service on OASIS in a manner
consistent with pro forma OATT
sections 18.1 and 18.2 (Procedures for
Arranging Non-Firm Point-to-Point
Transmission Service).
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Comments
1605. TDU Systems requests that the
Commission clarify that time constraints
located in OATT section 18.3 are not
applicable to secondary service. Section
18.3 provides that requests for non-firm
wholesale merchant function used network service
instead of point-to-point service to deliver shortterm energy purchases to its control area that were
not used to serve MidAmerican’s native load. The
Commission stressed that the use of secondary
network service is not for the purpose of serving offsystem sales. Id. at P 6. The modifications to section
28.4 adopted in this Final Rule do not alter that
limitation.
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point-to-point service shall not be made
before certain specified periods (more
than 60 days in advance for monthly
service, more than 14 days in advance
for weekly service, etc.). TDU Systems
states that some of its members
currently use secondary service to
access economy off-system purchases
where intervening transmission
constraints preclude the designation of
those resources as network resources for
long periods of time. Application of the
non-firm point-to-point service request
deadlines would impair TDU Systems’
ability to rely on secondary service in
those instances since they would extend
beyond the timing requirements set
forth in section 18.3.
Commission Determination
1606. The Commission clarifies that
secondary service must be requested in
accordance with section 18, including
the timing restrictions set forth in
section 18.3, of the pro forma OATT.
Secondary service is on an as-available
basis, and network customers should
not be permitted to lock in such service
in advance of other non-firm uses of
available transmission. Allowing lowerpriority secondary service to have a
scheduling advantage over non-firm
transmission would be inappropriate
and would discourage the use of nonfirm transmission service, thereby
minimizing the revenue credits from
non-firm transmission service that
benefit all firm transmission customers.
(3) Redirect of Network Service
1607. The current pro forma OATT
does not include any provision to
change the point of receipt for an offsystem designated network resource in
a manner similar to redirect of point-topoint service. We are aware, however,
that several transmission providers have
posted business practices that allow
network customers either to substitute
an off-system non-designated network
resource for a designated network
resource or to redirect the point of
receipt associated with an existing
network resource.
NOPR Proposal
1608. The Commission proposed to
clarify that network customers may not
redirect network service in a manner
comparable to redirect of point-to-point
service, as network service involves no
identified contract path and is,
therefore, not a directable service.
Should a network customer wish to
substitute one designated network
resource for another, the Commission
stated that it must terminate the existing
resource and designate a new one. The
Commission explained that the network
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customer could also request to
redesignate its original network resource
by making a request to designate a new
network resource. Alternatively, a
network customer could use secondary
network service when it wants to
substitute a non-designated network
resource for a designated network
resource on an as-available basis.
Comments
1609. MISO strongly supports the
Commission’s clarification stating that
network service is not a directable
service and believes that the proposal
appropriately clarifies the Commission’s
policy on redirect service. TDU Systems
and NRECA, however, believe that the
Commission should allow redirects of
network service to deliver an LSE’s
resources. TDU Systems assert that
redirect of network service is critical to
LSEs serving native load across multiple
transmission systems because it allows
the amount of flexibility necessary to
manage power supply costs. In addition,
in TDU Systems’ view, redirects have no
effect on system reliability.
1610. EEI argues on reply that it is
unclear why redirects of network
service should be allowed. The
advantage of redirecting firm point-topoint service is that the customer does
not have to pay an additional charge for
transmission service. However, both
TDU Systems and NRECA agree that
network customers should pay an
additional charge for transmission
service from network resources to offsystem loads.
1611. Sacramento alternatively
recommends that the Commission
remove the ban on off-system sales in
order to maximize efficiency in
allocating transmission capacity.
Occidental requests that the
Commission place all transmission,
including on behalf of native load,
under the OATT guidelines to ensure
that service is provided in a nondiscriminatory fashion.
Commission Determination
1612. The Commission clarifies that
network customers may not redirect
network service in a manner comparable
to the way customers redirect point-topoint service. Point-to-point service
consists of a contract-path with a
designated point of receipt and point of
delivery. Network service has no
identified contract-path and is therefore
not a directable service. Network service
instead provides for the integration of
new network resources and permits
designation of another network
resource, which has the same practical
effect as redirecting network service. If
the customer wants to permanently
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substitute one designated network
resource for another, it should terminate
the designation of the existing network
resource and designate a new network
resource. The customer could then
simply request to redesignate its original
network resource, if it so desires, by
making a request to designate a new
network resource. The ability of a
network customer to also temporarily
substitute one designated network
resource for another is addressed in
section V.D.6.
1613. The Commission rejects
Sacramento’s proposal to remove the
ban on off-system sales. Network service
is not based upon making off-system
sales, but rather on integrating a
network customer’s resources with its
load. Transmission providers must take
point-to-point transmission service for
off-system sales and network customers
should be treated comparably. The
Commission also rejects Occidental’s
request to place all transmission,
including on behalf of native load,
under the pro forma OATT. In Order
No. 888–A the Commission clarified
that a ‘‘transmission provider is not
required to ‘take service’ under its own
tariff for the transmission of power that
is purchased on behalf of bundled retail
customers.’’ 910 However, the
Commission required that transmission
providers, pursuant to section 28.2 of
the pro forma OATT, must designate
network resources and network loads in
the same manner as any network
customer. Occidental offers no
explanation why the existing
requirement of section 28.2 is not
sufficient to address its concerns.
b. Behind the Meter Generation
1614. In Order No. 888, in response to
customers with load served by ‘‘behind
the meter’’ generation that sought to
eliminate such load from their network
calculation, the Commission found that
a customer may exclude a particular
load at discrete points of delivery from
its load ratio share of the allocated cost
of the transmission provider’s integrated
system. The Commission determined,
however, that customers electing to do
so must seek alternative transmission
service, such as point-to-point
transmission service, for any load that
has not been designated as network load
for network service.911 In Order No.
888–A, the Commission stated that it
would permit a network customer to
either designate all of a discrete load as
network load under the network
integration transmission service or to
exclude the entirety of a discrete load
910 Order
911 Order
No. 888–A at 30,216.
No. 888 at 31,736.
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from network service and serve such
load with the customer’s behind the
meter generation and/or through any
point-to-point transmission service.912
1615. The Commission did not
address the subject of behind the meter
generation in the NOPR. A few
commenters nonetheless proposed
revisions to the pro forma OATT to
require netting of a network customer’s
behind the meter generation against
their network load as described in more
detail below.
Comments
1616. Some commenters argue that, in
order to meet the objective of
eliminating discrimination in the
provision of open access transmission
service, the Commission must require
comparable treatment between retail
native load and network customers by
allowing network customers to net
behind the meter generation against
their network load.913 Specifically, such
commenters argue that the Commission
should modify the current pricing rules
for network service to allow an LSE’s
load ratio share to reflect the reduction
in load caused by behind the meter
generation serving retail load.914 In
support of this position, these
commenters argue that assigning
transmission-related costs to customers
that do not rely on the transmission
provider’s system to serve load is
inconsistent with the Commission’s
cost-causation principles.915 For
example, CAC/EPUC contends that
customer generation does not cause the
transmission provider to incur costs
when power is not being sold to or
taken off the grid. Similarly, AMP-Ohio
argues that it is inappropriate to assign
a full load ratio share of transmissionrelated costs to behind the meter
generation customers that do not use the
network to the full extent of their load
ratio shares.916 Further, CAC/EPUC
asserts that measuring the customer’s
912 Order
No. 888–A at 30,258–61.
TAPS, TDU Systems, AMP-Ohio, and
CAC/EPUC.
914 TDU Systems and TAPS also cite Consumers
Energy, 98 FERC ¶ 61,333 at 62,410 (2002)
(requiring that a transmission provider’s retail load
associated with behind the meter generation be
included in the transmission provider’s load ratio
share to ensure comparability between transmission
providers and network customers in the calculation
of load ratio share).
915 E.g., AMP-Ohio, CAC/EPUC, and TAPS.
916 Citing Occidental Chemical Corporation v.
PJM Interconnection, L.L.C., and Delmarva Power &
Light Company, 102 FERC ¶ 61,275 at P 14 (2003)
(‘‘Access charges for use of PJM’s transmission
system should be allocated to network customers
based on a network customer’s actual use of PJM’s
system, consistent with the principle of costcausation.’’); PJM Interconnection, L.L.C., 107 FERC
¶ 61,113, at P 28 (2004).
913 E.g.,
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use of the transmission system at the
customer’s meter would be appropriate
as it would demonstrate that, if no
power flows to the customer from the
grid occur, that customer has not used
nor caused costs to be incurred by the
grid for the delivery of its energy
requirements.
1617. Some commenters note that the
Commission has approved PJM netting
provisions that apply to behind the
meter generation used by non-retail and
wholesale customers to serve load.917
These same commenters further observe
that PJM has filed with the Commission
to expand participation in its behind the
meter generation netting program to
include municipal, electric
cooperatives, and electric distribution
transmission customers who take
network service on the PJM system
pursuant to a settlement agreement filed
by PJM on October 24, 2005 in Docket
No. EL05–127–000.918
1618. Further, both TAPS and AMPOhio argue that behind the meter
generation provides benefits to the
transmission provider that should be
taken into account as part of system
planning obligations. For instance,
AMP-Ohio asserts that utility planning
can and should be able to take into
account the ability of customers to
reduce their load on the system with
behind the meter generation. TDU
Systems also notes PJM’s representation
that allowing municipal and electric
cooperative system participation in
behind the meter generation netting
programs increased reliability and
demand response opportunities on
PJM’s system.919 Similarly, TAPS
observes that PJM’s rules reserve the
right to call upon non-retail behind the
meter generation under certain
conditions.
Commission Determination
1619. The Commission is not
persuaded to require transmission
providers to allow netting of behind the
meter generation against transmission
service charges to the extent customers
do not rely on the transmission system
to meet their energy needs. Commenters
in this proceeding have not provided
any different arguments that were not
fully considered and addressed in Order
No. 888, et al. The existing pro forma
OATT already permits transmission
917 E.g., AMP-Ohio, TAPS, and TDU Systems
(citing PJM Interconnection, L.L.C., 107 FERC
¶ 61,113 (2004), reh’g denied, 108 FERC ¶ 61,032
(2004) (PJM)).
918 This settlement agreement was accepted in
PJM Interconnection, L.L.C., 113 FERC ¶ 61,279
(2005).
919 PJM Interconnection, L.L.C., 113 FERC
¶ 63,024 (2005).
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customers to exclude the entirety of a
discrete load from network service and
serve such load with the customer’s
behind the meter generation and
through any needed point-to-point
transmission service, thereby reducing
the network customer’s load ratio share.
Therefore, the Commission’s existing
policy already provides customers with
the opportunity to reduce network
service costs to the extent a customer is
not relying on the transmission system
to meet its energy needs.920 As the
Commission concluded in Order No.
888–A, transmission customers
ultimately must evaluate the financial
advantages and risks and choose to use
either network integration or firm pointto-point transmission service to serve
load.921 We believe it is most
appropriate to continue to review
alternative transmission provider
proposals for behind the meter
generation treatment on a case-by-case
basis, as the Commission did in the PJM
proceeding cited by the commenters.
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8. Transmission Curtailments
1620. In the NOPR, the Commission
proposed no changes to the pro forma
OATT with respect to curtailment
provisions for point-to-point service (set
forth in sections 13.6 and 14.7) and
network service (set forth in section 33).
These provisions establish the terms
and conditions under which a
transmission provider may curtail
service to maintain reliable operation of
the system. Though several commenters
claimed in response to the NOI that the
reasons for transmission curtailments
are difficult to discern, they did not
provide sufficient detail to indicate
whether that difficulty is a result of
inadequate disclosure regulations,
inadequate compliance with those
regulations, or some other reason.
Therefore, the Commission sought
further comment on whether requiring
transmission providers to post
additional information would improve
transparency and the ability of
customers to make use of that
information. The Commission also
declined in the NOPR to propose
generic penalties for improper
transmission curtailments.
Comments
1621. APPA suggests that the
Commission require transmission
providers to produce additional
information regarding firm transmission
service curtailments, including all
920 We note that EEI responds to allegations of
undue discrimination in the calculation of load
ratio share costs in the OATT Definitions section of
this Final Rule.
921 Order No. 888–A at 30,260–61.
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circumstances and events contributing
to the need for such firm service
curtailments, specific services and
customers curtailed (including the
transmission provider’s own retail
loads), and the duration of all such
curtailments. TAPS also urges the
Commission to move toward maximum
transparency and require that sufficient
information be provided for a customer
to evaluate whether it has been treated
fairly as compared to other users of the
system including the transmission
provider. TDU Systems suggests that the
Commission require investigations into
the need for network upgrades when
Level 5 Transmission Loading Relief
(TLR) procedures are repeatedly
employed. It also suggests that all Level
5 TLRs be posted on OASIS and filed
with the Commission. EEI agrees that
providing customers with information
on transmission curtailments may help
to reduce confusion and suspicion
concerning curtailments and suggests
the Commission request WEQ (NAESB)
to develop a more detailed template for
posting information on curtailments that
will be more useful to customers.
1622. Southern and other
commenters 922 state that sufficient
information regarding curtailments of
transmission service is already available
on OASIS and believe that the existing
rules requiring transmission providers
to make curtailment data available on
OASIS are adequate. Nevada Companies
request the Commission be very specific
if it decides to mandate additional
reporting requirements in order to
remove the burden of potential
confidentiality problems from the
reporting entity.
1623. Powerex is concerned about
inconsistent communication and
curtailment procedures. It recommends
that the Commission require three
additional measures including: Early
notice of curtailment through the use of
the ‘‘recall’’ function on OASIS; a
requirement to provide credits for
curtailed service when non-firm pointto-point transmission service is
interrupted; and requiring pro rata
curtailments made prior to the energy
scheduling and tagging deadline (e.g.,
20 minutes before the operating hour) to
be based on reservation rather than
schedule. In its reply comments, Seattle
states support of pro rata curtailments
based on reservations. TDU Systems
recommend that the Commission
require transmission providers to refund
transmission charges to curtailed
customers, to discourage transmission
providers from overselling their
systems. On reply, EEI and PNM–TNMP
922 PNM–TNMP
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12473
urge the Commission to reject the
proposals to require transmission
providers to refund transmission service
charges to curtailed customers. They
state that transmission providers are
following ATC calculation procedures,
but the planning process is not
structured to overbuild the system to
ensure that no curtailments occur. They
also argue that the rate of return
permitted in existing cost of service
regulation does not account for the risk
of loss of curtailment-related revenues.
Northwest IOUs request the
Commission examine whether pro rata
curtailments of transactions to relieve
transmission constraints unnecessarily
impose burdens on transmission
customers, because different
curtailments on different paths have
different effectiveness in relieving a
given transmission constraint.
1624. Manitoba Hydro notes that
MISO is the only RTO in the Eastern
Interconnection that does not redispatch
when constraints occur on non-market
to market flows. Manitoba Hydro
therefore urges the Commission to
encourage implementation of redispatch
to the fullest extent before resorting to
curtailment. Seattle also supports
modifying the pro forma OATT to
require reliability redispatch. Seattle
proposes that redispatch costs should be
allocated to all classes of customers, and
transmission providers’ cost recovery
should be allowed through automatic
adjustment clause-type formulas to
ensure all such costs are recovered. It
suggests that routine maintenance
outages are resulting in curtailments,
which is an indication that transmission
service is oversold. Seattle further
suggests that transmission providers
prepare a quarterly incident report for
redispatch events detailing
circumstances resulting in the
redispatch, system status information,
power transfer distribution factors,
generator offers for redispatch and other
information supporting redispatch
determinations, including the basis for
selecting generators called for
redispatch.
1625. APPA, EEI and others comment
that the Commission should not impose
generic penalties for improper
curtailments, but treat violations on a
case-by-case basis. To ensure
compliance with curtailment posting
information, Southwestern Coop
suggests that the Commission adopt
generic penalties for curtailment
violations, claiming that penalties for
transmission provider curtailment
discrimination would provide
incentives for compliance.
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Commission Determination
1626. The Commission concludes that
the posting of additional curtailment
information is necessary to provide
transparency and allow customers to
determine whether they have been
treated in the same manner as other
transmission system users, including
customers of the transmission provider.
A primary goal of this rulemaking is to
remove opportunities for transmission
providers to unduly discriminate in
favor of their own or their affiliates’ use
of the transmission system. Making
transparent details concerning
transmission curtailments so that
regulators and customers can verify that
the transmission provider curtailed
services in accordance with its OATT is
entirely consistent with this goal.
Commenters who oppose greater
curtailment transparency offer no
convincing evidence to suggest that any
harm or hardship of doing so outweigh
the benefits.
1627. We agree with suggestions for
the posting of additional curtailment
information on OASIS and, therefore,
require transmission providers, working
through NAESB, to develop a detailed
template for the posting of additional
information on OASIS regarding firm
transmission curtailments.
Transmission providers need not
implement this new OASIS
functionality and any related business
practices until NAESB develops
appropriate standards. These postings
must include all circumstances and
events contributing to the need for a
firm service curtailment, specific
services and customers curtailed
(including the transmission provider’s
own retail loads), and the duration of
the curtailment. This information is in
addition to the Commission’s existing
requirements: (1) When any
transmission is curtailed or interrupted,
the transmission provider must post
notice of the curtailment or interruption
on OASIS, and the transmission
provider must state on OASIS the
reason why the transaction could not be
continued or completed; (2) information
to support any such curtailment or
interruption, including the operating
status of facilities involved in the
constraint or interruption, must be
maintained for three years and made
available upon request to the curtailed
or interrupted customer, the
Commission’s Staff, and any other
person who requests it; and, (3) any
offer to adjust the operation of the
transmission provider’s system to
restore a curtailed or interrupted
transaction must be posted and made
available to all curtailed and interrupted
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transmission customers at the same
time.
1628. The Commission rejects TDU
Systems’ proposal to require reports
filed with the Commission regarding
Level 5 TLRs or to require transmission
providers to conduct investigations into
the need for network upgrades when
TLR 5 procedures are repeatedly
employed. TDU Systems’ proposal is
unnecessary at this time in light of our
requirement that OASIS templates for
curtailment information be developed
that will report occurrences of all levels
of TLRs. This will enable the
Commission and customers to monitor
TLR patterns and frequency.
Furthermore, the requirements imposed
in this Final Rule for congestion studies
as part of the coordinated, open and
transparent planning requirement will
allow stakeholders in the transmission
provider’s planning process to request
studies of those portions of the
transmission system where they have
encountered transmission problems due
to frequent and recurring constraints.
1629. The Commission rejects the
three proposals suggested by Powerex.
First, it is not necessary to provide early
curtailment notification through the
OASIS ‘‘recall’’ function since the
OASIS currently provides a curtailment
notification function. Transmission
providers should continue to use the
OASIS Schedule Details template to
post information on the scheduled uses
of the transmission system and any
curtailments and interruption thereof.
Second, with respect to Powerex’s
request to credit customers when their
non-firm point-to-point transmission
service is interrupted, we find it
unnecessary to modify the pro forma
OATT to adopt such crediting
procedures, consistent with our finding
in Order No. 888–A that proper
crediting would vary depending on the
specific rate design a company uses.923
Third, we believe that pro-rating
curtailments based on reservations
would have the potential to impair
reliability since the amount of capacity
actually curtailed using this approach
would not address actual power flows
and, therefore, may be less than
923 See Order No 888–A at 30,276. In Allegheny
Power System, Inc., 80 FERC ¶ 61,143 at 61,549
(1997), the Commission clarified that where a
transmission provider has not proposed an express
crediting provision for the interruption of non-firm
point-to-point customers, the transmission provider
must compute its bill to an interrupted non-firm
customer as if the term of service actually rendered
were the term of service reserved. In other words,
if a customer with a weekly reservation was
interrupted after one day, its bill must be computed
as if it had a daily reservation, and if a customer
with a daily reservation was interrupted after ten
hours, its bill must be computed using the hourly
rate applied to ten hours of service.
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required to relieve the overloaded
facility.
1630. The Commission also rejects
TDU Systems’ recommendation to
refund transmission charges to curtailed
customers as a means of disciplining
instances of improper curtailments or
transmission providers’ overselling their
systems. We also reject proposals to
remedy improper curtailments through
refunds of transmission charges to
curtailed customers or imposing generic
penalties. Rather, the Commission
believes that addressing allegations of
inappropriate curtailment practices or
transmission providers overselling their
transmission system are more effectively
administered by the Commission on a
case-by-case basis.
1631. With respect to the proposal to
require redispatch to be performed to
the fullest extent prior to curtailments,
Manitoba Hydro itself notes that the
proposal is intended to address
curtailment and redispatch practices
unique to MISO. Therefore we conclude
that Manitoba Hydro’s concerns are best
addressed on a case specific basis.
1632. Regarding Seattle’s proposal to
require what it characterizes as
‘‘reliability redispatch’’ to benefit and be
paid by all customer classes, we note
that this proposal would require
expansion of the network service
‘‘reliability redispatch’’ provisions to
apply to point-to-point service as well.
The network service ‘‘reliability
redispatch’’ provisions in pro forma
OATT sections 33.2 and 33.3 were
established in Order No. 888 to ensure
comparable reliable service to network
customers as the service that the
transmission provider provides to its
bundled retail load. These redispatch
procedures further provide for
redispatch of not just the transmission
provider’s own resources, but all
network resources, including those of
network customers, when required to
maintain the reliability of the system
and avoid the need for curtailments.
Seattle has not demonstrated that its
proposal to extend ‘‘reliability
redispatch’’ for point-to-point service is
required to ensure comparable, not
unduly discriminatory transmission
service and has not addressed why
network customer resources should be
redispatched for the benefit of point-topoint customer. Accordingly, we
decline to adopt Seattle’s proposal. We
discuss redispatch issues more broadly
in section V.D.1 of this Final Rule.
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9. Standardization of Rules and
Practices
a. Business Practices
1633. In Order No. 888, the
Commission required each public utility
that owns, controls, or operates facilities
used for transmitting electricity in
interstate commerce to file, pursuant to
section 205 of the FPA, a pro forma
OATT under which it would provide
open access transmission services.
However, certain rules, standards, and
practices governing the provision of
transmission service (e.g., public utility
business practices) are not reflected in
the pro forma OATT. Only when a
public utility adopts a rule, standard, or
practice that significantly affects its
rates and services has the Commission
required it to make a filing pursuant to
FPA section 205 to amend its OATT.924
The Commission has applied this policy
using a ‘‘rule of reason’’ test.925
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NOPR Proposal
1634. In the NOPR, the Commission
proposed not to modify its existing
policy regarding the inclusion of rules,
standards and practices in a
transmission provider’s OATTs. The
Commission expressed concern that
requiring transmission providers to
include all of their rules, standards, and
practices in their OATTs could decrease
a transmission provider’s flexibility to
change business practices and respond
to the requests of its customers. The
Commission also expressed a belief that
requiring transmission providers to file
all of their rules, standards, and
practices in their OATTs would be
impractical and potentially
administratively burdensome.
1635. The NOPR further noted that
there is broad consensus that rules,
standards, and practices not required to
be included in a transmission provider’s
pro forma OATT should be posted on
the transmission provider’s OASIS. The
Commission agreed and proposed to
require transmission providers to post
on OASIS all of their rules, standards,
and practices that relate to transmission
services. The Commission sought
comment on how best to determine
what ‘‘relates’’ to transmission service to
924 E.g., Cleveland v. FERC, 773 F.2d 1368, 1376
(D.C. Cir. 1985).
925 See, e.g., Public Serv. Comm’n of N.Y. v.
FERC, 813 F.2d 448, 454 (D.C. Cir. 1987) (holding
that the Commission properly excused utilities from
filing policies or practices that dealt with only
matters of ‘‘practical insignificance’’ to serving
customers); Midwest Independent Transmission
System Operator, Inc., 98 FERC ¶ 61,137 at 61,401
(‘‘It appears that the proposed Operating protocols
could significantly affect certain rates and service
and as such are required to be filed pursuant to
section 205.’’), order granting clarification, 100
FERC ¶ 61,262 (2002).
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facilitate a consistent interpretation and
to minimize discretion on what rules,
practice and standards should be posted
on OASIS.
1636. On the particular issue of
creditworthiness and security
requirements, the Commission
preliminarily concluded that the mere
posting of information on OASIS was
insufficient. The Commission proposed
that each transmission provider’s OATT
contain sufficient information about its
credit process and requirements to
enable customers to understand the
information required to demonstrate
creditworthiness and to determine for
themselves the general amount and type
of security they may need to provide in
order to receive service. The
Commission therefore proposed to
amend section 11 of the pro forma
OATT on creditworthiness to require
each transmission provider to include
its creditworthiness and security
requirements in a new Attachment L to
its OATT. Consistent with the
Creditworthiness Policy Statement,926
the Commission proposed to require the
new Attachment L to include such
qualitative and quantitative criteria
necessary to determine the level of
secured and unsecured credit required,
with supplementation in a credit guide
or manual to be posted on OASIS.927
The Commission sought comment on
whether the proposal is unduly
burdensome.
Comments
Included in Open Access Transmission
Tariffs
1637. Many commenters express
support for the continuation of the
current Commission policy which
requires the inclusion in the
transmission provider’s OATT of only
those rules, standards and practices that
significantly affect transmission rates
and services.928 These commenters
generally state that any rule, practice,
term or condition that could result in
926 Policy Statement on Electric Creditworthiness,
109 FERC ¶ 61,186 (2004) (Creditworthiness Policy
Statement).
927 The Commission proposed to require the new
Attachment L to include the following elements: (1)
A summary of the procedure for determining the
level of secured and unsecured credit; (2) a list of
the acceptable types of collateral/security; (3) a
procedure for providing customers with reasonable
notice of changes in credit levels and collateral
requirements; (4) a procedure for providing
customers, upon request, a written explanation for
any change in credit levels or collateral
requirements; (5) a reasonable opportunity to
contest determinations of credit levels or collateral
requirements; and (6) a reasonable opportunity to
post additional collateral, including curing any
non-creditworthy determination.
928 E.g., ISO/RTO Council, CAISO, LDWP, MISO/
PJM States, PGP, and PNM–TNMP.
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12475
limiting access to transmission services,
including rates and charges for service,
should be included in the OATT and
should be subject to Commission
scrutiny. Examples given include all
rules and practices affecting calculation
of ATC, creditworthiness criteria, and
rules or practices affecting the
transmission provider’s regional
planning process. Commenters argue
that Commission oversight is necessary
to ensure that these rates, charges, rules,
practices, terms or conditions of
transmission service are reasonable and
afford comparable treatment for
wholesale customers.
1638. Other commenters advocate
further inclusion of rules, standards and
practices in the transmission provider’s
OATT. Morgan Stanley believes that
business practices manuals should be
incorporated into each OATT and filed
with the Commission for approval.
Morgan Stanley states that if this is not
required then, at a minimum, each
OATT should provide for a process to
use when the transmission provider
wishes to amend its business practices
manuals. For example, transmission
providers should provide notice to all
affected parties of an intent to make a
change, a mechanism to receive
stakeholder feedback on the proposed
change, and a minimum period of time
between the final implementation
decision and the effective date of the
proposed change (e.g., 30–60 days after
final decision). Southwestern Coop,
however, maintains that transmission
providers should not be allowed to
change their rules, standards and
practices that affect the justness and
reasonableness of OATTs without prior
Commission review. Southwestern Coop
states that the Commission should
require all rules, standards and practices
relating to transmission services to be
included in the OATT filed with the
Commission, because otherwise it
cannot ensure that jurisdictional rates
are just and reasonable.
Posted on OASIS
1639. Many commenters also express
support for the proposed requirement
that all rules, standards and practices
that are not required to be included in
a transmission provider’s OATT and
that affect a transmission provider’s
provision of transmission service be
posted on OASIS.929 Commenters
generally state that these postings will
allow for increased transparency, while
affording the transmission provider
flexibility to make revisions rather than
929 E.g., CAISO, EEI, MidAmerican, MISO/PJM
States, Nevada Companies, PJM, Powerex, Santa
Clara, Suez Energy NA, TDU Systems, and TAPS.
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having to amend the OATT each time a
change occurs.
1640. Powerex argues that the
transmission provider also should be
required to post data used to calculate
ATC, any metrics the Commission
adopts regarding the transmission
provider’s performance of system
impact and facilities studies,
information concerning both planned
and unplanned transmission outages,
and a transmission provider’s business
practices, tariff, organizational charts
and job descriptions of its employees.
1641. Southern takes issue with the
use in the NOPR of the phrase ‘‘all of
their rules, standards and practices,’’
stating that language suggests that a
transmission provider might be required
to reduce each detail of its business
practices to writing, which could be
overly burdensome. In addition,
Southern believes that any rule relating
to posting requirements on OASIS
should have certain mechanisms to
allow the transmission provider to
deviate from posted practices when
necessary. In contrast, ELCON states
that any rule, standard or practice used
by the transmission provider and any of
its employees to approve or disapprove
a request for service should be
committed to writing and posted.
Similarly, TranServ argues that
transmission providers should be
required to post on OASIS any criteria
applied by the transmission provider to
any attribute of a transmission or
ancillary service request for the purpose
of determining whether the service
request should be approved or denied.
1642. Northwest IOUs suggests that
the Commission should adopt a ‘‘rule of
reason’’ test for matters required to be
posted on the OASIS similar to the test
applied to matters required to be
included in the OATT.
sroberts on PROD1PC70 with RULES
Creditworthiness
1643. Several commenters support the
inclusion of a separate Attachment L to
the pro forma OATT outlining
creditworthiness requirements, asserting
that Attachment L will standardize
credit procedures and security
requirements and increase
transparency.930 Suez Energy NA states
that the proposal is not unduly
burdensome, that the procedures
proposed are not different from the
Creditworthiness Policy Statement or
the procedures already imposed in
individual cases, and that the
Commission is merely proposing to
930 E.g., APPA, East Texas Cooperatives, Lassen,
MISO/PJM States, Nevada Companies, NRECA,
PGP, Powerex, Southern, Suez Energy NA, TANC,
and TAPS.
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apply an existing requirement in a nondiscriminatory manner.
1644. Other commenters propose
modifications to the credit-related
proposals set forth in the NOPR. TAPS
urges the Commission to require the
transmission provider to adopt a twopart creditworthiness assessment in
order to facilitate non-burdensome and
fair assessment of creditworthiness.
TAPS recommends that a standard
similar to the Florida Power Corp.
OATT be applied, which provides that
customers with ‘‘satisfactory long-term
payment history’’ and a minimum credit
rating of Baa2 (Moody’s) or BBB (S&P)
would not have to post any credit
security. If a customer fails to meet the
threshold test, TAPS states that the
transmission provider would perform a
transparent credit assessment that is
consistent with the Commission’s
Creditworthiness Policy Statement and
the credit policies developed for use in
regional transmission organizations
such as MISO and SPP. According to
TAPS, since quantitative measures
sometimes understate public power
creditworthiness, transmission
providers will need to weigh qualitative
factors more heavily than quantitative
factors in assessing public power
creditworthiness. For public entities
that fail the threshold test, TAPS states
that transmission providers should use
outstanding bond indebtedness as a
proxy for tangible net worth for those
entities whose energy and transmission
service payments receive priority over
bond payments.
1645. PJM generally agrees with the
creditworthiness proposals, except for
inclusion in the OATT of the actual
detailed algorithms used to calculate
credit scores, stating that those
algorithms, as the Commission
recognized,931 may change over time. In
PJM’s view, requiring all such changes
to be approved by the Commission
would be unnecessarily burdensome to
both the Commission and the
transmission provider. PJM
recommends that the overall framework
of the credit determinations be included
in the OATT, while the detailed
algorithms be posted on OASIS to meet
transparency goals. PJM also
recommends that the Commission
accept, as an option, a regularly-updated
posting on the transmission provider’s
Web site of each customer’s available
credit and collateral requirement as
sufficient notification for most changes
in credit available and credit
requirements. PJM further recommends
that only significant and sudden
reductions in credit available (for
931 See
PO 00000
NOPR at P 456.
Frm 00212
Fmt 4701
Sfmt 4700
example, those greater than 25 percent
within a one-month period) be subject
to an active notification requirement.
1646. TVA recommends the
Commission consider two fundamental
principles as it standardizes
creditworthiness terms and conditions.
First, as long as qualitative factors are
part of the equation (and TVA agrees
that they should be), TVA states that
certain subjective judgments by the
transmission provider will be required.
TVA encourages the Commission to
provide guidance on appropriate criteria
to consider in making these judgments,
but not to remove entirely from the
process the flexibility necessary for
individual assessments of customer
creditworthiness. Second, TVA states
that transmission providers may have to
impose different security requirements
as a result of differences in statutes,
regulations, or other legal requirements.
For example, TVA states that its ability
to incur debt is limited by section 15d(a)
of the Tennessee Valley Authority
Act 932 and, therefore, it may need to
impose security requirements that are
stricter than those of a public utility, as
the Commission has previously
recognized.933 TVA requests that the
final rule respect these differing legal
obligations and provide corresponding
flexibility in credit decisions among
transmission providers.
1647. A number of commenters
oppose the Commission’s proposed
creditworthiness policy.934 In general,
these commenters believe that each
transmission provider should have the
flexibility to make and change
creditworthiness procedures without
the delay of obtaining Commission
approval. They also argue that the
Commission’s goal of transparency
could be better achieved by requiring
the posting of a transmission provider’s
creditworthiness policy on OASIS.935
Xcel and MidAmerican assert that the
Commission’s proposal would decrease
a transmission provider’s ability to
timely respond to changing market and
financial conditions and, therefore,
creditworthiness and security
requirements should simply be posted
on OASIS. Southern believes that the
Commission should permit but not
require transmission providers to file
their creditworthiness and security
procedures as part of their OATTs.936
932 16
U.S.C. 831n–4.
East Ky. Power Coop., Inc., 114 FERC
¶ 61,035 at P 56 (2006).
934 E.g., MidAmerican, Southern, PNM–TNMP,
NorthWestern, and Xcel.
935 E.g., PNM–TNMP, EEI, and MidAmerican.
936 Southern states that it already includes
creditworthiness and security requirements in its
933 Citing
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Southern also asks that the Commission
allow a transmission provider, in its
compliance filing, to request a
determination that its current
creditworthiness policies and practices
are acceptable under the new
Commission policies. Similarly, ISONew England states that this rulemaking
should not modify the ISO-New
England Financial Assurance and
Billing Policies, which are already on
file with the Commission.
1648. CAISO states that although the
NOPR requirements concerning credit
and security requirements do not appear
unduly burdensome, it is concerned that
the Commission may apply these
requirements in a manner that will
impose an undue burden on
transmission providers and effectively
eliminate the ability of transmission
providers to supplement basic elements
with a credit guide or manual. CAISO
and MidAmerican further state that
there is no legitimate reason to treat
credit policies and procedures any
differently than the other rules,
practices and standards that the
Commission permits to be included on
OASIS and does not require to be filed
as part of the tariff. Santa Clara
recommends that if the Commission
decides to require creditworthiness and
security policies to be posted on OASIS
rather than included in the OATT, then
it should require at least a 30-day notice
period for changes in the credit policies.
Commission Determination
1649. The Commission adopts the
NOPR proposal to continue to require
only those rules, standards, and
practices that significantly affect
transmission service be incorporated
into a transmission provider’s OATT.
The Commission further affirms the use
of a ‘‘rule of reason’’ to determine what
rules, standards, and practices
significantly affect transmission service
and, as a result, must be included in the
transmission provider’s OATT.
1650. The ‘‘rule of reason’’ test has
arisen primarily with respect to
protocols or operating procedures used
by RTOs and ISOs. For example, the
Commission has held that, while
MISO’s business practices manuals
implicate the Commission’s jurisdiction
because they generally involve ‘‘the
installation, operation, or use of
facilities for the transmission or delivery
of power in interstate commerce,’’ they
do not require an FPA section 205 filing
because ‘‘they mostly involve general
operating procedures.’’ In other cases,
the facts have required the filing of the
OATT since the Commission issued its
Creditworthiness Policy Statement.
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rule, standard or practice. For example,
CAISO proposed to post certain
technical, operational and business
standards related to dynamic scheduling
on its Web site and include only the
rates under its OATT. In that instance,
the Commission found that the details
contained in the standards were
practices that could significantly affect
the terms and conditions of service and,
therefore, under the Commission’s ‘‘rule
of reason’’ must be filed under section
205 of the FPA.937
1651. Comments received in response
to the NOPR confirm that there is broad
support for the Commission’s existing
practice, requiring only those rules,
standards, and practices that
significantly affect transmission service,
and the use of the ‘‘rule of reason’’ test
to identify those rules, standards, and
practices. The Commission disagrees
with parties arguing that all of a
transmission provider’s rules, standards,
and practices should be incorporated
into its OATT. We believe that requiring
transmission providers to file all of their
rules, standards and practices in their
OATTs would be impractical and
potentially administratively
burdensome.
1652. The Commission instead
requires transmission providers to post
on their public Web sites all rules,
standards, and practices that relate to
transmission service and provide a link
to those rules, standards, and practices
on OASIS. We conclude that it would
not be appropriate to place the rules,
standards, and practices only on OASIS
as some transmission providers use
certificates to restrict access to their
OASIS sites. By providing a link on
OASIS to the rules, standards, and
practices that are otherwise publicly
posted, the Commission ensures that all
potential customers will have access to
the information necessary for them to
understand the terms and conditions of
service. We amend section 4 of the pro
forma OATT to expressly establish this
posting requirement.
1653. We note that we already require
certain rules and practices to be posted
937 California Independent System Operator
Corp., 107 FERC ¶ 61,329 at P 21–22 (2004); see
also Southwest Power Pool, Inc., 112 FERC ¶ 61,303
at P 25 (requiring that the SPP OATT provide
sufficient information for market participants to
fully understand SPP’s implementation of an
imbalance market), reh’g denied, 113 FERC ¶ 61,115
(2005); PJM Interconnection, L.L.C., 104 FERC
¶ 61,124 at P 61 (requiring PJM to place all
procedures, standards and requirements for
proposing that a transmission owner construct a
specific upgrade, and all procedures for charging
customers, in its tariff, not in its manuals), order on
reh’g, PJM Interconnection, L.L.C., 105 FERC
¶ 61,123 (2003).
PO 00000
Frm 00213
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12477
on OASIS.938 We find that it is now
necessary to also require that all rules,
standards or business practices that
relate to the terms and conditions of
transmission service, and how that
transmission service is provided to
customers, to be detailed, clearly stated
on the transmission provider’s public
Web site, with a link to this information
on OASIS.939 We emphasize that this
requirement applies to all such rules,
standards, and practices, currently
written or otherwise.940 While we
acknowledge this requirement will
result in some burden to transmission
providers, we find that this approach is
necessary to provide greater
transparency and mitigate the potential
for undue discrimination against
customers taking service under the
transmission provider’s OATT. Further,
our holding is not intended to eliminate
all discretion under the pro forma
OATT; rather, we recognize that certain
tariff provisions require consideration of
the specific facts and circumstances
related to particular service requests.941
We merely require that, if the
transmission provider uses standards,
rules or business practices to administer
its OATT, such standards, rules or
business practices must be available for
public inspection. Moreover, we note
that our actions here are consistent with
actions we have taken in recent
proceedings. For example, the
Commission has required that certain
business practices manuals be posted
938 See, e.g., Order No. 889 at 31,588–89; Open
Access Same-Time Information Systems, Order No.
605, 64 FR 34117 (Jun. 25, 1999), FERC Stats. and
Regs. ¶ 31,075 (1999); Order No. 676 at P 79.
939 If a particular rule, standard or practice
conflicts with an OATT provision, the OATT of
course shall govern in all circumstances. Moreover,
as noted in the NOPR, we emphasize that posting
rules, practices and standards—in lieu of filing such
practices with the Commission as part of the
transmission provider’s pro forma OATT—neither
insulates a transmission provider from complaints
nor confers a just and reasonable presumption. We
encourage customers to call the Commission’s
Enforcement Hotline with complaints about the
application of such rules, standards and practices
should they experience problems with their
transmission providers. To the extent customers are
not satisfied with responses from their transmission
provider, they should contact the Commission’s
Enforcement Hotline via telephone (202) 502–8390,
toll-free 1–888–889–8030, fax (202) 208–0057, or at
https://www.ferc.gov/cust-protect/enforce-hot.asp.
940 With respect to the business practices
developed by NAESB, there may be certain
copyright restrictions that limit the transmission
provider’s ability to post those practices on its own
Web site. In such instances, we expect that the
transmission provider will reference any NAESB
practices it uses and provide a link on its public
Web site to the NAESB Web site in order to provide
interested parties with a means to access the
copyrighted material.
941 The circumstances and manner in which a
transmission provider exercises its discretion under
its OATT must be posted in accordance with 18
CFR 37.6(4).
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sroberts on PROD1PC70 with RULES
and made available for public view on
a permanent basis.942 As in those cases,
we find that making rules, standards,
and practices readily accessible will
serve as a tool to supplement each
transmission provider’s OATT and
facilitate fair and open access to the
transmission grid.
1654. To provide guidance to the
transmission providers as to whether a
particular rule, standard, or practice
‘‘relates to’’ transmission service, and
therefore warrants posting, the
Commission believes the MAPP Policies
and Procedures for Transmission
Operations manual is a good example of
the type of information that relates to
the terms and conditions of
transmission service. For example, the
MAPP manual sets forth information
supplementing its OATT pertaining to
(1) transmission service requests on the
MAPP OASIS site, (2) the retraction of
an accepted or counteroffer
transmission request, (3) timing
requirements for transmission service
requests, (4) methods to accommodate a
firm transmission request with
redispatch, and (5) transmission service
charge implementation procedures.
Other examples include detailed
information regarding tagging,
scheduling, billing and other matters
provided in other RTO manuals. This is
the type of information that clearly
relates to transmission service and
therefore must be reduced to writing
and publicly posted.
1655. We also agree with requests to
require a transparent process for
amending rules, standards, and
practices previously posted by a
transmission provider. We therefore
require each transmission provider also
post on its public Web site (with a
corresponding link on OASIS) a
statement of the process by which the
transmission provider will amend these
rules, standards, and practices that are
accessible via OASIS. As part of this
process, the transmission provider must
specify a mechanism to provide
reasonable notice of any proposed
changes to a posted business practice
and the respective effective date of such
change.943 We amend section 4 of the
942 See, e.g., Midwest Independent Transmission
System Operator, Inc., 108 FERC ¶ 61,163 at P 658,
order on reh’g, 109 FERC ¶ 61,157 (2004), order on
reh’g, 111 FERC ¶ 61,043, order on reh’g, 112 FERC
¶ 61,086 (2005); see also PJM Interconnection,
L.L.C., 81 FERC ¶ 61,257 at 62,267 (1997) (finding
no reason to require filing of the PJM Manuals but
requiring that such manuals be available for public
inspection on a permanent basis), order on reh’g, 92
FERC ¶ 61,282 (2000).
943 As part of their business practice amendment
procedures, transmission providers may adopt such
additional procedures they deem appropriate, such
as opportunities for comment to proposed changes
to rules, standards, and practices.
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pro forma OATT to formalize this
posting requirement and obligate
transmission providers to follow the
amendment procedures specified by the
transmission provider. As with the
requirement to post the underlying
standards, rules and practices, we
believe the amendment procedures
required here will increase transparency
and help minimize opportunities for
undue discrimination.
1656. The Commission also adopts
the NOPR proposal and amend the pro
forma OATT to include a new
Attachment L.944 We find that the
transmission provider’s basic credit
standards significantly affect
transmission service and, therefore,
must be included in the pro forma
OATT. This will ensure that all
customers have clear information as to
the credit process and standards used by
a transmission provider to grant or deny
transmission service and, in turn, will
serve to prevent undue discrimination
and eliminate a potentially significant
barrier to entry in the provision of
service. Most importantly, by making
Attachment L a part of the pro forma
OATT, customers will have an
opportunity to comment on any changes
to the standards proposed by a
transmission provider in a rate filing
with the Commission.
1657. To that end, each transmission
provider’s Attachment L must specify
the qualitative and quantitative criteria
that the transmission provider uses to
determine the level of secured and
unsecured credit required. Attachment
L must also contain the following
elements: (1) A summary of the
procedure for determining the level of
secured and unsecured credit; (2) a list
of the acceptable types of collateral/
security; (3) a procedure for providing
customers with reasonable notice of
changes in credit levels and collateral
requirements; (4) a procedure for
providing customers, upon request, a
written explanation for any change in
credit levels or collateral requirements;
(5) a reasonable opportunity to contest
determinations of credit levels or
collateral requirements; and (6) a
reasonable opportunity to post
additional collateral, including curing
any non-creditworthy determination.
We will allow the transmission provider
to supplement Attachment L with a
credit guide or manual to be posted on
OASIS.
944 As with new Attachment K to the pro forma
OATT, regarding transmission planning, we
acknowledge that some transmission providers may
already have attachments to their OATTs labeled
with the letter ‘‘L,’’ in which case transmission
providers are free to label their credit procedures
OATT attachment with the next available letter.
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1658. We disagree with commenters
that claim requiring this information in
an attachment to each transmission
provider’s OATT will hinder the
transmission provider’s ability to timely
respond to changing market and
financial conditions. Because
Attachment L requires only a summary
of credit requirements and other
information, we expect the need to
revise Attachment L will occur
infrequently. As suggested by PJM,
detailed information, such as the
algorithms used by the transmission
provider to determine credit scores, can
be posted on OASIS along with other
information that relates to the provision
of transmission service. Thus, the
requirement we are imposing should not
be overly burdensome.
1659. At the same time, we agree that
transmission providers need flexibility
in determining credit requirements in
light of qualitative and quantitative
factors, as we recognized in the NOPR
and the Creditworthiness Policy
Statement. We believe the requirements
adopted in this Final Rule allow for
such flexibility. By requiring
transmission providers to consider both
quantitative and qualitative factors, the
particular circumstances surrounding
public power entities can be recognized.
We agree, moreover, with TVA that the
transmission provider’s credit policies
must be consistent with its legal
obligations and expect that interested
parties will bring any legal conflicts to
our attention on review of the
transmission provider’s compliance
filing.
1660. With regard to requests to find
existing credit policies consistent with
the requirements of the Final Rule, all
transmission providers will be required
to demonstrate compliance with all
aspects of the Final Rule either by
implementing the reforms adopted
today or showing that departures are
consistent with or superior to the terms
and conditions of the pro forma OATT,
as modified by this Final Rule. The
procedural mechanisms for making such
a showing provided for in section IV.C
above give transmission providers the
opportunity to demonstrate that
retention of their existing credit
practices is appropriate.
1661. Finally, with regard to Santa
Clara’s request to require the
transmission provider to provide at least
a 30-day notice period for changes in
creditworthiness and security policies
that are posted on OASIS, we explain
above that each transmission provider
must identify and incorporate a specific
process in its OATT for amending
business practices that are posted on
OASIS. Such practices include those
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that describe and implement its
creditworthiness and security policies.
(2) Indemnification/Limitation of
Liability
b. Liability and Indemnification
Comments
1662. In Order No. 888, the only
liability provisions included in the pro
forma OATT related to force majeure
and indemnification.945 Section 10.1 of
the pro forma OATT provides that
neither the transmission provider nor
the transmission customer will be
considered in default as to any
obligation under the tariff if prevented
from fulfilling the obligation due to an
event of force majeure. A party whose
performance under the tariff is hindered
by an event of force majeure, however,
is required to make all reasonable efforts
to perform its obligations under the
tariff. With respect to indemnification,
under section 10.2 of the pro forma
OATT, the transmission customer
indemnifies the transmission provider
against third party claims arising from
the transmission provider’s performance
of its obligations under tariff on behalf
of the transmission customer, except in
cases of negligence or intentional
wrongdoing by the transmission
provider.
1665. Several commenters 946 urge the
Commission to change the
indemnification provision to protect
transmission providers from liability
except in the case of gross negligence or
intentional misconduct, thereby
exempting the transmission provider
from liability for acts of ordinary
negligence. These commenters also
request that the Commission add to the
pro forma OATT a new provision
clarifying that the transmission provider
would not be liable to any transmission
customer or third party for direct,
incidental, consequential, indirect, or
punitive damages arising from services
provided under the tariff, except in
cases of gross negligence or intentional
misconduct (in which case, EEI, and
Northwest IOUs propose, liability
would be limited to direct damages).
These commenters note that the
Commission has allowed transmission
providers this protection in the tariffs of
MISO, PJM, ISO New England, SPP, and
their member transmission owners and
generators, but it has not fully explained
its basis for treating non-RTO member
transmission providers differently from
RTOs and ISOs. EEI further notes that
the Commission accepted similar
liability protection in the Large
Generator Interconnection Agreement
(‘‘LGIA’’) and in natural gas pipeline
tariffs.947 EEI requests that this liability
limitation be added to the pro forma
transmission service agreement that
would apply to transmission customers
acting in good faith to carry out the
directives of a transmission provider.
1666. With respect to third party
indemnification, EEI notes that the
Commission reasoned in SPP that, even
though a broader liability limitation
would relieve a transmission provider
from liability for ordinary negligence,
that provision only applies to
transmission customers under the tariff.
EEI states that there are many other
entities that could initiate legal action
against the transmission provider in
connection with the provision of
transmission service, thereby making an
adequate indemnification provision in
the pro forma OATT necessary for the
same reasons as the limited liability
provision.948
(1) Force Majeure
Comments
1663. Santa Clara queries whether the
Commission intended to make the
transmission provider’s performance of
its obligations less burdensome by using
the phrase ‘‘all reasonable efforts’’
instead of ‘‘due diligence’’ in the force
majeure provision in section 10.1 of the
pro forma OATT is. In either case, Santa
Clara requests the Commission to
consider the use of the most stringent
term when addressing a transmission
provider’s obligation to perform under
its tariff.
sroberts on PROD1PC70 with RULES
Commission Determination
1664. The Final Rule retains the
current ‘‘all reasonable efforts’’ standard
in the force majeure provision. Santa
Clara does not explain how the ‘‘all
reasonable efforts’’ standard may be
more or less stringent than the ‘‘due
diligence’’ standard. Further, as the
Commission explained in Order No.
888, this protection against unexpected
and unpredictable events is
appropriately made available to both the
transmission provider and transmission
customer. We therefore find that the
clarification requested by Santa Clara is
unnecessary.
945 Order
No. 888–B at 62,081
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946 E.g.,
Southern, EEI, and Northwest IOUs.
Article 18, Large Generator
Interconnection Agreement; ANR Pipeline Co., 98
FERC ¶ 61,218, order on tariff filing, 100 FERC
¶ 61,132 (2002).
948 Citing Southwest Power Pool, Inc., 112 FERC
¶ 61,100 at P 39 (2005).
947 Citing
PO 00000
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12479
1667. EEI contends that the addition
of the Commission’s new EPAct 2005
authority to establish mandatory
reliability standards to provide open
access transmission service to all
customers, regardless of their risk
profile, makes it an appropriate time to
revisit the liability provisions in the
OATT. According to EEI, a limitation on
liability in the pro forma OATT should
be viewed as a necessary element of the
implementation of the Commission’s
reliability authority. Because
transmission providers cannot deny
service to particular customers based on
the risk of potential damages, EEI and
Southern assert that all transmission
providers should be protected from
certain risks associated with this
obligation to serve. EEI argues that
increased protection from liability
would lower the cost of capital for new
transmission projects and promote the
expansion of transmission
infrastructure. EEI further argues that
the technological complexity of modern
utility systems and the potential for
service interruptions unrelated to
human errors justify liability
limitations. According to EEI, a
limitation on liability to direct damages
puts the risk on those customers with
special reliability needs, rather than
spreading the risk among all customers.
1668. EEI notes that the Commission
has denied requests for exemptions from
liability for ordinary negligence in the
indemnification provision on the
grounds that liability and
indemnification were ‘‘separate
issue[s]’’ and that transmission
providers seeking liability protections
could rely on state laws.949 EEI argues,
however, that an OATT and the
accompanying service agreement
constitute a contract between the
transmission provider and the customer
that is established pursuant to federal
law and, as a result, it is not at all clear
that a state law limitation on liability
would apply. Southern asserts that
adopting liability limits would provide
uniformity, certainty, and reduce risk
since reliance on state law is an issue
not free from doubt.
1669. Entegra argues on reply that the
NOPR did not contemplate any
modification to these provisions of the
pro forma OATT and neither EEI nor
Southern has established a nexus
between such a modification and the
goals set forth in the NOPR. TDU
Systems on reply similarly argue that
EEI’s request is outside the scope of the
rulemaking and neither EEI nor
Southern show a change in
circumstance justifying a new limitation
949 Citing
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on liability. Immunizing transmission
providers from these liability risks, TDU
Systems contend, would simply transfer
risk to customers that have no control
over the transmission provider’s
negligence. Entegra and TDU Systems
further argue that Southern previously
sought the same relief in a tariff filing
rejected by the Commission less than a
year ago, stating that the Commission
thus already rejected the notion that
Southern was similarly situated to the
RTOs and ISOs that have this
protection.950 Entegra notes that
Southern did not seek rehearing of that
order and its comments here are
therefore an impermissible collateral
attack on a final Commission order. As
for the argument regarding EPAct 2005,
TDU Systems note that the Commission
presumably was aware of its new
reliability authorities when it issued the
Southern order four months after EPAct
was enacted.
1670. TDU Systems also point out that
the tariff language proposed by EEI
would not protect a transmission
customer from being sued by a third
party for the negligence or willful
misconduct of the transmission
provider. In such lawsuits, TDU
Systems claim, a third party would not
be limited to direct damages. According
to TDU systems, any indemnification as
between the transmission provider and
the transmission customer that is
limited to direct damages would leave
the customer holding the bag for the
indirect damages caused by the
transmission provider’s negligence or
willful misconduct.
sroberts on PROD1PC70 with RULES
Commission Determination
1671. We will retain the current
liability protections in the pro forma
OATT for the same reasons that the
Commission has rejected similar past
proposals. While the Commission
explained in Order Nos. 888–A and
888–B that the pro forma tariff was not
intended to address liability issues, as
EEI notes, the Commission stated that
liability was a separate issue from
indemnification.951 The Commission
further explained that transmission
providers were not precluded from
relying on state laws that protected
utilities or others from claims founded
in ordinary negligence.952 The
Commission declined to adopt a
uniform federal liability standard and
decided that, while it was appropriate to
protect the transmission provider
950 See Entegra Reply (citing Southern Company
Services, Inc., 113 FERC ¶61,239 (2005)).
951 See Order No. 888–A at 30,301 and Order No.
888–B at 62,081 (section 10.2 of the pro forma
OATT).
952 Order No. 888–A at 30,301.
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through force majeure and
indemnification provisions from
damages or liability when service is
provided by the transmission provider
without negligence, it would leave the
determination of liability in other
instances to other proceedings.953
1672. On the issue of a negligence
standard for the indemnification
provision, we decline to depart from our
policy set forth in Order No. 888, as
affirmed in Order No. 888–A and
subsequent orders.954 In Order No. 888,
the Commission stated:
We have limited the indemnification
portion of the provision so that it is now only
the transmission customer who indemnifies
the transmission provider from the claims of
third parties. The customer is taking service
from the transmission provider and may
appropriately be asked to bear the risks of
third-party suits arising from the provision of
service to the customer under the tariff. We
find that this new indemnification provision
would be too strict if it required customers
to indemnify transmission providers even in
cases where the transmission provider is
negligent. Accordingly, the revised provision
provides that the customer will not be
required to indemnify the transmission
provider in the case of negligence or
intentional wrongdoing by the transmission
provider.955
1673. The Commission subsequently
addressed this issue in Northeast
Utilities. There, the Commission found
that a broader customer indemnification
obligation that would include ordinary
negligence would not give any incentive
to the transmission provider to avoid
negligent actions. In Northeast Utilities,
the Commission explained again why it
permitted a gross negligence exception
in the pro forma LGIA section 18.1 in
order to further limit the transmission
provider’s liability. As the Commission
explained in Order No. 2003,
interconnection warrants a different
standard because it presents a greater
risk of liability than exists for the
provision of transmission service. The
Commission further found that because
risk exposure can increase
interconnection costs, a broader
indemnity standard is appropriate in the
interconnection context.956
1674. Further, unlike Order No. 888
in which the transmission customer
indemnifies the transmission provider,
in Order No. 2003 the indemnity
provision is expressly bilateral. In Order
No. 2003 the interconnecting generator
and the transmission provider each
indemnifies the other from all damages
953 Order
No. 888–B at 62,081.
e.g., Northeast Utilities Services Co., 111
FERC ¶ 61,333 (2005) (Northeast Utilities).
955 Order No. 888 at 31,765.
956 Order No. 2003 at P 636; Order No. 2003–A
at 31,162.
954 See,
PO 00000
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to third parties arising under the LGIA
from conduct on behalf of the
indemnifying party, except in cases of
gross negligence. Given that the
indemnification provision in the pro
forma LGIA is bilateral, in contrast to
the pro forma OATT, it is reasonable to
permit a gross negligence standard in
the case of an interconnection.
1675. We also reject commenters’
assertions that the liability standard the
Commission has approved for RTOs/
ISOs and gas pipelines is appropriate for
other transmission providers. In the
Reliability Policy Statement,957 the
Commission stated that it would
consider, on a case-by-case basis,
proposals by public utilities to amend
their OATTs to include limitations on
liability. The Commission further noted
that while this issue has not been
resolved on a standardized basis, the
Commission has entertained RTO
transmission providers’ specific
proposals to amend their OATTs to
include provisions addressing
limitations on liability.958
1676. In subsequent orders, the
Commission found that the gross
negligence and intentional wrongdoing
indemnification and liability standard is
appropriate for RTOs and ISOs.
However, the Commission has declined
to extend this protection to all
transmission providers. In Southwest
Power Pool, Inc., the Commission
explicitly stated ‘‘that our acceptance
here of the gross negligence and
intentional wrongdoing indemnity
standard is limited to SPP, in its role as
an RTO, and its TOs; we do not intend
to extend such protection to all
transmission providers.’’ 959 In Southern
Company Services, Inc., the
Commission stated that:
Having considered Southern Companies’
proposed limitation on liability and
indemnification provisions pursuant to our
Reliability Policy Statement cited above, we
find that Southern Companies have not
shown that they are similarly situated to the
RTOs/ISOs they cite in support. While
Southern Companies claim that they ‘‘may
not be protected by any State-regulated
limitations on liability,’’ Southern
Companies offer no evidence to support this
concern. The Commission has provided such
liability protection to RTOs/ISOs because
they were created by and solely regulated by
the Commission, and otherwise would be
without limitations on liability. Southern
Companies have proffered no evidence of any
957 Policy Statement on Matters Related to Bulk
Power System Reliability, 107 FERC ¶ 61,052 (2004)
(Reliability Policy Statement).
958 Reliability Policy Statement at P 40 (citations
omitted).
959 112 FERC ¶ 61,100 at P 39 (2005).
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`
change in circumstances vis-a-vis their
liability exposure post-Order No. 888.960
1677. Commenters offer no new
arguments that demonstrate that they
are unable to rely on state laws, i.e., the
state laws provide inadequate
protection. While EEI and Southern
assert that there is uncertainty in
whether state law on liability would
apply to a service agreement between a
transmission provider and a
transmission customer, we note that
neither provide any evidence that
transmission providers are actually
precluded from relying on state law for
liability protection. EEI and Southern
thus fail to show that the potential for
a legal and regulatory gap is so great as
to warrant inclusion of liability
protections in the pro forma OATT for
all transmission providers. In this
regard, the Commission also finds
without merit assertions that increased
liability protections in the pro forma
OATT should be viewed as a necessary
element of the implementation of the
Commission’s reliability authority. As
none of the arguments proffered by
commenters persuade us to change our
policy regarding liability protections
applicable to non-RTO and non-ISO
transmission providers, we decline to
modify the liability protections in the
pro forma OATT.
10. OATT Definitions
1678. In order to support the reforms
adopted in this Final Rule and
otherwise clarify the requirements of the
pro forma OATT, the Commission adds
and amends various definitions in the
pro forma OATT, as set forth below.
a. Affiliate
NOPR Proposal
1679. In the NOPR, the Commission
proposed a new definition of Affiliate
incident to the proposed change to the
pricing of reassigned capacity.
sroberts on PROD1PC70 with RULES
Comments
1680. Some commenters request
clarification that the proposed
definition of Affiliate would not apply
to transmission-only cooperatives or
independent entities such as RTOs.
NRECA asserts that in Order No. 2004–
A, the Commission concluded that
‘‘[g]eneration and transmission
cooperatives (G&T) are not subject to the
Standards of Conduct consistent with
the policies established under Order No.
888.’’ NRECA asks for confirmation that
distribution and generation and
transmission cooperatives will not be
considered affiliates of each other for
960 113
FERC ¶ 61,239 at P 7 (2005).
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OATT and Standards of Conduct
purposes because recent pleadings
reveal that there continues to be
confusion about this definition.
TranServ asks for clarification of the
application of the definition of
‘‘affiliate’’ with respect to a merchant
affiliate of a transmission provider that
has turned over tariff administration
functions to an ISO, RTO, or other
independent entity. PNM–TNMP
suggests that the definition of Affiliate
be expanded or clarified to encompass
divisions of an entity that operate as a
functional unit. PNM–TNMP asserts
that such a change would make clear
that an Affiliate includes not only
separate legal entities, but also may
apply to divisions and functional units
within the entity.
Commission Determination
1681. As discussed in section V.C.4,
the Commission lifts the price cap on
reassigned transmission capacity for all
transmission customers, regardless of
affiliation with the transmission
provider. It is therefore no longer
necessary to define an affiliate for
purposes of that provision. The
Commission nonetheless adopts the
proposed definition of Affiliate to
implement the reforms associated with
distribution of operational penalties
discussed in section V.C.5.b.
1682. With regard to the request that
we clarify that an Affiliate does not
apply to transmission-only cooperatives,
we agree with NRECA that the
Commission made clear in Order No.
888–A that there was no corporate
affiliation between G&T cooperatives
and their member distribution
cooperatives.961
1683. TranServ requests clarification
regarding the use of the term ‘‘affiliate’’
in the context of a transmission owner
that has turned over operational control
of its transmission facilities to an RTO,
ISO, or to an independent entity. We
clarify that, for purposes of the
distribution of penalties, if such
transmission owner is not required to be
a transmission provider under a
Commission-approved tariff, the
merchant affiliate of such transmission
owner would not be considered to be an
‘‘affiliate’’ of the RTO, ISO, or
independent entity under the definition
adopted in this Final Rule. The
affiliation of a merchant to a
transmission owner does not establish
an affiliation between such merchant
and the RTO, ISO, or independent entity
transmission provider.
1684. As to PNM–TNMP’s request
that the definition of ‘‘affiliate’’ be
961 Order
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12481
expanded or clarified to encompass
divisions of an entity that operate as a
functional unit, we note that PNM–
TNMP’s concern appears to have been
raised in the context of lifting the price
cap for capacity reassignment, initially
proposed only for non–affiliated
transmission customers. We believe we
have addressed PNM–TNMP’s concerns
by lifting the price cap for capacity
reassignment for all customers,
including affiliates of the transmission
provider and the transmission
provider’s merchant function.
b. Good Utility Practice
NOPR Proposal
1685. In the NOPR, the Commission
proposed to incorporate the definition
of reliable operation from FPA section
215 in the definition of Good Utility
Practice in the pro forma OATT.
Comments
1686. No commenters oppose the
Commission’s proposal to modify the
definition of Good Utility Practice to
reference the reliable operation standard
of FPA section 215.
Commission Determination
1687. The Commission adopts the
NOPR proposal to incorporate the
definition of reliable operation from
FPA section 215 in the definition of
Good Utility Practice in the pro forma
OATT. FPA section 215(b) obligates all
users, owners and operators of the bulk
power system to comply with reliability
standards that will take effect under that
section. Referencing section 215 in the
definition of Good Utility Practice is
appropriate to ensure that the reliability
standards ultimately developed by the
ERO and approved by the Commission
are reflected in the pro forma OATT.
c. Non-Firm Sales
NOPR Proposal
1688. The Commission proposed to
add a definition for Non-Firm Sales to
clarify the treatment of such sales under
section 30.4 of the pro forma OATT.962
The Commission proposed defining a
Non-Firm Sale as ‘‘an energy sale for
which delivery or receipt of the energy
may be interrupted for any reason or for
no reason, without liability on the part
of either the buyer or seller.’’ The
Commission also proposed to clarify
that, for the purposes of applying
962 Section 30.4 as proposed in the NOPR
provides, in relevant part, that ‘‘[t]he Network
Customer shall not operate its designated Network
Resources located in the Network Customer’s or the
Transmission Customer’s Control Area such that the
output of those facilities exceeds its designated
Network Load, plus Non-Firm Sales delivered
pursuant to Part II of the Tariff, plus losses.’’
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section 30.4, energy sales that can only
be interrupted to maintain system
reliability would be considered firm
sales.
sroberts on PROD1PC70 with RULES
Comments
1689. Several commenters argue that
the proposed definition of Non-Firm
Sales could impede a network
customer’s ability to obtain transmission
service for certain types of energy
products. In particular, Duke, EEI, and
Southern question the treatment of
power purchase agreements with LD
provisions under the proposed
definition. Duke contends that a
contract with an LD provision might be
interruptible for any reason, but it
would still provide for liability in the
form of LD payments. As a result, the
LD contract might not fall within the
definition of a Non-Firm Sale. At the
same time, network customers can only
designate resources from system
purchases not linked to a specific
generating unit if the purchase power
agreement is not interruptible for
economic reasons, does not excuse
seller performance for economic
reasons, and requires the network
customer to pay for the purchase.
1690. Commenters are thus concerned
that some contracts with LD provisions
may be too firm to be a Non-Firm Sale,
but not firm enough to be designated as
a network resource. Duke argues that
network customers should be allowed to
operate their Network Resources to both
serve load and sell a firm LD product.
EEI is concerned that the proposed
definition of Non-Firm Sales would
prohibit a network customer from
making an off-system sale of a firm LD
product or any other product that does
not result in undesignation of a Network
Resource, given the restrictions set forth
in section 30.4. Duke and EEI therefore
propose that a Non-Firm Sale should be
defined as any sale that is not
sufficiently firm to be designated a
Network Resource of the purchasing
entity. Raising concerns similar to those
raised by Duke and EEI, Southern
proposes to define Non-Firm Sales as
any sale that does not commit the
associated resource to a third party and
otherwise keeps the resource available
for network service on a noninterruptible basis.
1691. NRECA, however, argues that
contracts with LD provisions are
typically considered firm products, so
long as they cannot be curtailed for
economic reasons alone. NRECA
requests that the Commission confirm
its understanding that the mere
inclusion of an LD provision in a
contract does not make the sale non-
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firm, provided that the sale cannot be
curtailed only for economic reasons.
Commission Determination
1692. The Commission adopts the
proposed definition of a Non-Firm Sale
and incorporates that defined term in
section 30.4 of the pro forma OATT.
Network customers may use network
resources for third party sales only if the
sale is on a non-firm basis. This ensures
that the network resource is available to
serve the network load on an
uninterruptible basis. We conclude that
it would be inappropriate, as some
commenters suggest, to relax the
definition of a Non-Firm Sale to include
any sale that is not otherwise firm
enough to be designated as a network
resource. We address the requirements
for designation of network resources in
section V.D.6, concluding that not all
contracts with LD provisions are
sufficiently firm to be eligible for
designation. There we explain that only
LD provisions that provide for ‘‘make
whole’’ remedies are sufficiently firm to
be designated as network resources. It
does not follow, however, that all
remaining contracts with LD provisions
are non-firm. The very existence of an
LD provision indicates that interruption
of service will result in liability and,
thus, such contracts cannot
automatically be considered Non-Firm
Sales for purposes of section 30.4. To
allow otherwise would create
conflicting incentives for the network
customer.
d. Pre-Confirmed Application
NOPR Proposal
1693. Incident to the proposal to give
priority to requests that are preconfirmed, the NOPR proposed a new
definition of Pre-Confirmed
Application.
Comments
1694. No commenters oppose the
Commission’s proposed definition of a
Pre-Confirmed Application.
Commission Determination
1695. The Commission adopts the
proposed definition of Pre-Confirmed
Application in order to implement the
reforms adopted above regarding the
priority of transmission service requests
under the pro forma OATT.
e. NOPR Proposals Not Adopted
Economy Energy
1696. The Commission also proposed
in the NOPR to adopt a definition of
‘‘economy energy’’ incident to its
proposed changes to section 28.4
regarding the use of secondary network
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service. As discussed in section V.D.7,
the Commission retains the existing
requirement in section 28.4 that permits
use of secondary network service ‘‘to
deliver energy to its Network Loads.’’
The proposed definition of ‘‘economy
energy’’ is therefore unnecessary.
f. Commenter Proposals
1697. Several commenters request
that the Commission amend or add
other definitions in the pro forma
OATT.
(1) Network Transmission Service
Comments
1698. TDU Systems and Northwest
Parties contend that, to help eliminate
undue discrimination, the Commission
should modify the definitions of
‘‘network load’’ and ‘‘network operating
committee’’ in the pro forma OATT.
Although the pro forma OATT already
defines ‘‘network load’’ to include
wholesale native load, TDU Systems
contend that transmission providers
frequently either give preference to their
own retail native load or ignore
wholesale customer native load in
planning and expansion of the system
and in ATC calculations for processing
transmission service requests. TDU
Systems argue that comparable
treatment of wholesale native load and
retail native load is required in all
respects in light of the definition of
‘‘network load.’’ At the same time, TDU
Systems argue that the definition of
‘‘network load’’ unreasonably restricts a
transmission customer from serving a
part of its load at a given delivery point
with non-network resources since it
provides that a customer ‘‘may not
designate only part of the load at a
discrete Point of Delivery.’’
1699. Northwest Parties also assert
that the Commission should revise the
definition of ‘‘network load’’ to permit
point-to-point service and network
service to the same network load if the
point-to-point service is ignored in
calculating load ratio share. Northwest
Parties also argue that the Commission
should allow point-to-point and
network service to the same network
load if the point-to-point service is
purchased as non-firm.
1700. EEI replies in opposition to
TDU Systems’ proposal to eliminate the
requirement that a network customer
may designate only part of its load
delivery as a network load. EEI argues
that TDU Systems are incorrect in
asserting that the definition of ‘‘network
load’’ prohibits a network customer
from serving part of its load with nonnetwork resources and secondary
network service to serve part, or even
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all, of its network load. EEI contends
that adoption of TDU Systems’ proposal
would eliminate one of the fundamental
principles on which network service is
founded: That the network customer
must pay for network service based on
its entire load, including load served by
behind the meter generation, since the
transmission provider must plan its
transmission system to serve the
customer’s entire load.
1701. PNM–TNMP agree on reply that
Commission should reject a change to
the definition in the pro forma OATT
regarding network load. PNM-TNMP
state that the proposal presupposes that
transmission providers discriminate
against transmission customers and
provides preferential treatment to their
own retail native load in terms of
planning and expansion of the system
and in ATC calculations for processing
transmission service requests. PNM–
TNMP contend that they treat retail
native load comparably with other
network customers in all aspects and
believe that any problems encountered
by a transmission customer regarding
undue discrimination should be
addressed through the enforcement or
complaint process, and that a change to
the pro forma OATT is not warranted.
Commission Determination
1702. The Commission declines to
modify the definitions of ‘‘network
load’’ and ‘‘network operating
committee.’’ The reforms related to ATC
calculation and transmission planning
adopted in this Final Rule adequately
address the concerns regarding undue
preference of native load in those areas.
With regard to the request to allow
network customers to serve part of their
load with non-firm point-to-point
service and part with network service,
the Commission already determined in
Order Nos. 888 and 888–A that a
transmission customer is not allowed to
take a combination of both network and
point-to-point transmission service to
serve the same discrete load.963 We are
not persuaded to modify that policy
here.
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(2) Firm and Non-Firm Transmission
Service
Comments
1703. Powerex contends that ‘‘firm
transmission service’’ is not adequately
defined or sufficiently described in the
pro forma OATT to ensure that a
transmission customer is not being
required to pay for firm service that is
curtailed on a regular basis. For
example, Powerex states the
963 See Order No. 888 at 31,736; Order No.
888–A at 30,259.
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Commission could require that firm
transmission service be available at least
95 percent of the time (excluding force
majeure curtailments) in order for
transmission to be defined as ‘‘firm.’’
1704. Powerex also contends that
‘‘non-firm transmission service’’ is
interpreted differently in different
regions. In the Pacific Northwest,
Powerex asserts that non-firm service
implies a lower curtailment priority but
only as a result of actual transmission
system constraints (i.e., once the
operating hour has begun, higher
priority firm reservations cannot
implement schedules over lower
priority non-firm reservation). In
contrast, Powerex argues that, for some
transmission providers located in the
Desert Southwest, transmission capacity
associated with firm service reservations
that have capacity schedules attached to
them (e.g., to deliver operating reserves)
can also be sold as non-firm service that
could be interrupted in the operating
hour by the firm reservation. Powerex
believes that these two types of service
could be described as non-firm, noninterruptible (for the Pacific Northwest)
and non-firm, interruptible (for the
Desert Southwest).
Commission Determination
1705. The Commission finds that the
clarifications proposed by Powerex are
unnecessary to remedy undue
discrimination in the provision of open
access transmission service. In section
V.D.8 of this Final Rule, the
Commission requires transmission
providers to post additional information
regarding curtailments in order to
provide transparency and allow
customers to determine whether they
have been treated in the same manner
as other transmission system users. We
conclude that existing compliance and
enforcement procedures, coupled with
these new posting requirements, are
sufficient to address improper
curtailments of service.
(3) System Impact Study
Comments
1706. Powerex urges the Commission
to modify sections 1.47 and 17.5 of the
pro forma OATT to clarify that
transmission providers are not required
to perform system impact studies for
short-term service requests. Specifically,
Powerex requests that the Commission
amend the definition of a ‘‘system
impact study’’ to refer only to requests
for long-term firm point-to-point service
or network service. Powerex argues that
short-term firm point-to-point service
requests do not require transmission
providers to upgrade their systems and,
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12483
as a result, requiring system impact
studies for short-term requests often
creates unnecessary burdens for
transmission providers by mandating
them to use limited resources to perform
studies that do not offer significant
benefits to customers. Powerex contends
that the 60-day study period is
particularly ill-suited for short-term
transmission requests, most of which
are for service that must commence
within the study period.
Commission Determination
1707. The Commission declines to
modify the definition of ‘‘system impact
study’’ or otherwise modify section 17.5
to restrict system impact studies only to
exclude reference to short-term point-topoint service. Regardless of the length of
a service request, a transmission
provider must assess whether a system
impact study is required to evaluate the
request for transmission service. Only
upon the completion of such an
assessment will the transmission
provider be able to identify the impact
a particular request will have on the
grid. We conclude that eliminating or
shortening the system impact study
period could jeopardize system
reliability and therefore reject the
modifications proposed by Powerex.
(4) Definitions for RTOs, ISOs and ITCs
Comments
1708. Wisconsin Electric and
International Transmission argue that
the terms used in the pro forma OATT
are inadequate when applied to RTO
regions, especially in MISO.
International Transmission and
Wisconsin Electric assert that, in an
RTO, the transmission provider and
transmission owner are separate entities
with separate functions, thus creating a
need for separate definitions. They also
contend that additional definitions may
be needed when the transmission owner
is an independent stand-alone
transmission company operating within
the RTO.
1709. Wisconsin Electric requests that
the Commission define the term
‘‘transmission owner’’ in the pro forma
OATT and specify which of its
provisions are applicable to the
transmission provider and which apply
to the ‘‘transmission owner.’’
Additionally, Wisconsin Electric states
that the pro forma OATT includes a
definition for ‘‘control area’’ and the
NOPR refers to the geographic area
served by transmission providers as its
control area, which in Wisconsin
Electric’s view is inaccurate in the case
of MISO. Wisconsin Electric explains
MISO has shifted to the use of the NERC
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functional model and uses terms such as
‘‘balancing authorities,’’ ‘‘generator
operators,’’ ‘‘reliability authorities,’’ and
the like. Wisconsin Electric therefore
requests that the Commission supplant
the term ‘‘control area’’ in the pro forma
OATT with a term that is predicated on
the performance of a particular function,
not the type of entity performing the
function.
1710. International Transmission does
not object to the Commission’s proposal
to largely retain the existing definitions
set forth in the pro forma OATT, but
asserts that the Commission should
explicitly recognize in the Final Rule
that such definitions may be inadequate
when applied to RTOs. International
Transmission also asks the Commission
not to require RTOs with additional
definitions in their tariffs to remove
those definitions when complying with
the Final Rule and, instead, expressly
allow RTOs to propose additional
definitions that may be necessary.
Commission Determination
1711. As explained in section IV.C, all
transmission providers—including ISOs
and RTOs—will have an opportunity to
demonstrate that departures from the
pro forma OATT, as modified by this
Final Rule, are consistent with or
superior to the terms and conditions of
the pro forma OATT. Proposals to
amend terms such as ‘‘control area’’ or
‘‘transmission owner’’ based on a
particular set of facts are best left for
case-by-case review.
(5) Other Definitions
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Comments
1712. Ameren advocates the
modification of a number of other pro
forma OATT definitions. Ameren
proposes definitions for ‘‘source’’ and
‘‘sink,’’ as well as additional provisions
in section 22.2 governing source and
sink of transmission. Ameren also
requests clarification of the word ‘‘use’’
in section 30.8, arguing that some
entities have assumed that ‘‘use’’ means
scheduled amounts. Ameren argues for
an improved definition of ‘‘transmission
peak’’ because the data necessary no
longer resides with the transmission
owner in an RTO or ISO. Finally,
Ameren suggests a revised definition of
‘‘long-term firm,’’ which would include
only contracts that are longer than one
year, not just one year or longer, arguing
it would reduce the number of contracts
that are only one-year in length that are
used in the denominator for purposes of
calculating the load ratio share and for
ratemaking purposes. On this latter
point, Ameren asserts that such
contracts should be reflected as a
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revenue credit instead. In addition,
Ameren believes that the current
definition of long-term firm point-topoint service in section 1.18 of the pro
forma OATT makes calculation of load
ratio share very difficult in the modern
RTO/Seams Elimination Cost Allocation
(SECA) environment.
Commission Determination
1713. The Commission is not
persuaded to adopt the revisions
proposed by Ameren. We believe that
what constitutes source and sink is
sufficiently addressed in Order No. 888
and OASIS related proceedings and we
will not expand the discussion here.964
Order No. 888 also made clear that there
are no ‘‘load ratio’’ limitations on the
use of interfaces under section 30.8 of
the pro forma OATT.965 Otherwise,
requests for interface capacity are
subject to the pro forma OATT
procedures. Moreover, Ameren has
failed to justify revising the definition of
‘‘transmission peak.’’ While peak load
data ultimately resides with the RTO or
ISO, each transmission provider
coordinates this type of data with RTO
or ISO. Finally, we reaffirm that longterm firm service is service with a term
of one year or more. Modifying the term
of long-term service to reduce the
number of contracts used in the
denominator for purposes of calculating
the load ratio share and for ratemaking
purposes may affect how the
transmission provider plans its system
to service customers and has not been
justified.
E. Enforcement
1714. The Commission attaches
substantial importance to strengthening
compliance with the OATT, on
monitoring and auditing OATT
compliance, including its staff’s efforts
to resolve disputes about compliance
through the Enforcement Hotline and
other dispute resolution mechanisms,
and on investigating potential and
alleged OATT violations. The expansion
of the Commission’s enforcement
powers pursuant to EPAct 2005 directly
augmented its ability to enforce the
OATT by, among other things,
providing authority to assess civil
penalties of up to $1 million for each
day that an OATT violation continues.
The Commission intends to use its
enforcement powers with respect to the
OATT in a fair and even-handed
964 Redirect-related issues are addressed in
section V.D.4.
965 See Order No. 888 at 31,753–54; Order No.
888–A at 30,304–5; see also Sierra Pacific Power
Co., 81 FERC ¶ 61,136 at 61,139–40 (1997); New
England Power Pool, 83 FERC ¶ 61,045 at 61,248
(1998).
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manner, pursuant to the principles set
forth in the Policy Statement on
Enforcement.
1. General Policy
a. Compliance Review Regime
NOPR Proposal
1715. The Commission proposed to
maintain a strong program to audit
compliance with the new pro forma
OATT. The audit program would
include operational audits similar to
past OATT compliance audits, during
which staff may collect information on
implementation of a transmission
provider’s OATT. The Commission
stated that it would issue public reports
of audit results and noted that contested
audits would be subject to the
Commission’s Final Rule on contested
operational audits.966
Comments
1716. Most initial commenters
support a strong staff audit program.967
Other commenters counter that staff
audits will not be needed if the
Commission issues a corrected pro
forma OATT, especially with respect to
RTOs and ISOs.968 These commenters
argue that formal complaints,
Enforcement Hotline calls and random
audits sufficiently inform staff of OATT
compliance issues as to make additional
staff audits unnecessary. Southern
asserts that, under the separation of
function policy, Commission audit staff
should be separated from investigative
and enforcement staff. Particular
commenters contend that the
Commission should focus compliance
efforts on specific OATT provisions,
such as those concerning network
service (Arkansas Cities), or on
structural issues such as independent
planning and operation of transmission
facilities (Reliant). Nevada Companies
suggests that the Commission set up
regional audit teams to foster strong
working relationships with transmission
providers. EPSA asks the Commission to
adopt stronger measures than a staff
audit program to monitor compliance.
EPSA’s proposed measures include
requiring transmission providers to:
designate compliance officers to report
OATT violations to company boards;
undergo compliance audits by an
966 See Procedures for Disposition of Contested
Audit Matters, Order No. 675, 71 FR 9698 (Feb. 27,
2006), FERC Stats. & Regs. ¶ 31,209 (2006)
(Contested Audit Matters), order on rehearing and
clarification, Order No. 675–A, 71 FR 29779 (May
24, 2006), FERC Stats. & Regs. ¶ 31,217 (2006).
967 E.g., APPA, AWEA, EEI, Morgan Stanley,
NRG, Southern, TAPS, and Williams.
968 E.g., Ameren, PNM–TNMP, and South
Carolina E&G. In reply comments, TDU Systems
urge the Commission to reject this contention.
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independent auditor in response to
material violations; and hire an
independent administrator to oversee
OATT compliance and regional
planning efforts if a transmission
provider has not complied with its new
OATT within a specified period of time.
In reply comments, MISO opposes
EPSA’s proposal for a third-party
compliance administrator for RTOs and
ISOs if they do not timely comply with
new OATT provisions, arguing that
these entities already are independent
administrators of transmission grids and
planning processes. MISO asserts that
inserting an ‘‘independent’’ authority
over OATT compliance by RTOs and
ISO would create a superfluous
bureaucratic layer. NRECA opposes
EPSA’s proposal because a third-party
compliance administrator or auditor
would be too expensive and the
Commission cannot delegate its
compliance authority.
1717. Noting that the Commission
required RTOs to undertake extensive
market monitoring in Order No. 2000,
PJM states that the Commission should
require in the pro forma OATT a similar
degree of market monitoring in nonRTO areas to make available to
Commission staff information needed to
ascertain market abuses in these areas.
PJM asserts that any such market
monitoring should be performed by
entities independent of the non-RTO
utilities, with Commission oversight.
Indicated Parties reply that RTOs’
market monitors should examine market
power in transmission planning because
RTOs delegate transmission operations
and planning duties to constituent
transmission owners that retain
incentives to benefit affiliates or
vertically-integrated divisions.
Commission Determination
1718. The Commission adopts the
NOPR proposal to emphasize a strong
staff audit program for compliance with
OATT requirements, including
operational audits. Staff audits of OATT
compliance may be random or targeted
with respect to the entities being
audited or particular provisions of the
OATT that are scrutinized. Because its
responsibility is to assess and ensure
compliance with the OATT, staff will
maintain discretion as to the entities it
audits and the subject matter of these
audits. The Commission encourages
transmission providers to designate
employees as compliance officers for the
OATT or to conduct third-party audits
relating to OATT compliance when
appropriate. However, we do not believe
that staff should forego an audit of an
entity’s OATT compliance solely
because a transmission provider has
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designated an OATT compliance officer,
engaged a third-party auditor, or
transferred transmission functions to an
independent transmission coordinator.
We decline EPSA’s proposal to require
such actions, except on a case-by-case
basis when warranted.
1719. We disagree with PJM’s request
that the Commission require third-party
market monitoring to ascertain market
abuses occurring with respect to
transmission providers outside RTOs
and ISOs, subject to Commission
oversight. In a number of instances
since 2000, the Commission has
established third-party monitoring of a
transmission provider located outside
an RTO or ISO.969 These monitors were
established on a case-specific basis to
address concerns related to the
transmission provider at issue. We have
no evidence to support requiring
monitors for every transmission
provider in the Nation. Further, the
Commission has access to substantial
information on OATT compliance by
transmission providers that are not
RTOs or ISOs through their postings on
OASIS, informal and formal complaints
by customers, and reports by market
monitors for such transmission
providers. Indeed, the revised pro forma
OATT will greatly enhance our
oversight and enforcement capabilities
by increasing the transparency of many
critical functions under the pro forma
OATT, such as ATC calculation and
transmission planning. PJM has not
provided any evidence that the
enhanced transparency under the
OATT, coupled with the Commission’s
own monitoring and audits of OATT
compliance and its enhanced
enforcement authority, will be
insufficient to ascertain and deter OATT
violations. We do not object to the
suggestion of Indicated Parties that RTO
and ISO market monitors examine
market power in transmission planning,
so long as the market monitors’
activities in this respect are consistent
with these roles as set forth in the
applicable RTO and ISO tariffs.
1720. We do not agree with
Southern’s assertion that the
Commission’s audit staff should be
separated from its investigative and
enforcement staff. The Commission’s
separation of functions regulation 970
generally permits Commission auditors,
investigators and enforcement staff to
speak freely to persons inside the
Commission as to the subject matter of
969 See, e.g., Duke Power, 113 FERC ¶ 61,288
(2005); MidAmerican Energy Holdings Co., 113
FERC ¶ 61,298 (2005).
970 18 CFR 385.2202.
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12485
their inquiries.971 Southern has not
cited any justification for restricting
communications among these staff
members or from them to the
Commission. To the contrary, a free
flow of communications among auditors
and investigators, consistent with the
Commission’s rule on staff separation of
functions, should increase the efficiency
of the Commission staff’s compliance
program and enforcement efforts.972
b. Use of Independent Third Party
Audits
NOPR Proposal
1721. The Commission proposed not
to mandate the use of third party
auditors and, instead, proposed that
Commission staff conduct audits of
compliance with the pro forma OATT.
The Commission stated that it may
require third party compliance audits as
part of a compliance plan following a
Commission staff audit report. In
response to situations such as
systematic OATT violations, a pattern of
repeated violations, or violations that
require ongoing monitoring, the
Commission could require an audited
party to hire a third party to continue
compliance audits.
Comments
1722. Most initial commenters agree
with the Commission’s proposal to
require third-party audits only as part of
an individual post-audit compliance
plan.973 EEI and Southwestern Coop
submit that selection of third-party
auditors should be subject to
Commission review and approval, while
South Carolina E&G cautions that the
Commission should carefully weigh the
costs and benefits of independent
auditors before requiring their use.
Southern suggests that third-party
audits be required only for systematic,
egregious OATT violations. Entegra
doubts that third-party auditors can
remedy patterns of discrimination by
transmission providers against
independent merchant generators.
971 Statement of Administrative Policy on
Separation of Functions, 101 FERC ¶ 61,340 at P
24–26 (2002).
972 See also Order No. 675–A at P 25–29 (the
Commission’s regulation and policy statement on
separation of functions remain applicable following
EPAct 2005, and efficiency and sound
administrative practice continue to favor the
sharing of information between the Commission’s
audit staff and investigative staff).
973 E.g., Alberta Intervenors, Arkansas
Commission, Constellation, EEI, EPSA, MISO/PJM
States, Nevada Companies, PNM–TNMP, South
Carolina E&G, Southwestern Coop, and Suez Energy
NA.
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Commission Determination
1723. The Commission adopts the
NOPR proposal not to require generally
the use of third party auditors to assess
compliance with the OATT. We believe
that a requirement for the use of thirdparty audits in compliance plans should
depend on particular facts, including
the egregiousness and extent of
violations found during a staff audit or
investigation and the appropriate scope
or cost of a third-party audit. As stated
above, we encourage transmission
providers to use third-party compliance
audits when appropriate to supplement
our staff’s audit efforts.
2. Civil Penalties
1724. In the NOI, the Commission
asked for comment as to whether it
should address imposing remedies or
penalties against transmission providers
as part of OATT reform. After the NOI,
the Commission issued its Policy
Statement on Enforcement and, in
response to specific authority granted it
in EPAct 2005, issued Order No. 670,
the Anti-manipulation Rule. 974
a. Whether Civil Penalties Should Be
Specified in the OATT
NOPR Proposal
1725. Aside from operational
penalties proposed in the NOPR, 975 the
Commission proposed not to establish a
schedule of enforcement remedies and
sanctions in the pro forma OATT.
Rather, the Commission stated that it
would address OATT violations and
appropriate responses on a case-by-case
basis, consistent with the Policy
Statement on Enforcement. The
Commission explained that it may
impose civil penalties when warranted,
after consideration of applicable factors
listed in the Policy Statement on
Enforcement; OATT violators also will
be expected to disgorge unjust profits
when they can be determined or
reasonably estimated.
sroberts on PROD1PC70 with RULES
Comments
1726. The majority of parties filing
comments on this issue agree that the
Commission should assess civil
penalties on a case-by-case basis under
the guidance of the Policy Statement on
Enforcement. 976 Other commenters
974 Prohibition of Energy Market Manipulation, III
FERC Stats. & Regs. ¶ 31,202 (2006), order denying
rehearing, 114 FERC ¶ 61,300 (2006).
975 NOPR at P 384.
976 E.g., APPA, EEI, EPSA, Nevada Companies,
PNM–TNMP, Southern, and Southwestern Coop.
Southwestern Coop also urges speedy review of
violations and swift assessment of penalties. In
reply comments, Sacramento adds that the
Commission may assess civil penalties against a
transmission provider that engages in unduly
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instead support incorporation in the pro
forma OATT of a schedule of significant
remedies and sanctions for specific
violations to assure transparency and
certainty as to situations in which
penalties would be assessed and to deter
anticompetitive behavior. 977 EPSA
advises that the Commission refrain
from setting pre-determined limits on
penalty amounts because each violation
of a specific pro forma OATT provision
may present different facts that may
warrant different outcomes. Nevada
Companies suggest that the Commission
provide incentives to construct new
transmission infrastructure rather than
implement an overbearing penalty
regime because additional transmission
capacity itself will resolve many
complaints.
1727. Wisconsin Electric concludes
that OATT violations by non-profit
RTOs and ISOs should not be subject to
civil penalties because they would be
passed through to customers and not act
as an effective deterrent. 978 Rather than
assess a penalty in response to an RTO’s
or ISO’s OATT violation, Wisconsin
Electric suggests that the Commission
could intensify oversight of an RTO’s or
ISO’s OATT compliance. NorthWestern
comments, in contrast, that RTOs and
ISOs should not be exempted from civil
penalty assessments for their OATT
violations, because these violations
could have as much or more adverse
effects on transmission access or system
reliability as would OATT violations by
other transmission providers.
1728. Several commenters support the
Commission’s proposal to consider
mitigating factors listed in the Policy
Statement on Enforcement in assessing
civil penalties for OATT violations. 979
In this regard, EEI states that the
Commission should clarify that when a
party engages in self-reporting,
compliance programs or cooperation
with Commission staff, the Commission
will recognize the party’s attorney-client
privilege. 980
1729. EEI suggests that the
Commission establish ‘‘safe harbors’’
against civil penalties for OATT
discriminatory behavior in its transmission
planning process.
977 E.g., Arkansas Commission and ELCON.
978 Wisconsin Electric asserts that the
Commission has recognized this principle in other
contexts, citing Financial Reporting and Cost
Accounting, Oversight and Recovery Practices for
Regional Transmission Organizations and
Independent System Operators, FERC Stats. & Regs.
¶ 35,546 at P 9 (2004).
979 E.g., Nevada Companies and PNM–TNMP.
980 EEI observes that the Commission held in its
final rule on contested audit procedures that ‘‘an
audited person who appropriately interposes the
attorney-client privilege will not be considered noncooperative.’’ Contested Audit Matters at P 35.
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violations involving reasonable
interpretations of tariff provisions or for
actions taken for reliability purposes
that are consistent with good utility
practice. PNM–TNMP and Southern ask
the Commission to clarify that LSEs will
not be penalized for OATT violations
for taking actions necessary to meet
their native load obligations since,
pursuant to new FPA section 217, 981
LSEs should not be considered to have
engaged in ‘‘undue discrimination or
preference’’ for certain actions required
to serve native load customers. TDU
Systems argue in reply comments that a
‘‘safe harbor’’ approach could permit
unduly discriminatory or preferential
behavior that would be penalized under
a case-by-case approach. Entegra replies
that safe harbors for ‘‘reasonable’’ tariff
interpretations would give verticallyintegrated utilities license to
discriminate against competitors, and
suggests that the Commission ensure
that the OATT operates as a sword for
attacking undue discrimination, not as a
shield for defending it. Occidental
replies that transmission providers with
a Commission-approved independent
transmission coordinator should not be
insulated from tariff-based civil
penalties and other sanctions.
Commission Determination
1730. Following enactment in EPAct
2005 of enhanced authority for the
Commission to assess civil penalties for
violations of statutes it administers and
of regulations and orders under these
statutes, the Commission issued the
Policy Statement on Enforcement to set
forth how it intends to use this authority
consistent with the statute. 982
Underlying this policy is the recognition
that the appropriate basis for assessment
of a civil penalty for a violation is an
examination of the facts and
circumstances relating to that violation,
and the use of discretion and flexibility
to address it on its merits. This
examination includes a review of all
applicable mitigating factors set forth in
the Policy Statement on Enforcement.
While we understand that establishing a
schedule of civil penalties for violations
of particular provisions of the pro forma
OATT would establish greater
specificity with respect to civil
penalties, the Commission already
concluded in the Policy Statement on
Enforcement that it would ‘‘not
prescribe specific penalties or develop
formulas for different violations.’’ 983
We see no justification to depart from
981 16
U.S.C. 824q(k).
Statement on Enforcement at P 1.
983 Id. at P 13.
982 Policy
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that decision with respect to violations
of OATT provisions.
1731. Several commenters ask that we
establish specific ‘‘safe harbors’’ or
exemptions from assessment of civil
penalties for OATT violations in
specific circumstances or with respect
to specific types of entities that may
engage in OATT violations. We decline
to create automatic safe harbors for
specific circumstances or specific types
of OATT violations. The creation of
such exemptions would require us to
forego the examination of the specific
circumstances of particular violations
that we described in the Policy
Statement on Enforcement as the
touchstone of our policy in assessing
civil penalties. Instead, we will decide
requests for leniency in particular cases
by using the principles set forth in the
Policy Statement on Enforcement and
considering all applicable mitigating
factors listed therein.984
1732. Likewise, we will not establish
an automatic exemption from civil
penalty assessments for OATT
violations committed by particular types
of entities such as non-profit RTOs and
ISOs. The Commission decided last year
that it would not automatically exempt
RTOs and ISOs from penalties assessed
by the Electric Reliability Organization
or Regional Entities for reliability
violations pursuant to new FPA section
215. In Order No. 672, the Commission
stated, ‘‘[w]hile we recognize that RTOs
and ISOs have some unique
characteristics, we do not believe that a
generic exemption from any type of
penalty is appropriate for any entity,
including an RTO or ISO.’’ 985 We
believe the same principle applies to
civil penalties for OATT violations.
However, in assessing civil penalties for
OATT violations, we will consider all
applicable facts relating to the violator,
including the effect of potential
penalties on the financial viability of the
violator.986
984 We have also provided clarification on the
procedures that would apply to the assessment in
formal proceedings of civil penalties relating to
OATT violations in our recent Statement of
Administrative Policy Regarding the Process for
Assessing Civil Penalties, 117 FERC ¶ 61,317 (2006).
985 Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of
Electric Reliability Standards, Order No. 672, 71 FR
8662 (Feb. 17, 2006), FERC Stats. & Regs. ¶ 31,204
at P 634 (2006), order on reh’g, Order No. 672–A,
FERC Stats. & Regs. ¶ 31,212 (2006).
986 Policy Statement on Enforcement at P 20. Cf.
Order No. 672–A at P 56–57 (holding that for
determining a penalty pursuant to the FPA section
215 reliability program, circumstances such as
organization structure or non-for-profit status will
be considered, but that there should not be an
automatic exemption from monetary penalties for
RTOs and ISOs).
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1733. We agree with commenters who
state that the Commission and its staff
should recognize the valid assertion of
the attorney-client privilege in the
context of investigations, audits and
other fact-finding activities. As EEI
points out, we recently stated with
respect to audits that we would not
consider an entity to be uncooperative
with audit staff if the entity
appropriately asserts that a
communication or document is covered
by that privilege.987 We take the same
position with respect to investigations
or other fact-finding undertakings with
respect to possible OATT violations.
1734. In the Policy Statement on
Enforcement, however, the Commission
drew a distinction between cooperation,
which we expect from entities subject to
the Commission’s jurisdiction given
their statutory obligation to provide
information to us, and ‘‘exemplary’’
cooperation, which ‘‘quickly ends
wrongful conduct, determines the facts,
and corrects a problem.’’ 988 The
Commission explained that we will give
some consideration to exemplary
cooperation and indicated that one
example of such cooperation is a
situation in which an entity being
investigated provides to staff internal
investigations or audit reports relating
to misconduct. These investigations and
reports may include information that an
entity could properly shield from
disclosure pursuant to the attorneyclient privilege. We observe that an
entity that is in a position to assert this
privilege validly also has the option to
waive it. If a waiver of attorney-client
privilege, whether related to an internal
investigation or audit or not, assists staff
in ascertaining the facts relating to
alleged or apparent misconduct, ends
misconduct quickly or otherwise
substantially advances an investigation
or inquiry, that waiver may be an
element in finding ‘‘exemplary
cooperation’’ as described in the Policy
Statement on Enforcement.989
987 Citing
Contested Audit Matters at P 35.
Statement on Enforcement at P 26.
989 See In re PacifiCorp, 118 FERC ¶ 61,026 at P
3, 8 and attached stipulation and consent agreement
at P 24 (2007) (referring to transmission provider’s
waivers of attorney-client privilege as an element in
making finding of exemplary cooperation with
investigation when approving settlement assessing
civil penalty that resolved a transmission provider’s
violations of its OATT, among other matters); In re
Entergy Services, Inc., 118 FERC ¶ 61,027 at P 15,
18 (2007) (same).
988 Policy
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12487
b. Whether Transmission Providers
Should Be Subject to Revocation of
Market-Based Rates for OATT
Violations
NOPR Proposal
1735. The Commission observed in
the NOPR that some OATT violations,
after applying the factors in the Policy
Statement on Enforcement to all facts
and circumstances, may merit
revocation of market-based rate
authority. Before considering revoking
an entity’s market-based rate authority
for an OATT violation, the Commission
proposed that it must find a nexus
between the specific facts relating to the
OATT violation and the entity’s marketbased rate authority. The Commission
also proposed that if it determines, as a
result of a significant OATT violation, to
revoke the market-based rate authority
of a transmission provider within a
particular market, each affiliate of the
transmission provider that possesses
market-based rate authority would have
that authority revoked in that market,
effective on the date of revocation of the
transmission provider’s market-based
rate authority.
Comments
1736. Most parties that submitted
initial comments on this issue support
the Commission’s conclusion that, in
certain circumstances, it may be
appropriate to revoke the market-based
rate authority of an entity that engages
in an OATT violation.990 The majority
of these commenters support the
Commission’s proposal to do so only if
it finds a nexus between the OATT
violation and the entity’s market-based
rate authority.991
1737. Some commenters oppose the
requirement for a nexus between the
OATT violation and the entity’s marketbased rate authority because the
Commission has not stated what facts
would be sufficient to show such a
nexus.992 EPSA and NRECA (in reply
comments) contend that if the
Commission does not remove the
‘‘nexus’’ condition, it should clarify
what constitutes a ‘‘nexus’’ between an
OATT violation and an entity’s marketbased rate authority. Similarly, PNM–
TNMP argues that such a nexus must be
clear and fact-specific, consistent with
the Policy Statement on Enforcement.
TDU Systems contend in reply
990 E.g., EEI, ELCON, Morgan Stanley, Nevada
Companies, Northwest IOUs, Progress Energy,
PNM–TNMP, Sempra Global, Southern, and TDU
Systems.
991 E.g., EEI, Nevada Companies, Northwest IOUs,
Progress Energy, PNM–TNMP, Sempra Global, and
Southern.
992 E.g., APPA.
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comments that, at a minimum, a
transmission provider or its affiliate that
has market-based rate authority must
overcome a rebuttable presumption that
its OATT violation has the requisite
‘‘nexus’’ to support revocation of such
authority.
1738. Other commenters argue that a
serious OATT violation removes the
mitigation of transmission market power
provided by adherence to an OATT,
thereby eviscerating one of the essential
requirements for market-based rate
authority.993 EEI and PNM–TNMP reply
that not every OATT violation
diminishes the availability of
transmission service so as to establish
vertical market power.
1739. APPA and TDU Systems suggest
in reply comments that the proposed
nexus condition would unduly limit
any sanctions, because the shareholders
of the violator could still reap the
benefits of such a violation if an affiliate
that did not have any knowledge of the
OATT violation could continue to
engage in transactions under marketbased rate authority. According to
APPA, this possibility could lessen the
incentive for senior management over a
transmission provider and affiliates to
make OATT compliance a high priority.
As such, APPA and TAPS suggest that
the Commission consider revoking a
transmission provider’s market-based
rate authority for a ‘‘material’’ OATT
violation that effectively denies, delays,
or diminishes a customer’s access to
transmission service essential to
mitigating transmission market power.
1740. TDU Systems caution that
revocation of market-based rate
authority may not be sufficient to deter
OATT violations if reversion to costbased rates may provide a transmission
provider with the ability to recover all
costs and receive higher revenues than
competitive markets might otherwise
produce. Therefore, TDU Systems ask
that the Commission consider
assessment of civil penalties in addition
to revocation of market-based rate
authority.
1741. The majority of commenters
disagree, however, with the
Commission’s proposal to revoke the
market-based rate authority of all
affiliates of a transmission provider to
the same extent that we revoke that
transmission provider’s market-based
rate authority.994 These commenters
assert that affiliates that have no
knowledge of, or involvement in, their
affiliated transmission provider’s
993 E.g.,
APPA, EPSA, and TAPS.
EEI, Nevada Companies, Northwest IOUs,
Progress Energy, PNM–TNMP, Sempra Global, and
Southern.
994 E.g.,
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unlawful activities should not lose their
market-based rate authority as a result of
the transmission provider’s OATT
violation. NRECA replies that marketbased rate authority is a privilege, not a
right, and asserts that the Commission
should revoke market-based rate
authority in response to an OATT
violation that indicates that a public
utility possesses market power.
1742. APPA also suggests that, short
of revocation of a transmission
provider’s market-based rate authority
in response to an OATT violation, the
Commission could condition that
authority, or the market-based rate
authority of the transmission provider’s
affiliates. APPA provides the following
examples of such conditions: A
requirement to participate in joint
planning of transmission facilities with
the transmission provider’s network
customers and offer these customers
appropriate credits under OATT section
30.9; an offer of joint transmission
ownership opportunities to LSEs for
new transmission facilities on
reasonable terms and conditions; and an
offer to network service customers to
participate in the ownership of the
transmission provider’s existing
transmission system on a load ratio
share basis.
Commission Determination
1743. We adopt the NOPR proposal to
revoke an entity’s market-based rate
authority in response to an OATT
violation only upon a finding of a
specific factual nexus between the
violation and the entity’s market-based
rate authority. We believe that the
‘‘nexus condition’’ is required in order
to ensure that our actions are not
arbitrary or capricious or based on an
inadequate factual record. We note that
in this context the Commission has the
burden to show a factual nexus. We do
not assign a burden on the violator to
show the lack of this nexus.
1744. Determining what would be a
sufficient factual nexus between an
OATT violation and revocation of the
violator’s market-based rate authority is
best left to a case-by-case consideration.
The wide range of positions among
commenters on how to define a
sufficient factual nexus itself suggests
that this finding is best made after
review of a specific factual situation.
Some commenters assert that a finding
of a ‘‘serious’’ or ‘‘material’’ violation of
the OATT would be sufficient. We
disagree. While an entity’s
inconsequential OATT violation would
not serve as a basis for revoking that
entity’s market-based rate authority, our
view is that the nexus condition
requires us to find both that a
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Fmt 4701
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substantial OATT violation has
occurred and that the violation either
related to the exercise of the violator’s
market-based rate authority or violated
a specific condition of that authority.
1745. The Commission emphasizes
that we have discretion to fashion
remedies for OATT violations that relate
to the violator’s market-based rate
authority in instances in which we do
not find a factual nexus justifying
revocation of that authority. For
example, in appropriate circumstances,
we may modify or add additional
conditions to the violator’s marketbased rate authority or impose other
requirements to help ensure that the
violator does not commit future, similar
misconduct. Nor is revocation of
market-based rate authority the only
action we may take to respond to an
OATT violation that meets the nexus
condition. We will consider whether to
impose sanctions such as assessment of
civil penalties for particularly serious
OATT violations in addition to
revocation of the violator’s market-based
rate authority.
1746. We do not adopt our proposal
from the NOPR to revoke the marketbased rate authority of each affiliate of
a transmission provider that loses its
market-based rate authority within a
particular market as a result of an OATT
violation. Rather, we will create a
rebuttable presumption that all affiliates
of a transmission provider should lose
their market-based rate authority in each
market in which their affiliated
transmission provider loses its marketbased rate authority as a result of an
OATT violation. We will allow an
affiliate of a transmission provider to
retain its market-based rate authority in
a market area if the affiliate overcomes
the rebuttable presumption with respect
to that market area.
1747. We expect that the issue of
potential revocation of market-based
rate authority will arise as a result of an
OATT violation in a market in which
the transmission provider possesses
transmission market power through the
ownership of transmission facilities in
that market. For these markets, we have
evaluated whether a transmission
provider should receive authority to
make sales of electric power for resale
at market-based rates using a four-prong
analysis. In this analysis we consider
whether the transmission provider and
its affiliates have adequately mitigated
market power in generation and
transmission, whether the transmission
provider or its affiliates can erect other
barriers to entry, and whether there is
evidence that the transmission provider
and its affiliates have engaged in
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affiliate abuse or reciprocal dealing.995
In particular, we have long held that the
existence of an OATT is deemed to
mitigate vertical market power and
transmission market power held by a
transmission provider and its affiliates
in a particular market. An OATT
violation by a transmission provider in
a market in which it possesses
transmission market power that merits
revocation of the transmission
provider’s market-based rate authority
may call into question whether the
transmission provider’s affiliates
continue to qualify for market-based
rates in that market under the standards
that we have established.996 As a result,
995 In our recent NOPR on market-based rates for
wholesale sales of electricity, the Commission
proposed to discontinue referring to affiliate abuse
among a transmission provider and its affiliates as
a separate ‘‘prong’’ of our analysis of whether to
grant market-base rate authority. The Commission
instead proposed to address affiliate abuse by
requiring that transmission providers and their
affiliates comply with restrictions and conditions
set forth in the regulations we propose in that
proceeding. Market-Based Rates for Wholesale
Sales of Electric Energy, Capacity and Ancillary
Services by Public Utilities, 71 FR 33102 (Jun. 7,
2006), FERC Stats. & Regs. ¶ 32,602 at P 13 (2006).
996 We observe that specific situations in which
transmission providers have agreed to resolve staff
allegations that they engaged in OATT violations
have involved transactions with affiliates. See
Idaho Power (settlement of, among other issues, an
Enforcement staff allegation that a transmission
provider permitted its merchant function to request
non-firm transmission to enable the merchant
function to make off-system sales that by definition
were not used to serve native load, so that the
transmission did not qualify for the ‘‘native load’’
priority specified in section 28.4 of the transmission
provider’s OATT); Cleco Corp., 104 FERC ¶ 61,125
(2003) (settlement between Enforcement staff and a
utility holding company and its subsidiaries
relating, in part, to the provision by a transmission
provider of a unique type of transmission service
that was neither made available to non-affiliates nor
included in its FERC tariff); Tucson Electric Power
Co., 109 FERC ¶ 61,272 (2004) (operational audit in
which staff found that, among other matters, a
transmission provider permitted its wholesale
merchant function to purchase hourly non-firm and
monthly firm point-to-point transmission service
using an off-OASIS scheduling procedure while the
transmission provider did not post on its OASIS the
availability of capacity on these paths); South
Carolina Electric & Gas Co., 111 FERC ¶ 61,217
(2005) (settlement of Enforcement staff allegation
that a transmission provider made available firm
point-to-point transmission service to its affiliated
merchant function that did not submit transmission
schedules with specific receipt points for the
service as required by section 13.8 of the
transmission provider’s OATT); and MidAmerican
Energy Co., 112 FERC ¶ 61,346 (2005) (operational
audit in which staff found, among other things, that
a transmission provider permitted its wholesale
merchant function to (a) use network transmission
service to bring short-term energy purchases onto
its system while it simultaneously made off-system
sales, inconsistently with the preamble to Part III
of the transmission provider’s OATT and section
28.6 of its OATT; and (b) confirm firm network
transmission service requests without identifying a
designated network resource or acquiring an
associated network resource, in some instances
using this service to deliver short-term energy
purchases used to facilitate off-system sales,
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we believe that it is appropriate to
establish a presumption in this
circumstance that if we find that a
transmission provider should lose its
market-based rate authority in a market
in which it possesses transmission
market power, we will revoke the
market-based rate authority in that
market of all affiliates of the
transmission provider.
1748. We are mindful, however, that
the circumstances of a particular
affiliate may not always justify the
imposition of a remedy so severe as
revocation of market-based rate
authority in a particular market when its
affiliated transmission provider loses its
market-based rate authority in that
market as a result of an OATT violation.
To afford due process to a transmission
provider’s affiliates in that situation,
and to ensure that a determination to
revoke market-based rate authority in a
particular market for a transmission
provider and all of its affiliates that
possess such authority is adequately
based upon record evidence and not
arbitrary or capricious, we will allow an
opportunity for each such affiliate to
make a showing that it should retain its
market-based rate authority or that
enforcement action against it should be
less severe than revocation. The
determination whether an affiliate has
overcome the rebuttable presumption
depends on an analysis of specific facts
in the record. Relevant facts would
include, but are not limited to, whether:
(1) The transmission provider and the
affiliate were under the same control; (2)
the affiliate knew of, participated in or
was an accomplice to the OATT
violation; (3) the affiliate assisted the
transmission provider in exercising
market power; or (4) the affiliate
benefited from the violation.
c. Whether Certain OATT Violations
Should Be Considered Market
Manipulation Under Section 222 of the
FPA
NOPR Proposal
1749. The Commission proposed in
the NOPR to decline to identify in the
pro forma OATT specific conduct that
constitutes per se market manipulation.
The Commission proposed to consider
on a case-by-case basis, if and when
they arise, whether specific
circumstances relating to OATT
violations constitute market
manipulation under the standards set
forth in Order No. 670.
inconsistent with section 29.2 or section 30.6 of the
transmission provider’s OATT). See also
Commission orders cited in note 989 supra.
PO 00000
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Fmt 4701
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12489
Comments
1750. All commenters on this issue
concur with a case-by-case approach to
it.997 Southwestern Coop suggests that,
as the Commission gains sufficient
experience to describe particular
misconduct as market manipulation per
se, it should identify such misconduct
in the OATT. While contending that the
Commission should act with caution in
listing behaviors that constitute per se
market manipulation in view of the
dynamic nature of markets, TDU
Systems urge the Commission to specify
in the OATT that transmission planning
misconduct could constitute a form of
market manipulation or abuse.
Commission Determination
1751. We adopt the NOPR proposal
for a case-by case approach to
considering whether OATT violations
may constitute market manipulation.
Without reference to a specific factual
pattern developed in an investigation or
on-the-record proceeding, the
Commission is not in a position to
identify market manipulation relating to
OATT violations.998
VI. Information Collection Statement
1752. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain reporting, record
keeping, and public disclosure
(collections of information) imposed by
an agency.999 Pursuant to OMB
regulations, the Commission is
providing notice of its proposed
information collections to OMB for
review under section 3507(d) of the
Paperwork Reduction Act of 1995.1000
1753. The Commission identifies the
information provided under Part 35
subpart C as contained in FERC–516
and Part 37 as contained in FERC–717.
The Commission solicited comments on
the need for this information, whether
the information will have practical
utility, ways to enhance the quality,
utility, and clarity of the information to
be collected, and any suggested methods
for minimizing respondents’ burden,
including the use of automated
information exchanges. The
Commission did not receive any specific
comments regarding its burden
estimates. Where commenters raised
concerns that specific information
collection requirements would be
burdensome to implement, the
997 APPA, Nevada Companies, PNM–TNMP,
Southwestern Coop, and TDU Systems.
998 Similarly, in issuing the Anti-manipulation
Rule, we declined to provide specific examples of
what would constitute market manipulation. Order
No. 670 at P 64–67.
999 5 CFR 1320.11.
1000 44 U.S.C. 3507(d).
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Commission has address those concerns
elsewhere in the rule.
1754. The Commission estimates the
burden for complying with the Final
Rule is as follows: 1001
Number of
respondents
Data collection
Number of
responses
Hours per
response
Total annual
hours
Part 35 (FERC–516)
Conforming tariff changes ...............................................................................
Revision of Imbalance Charges .......................................................................
ATC revisions ..................................................................................................
Planning (Attachment K) ..................................................................................
Congestion studies ..........................................................................................
Attestation of network resource commitment ..................................................
Capacity reassignment ....................................................................................
Operational Penalty annual filing .....................................................................
Creditworthiness—include criteria in the tariff .................................................
116
116
116
116
116
116
116
116
116
1
1
1
1
1
1
1
1
1
25
5
40
200
300
1
100
10
40
2,900
580
4,640
23,200
34,800
116
11,600
1,160
4,640
Sub Total Part 35 .....................................................................................
........................
........................
........................
83,636
Part 37 (FERC–717)
1
116
116
116
116
116
116
116
116
116
116
116
........................
1
1
1
1
1
1
1
1
1
1
1
1
........................
1,920
20
40
80
100
20
90
20
10
5
100
5
........................
1,920
2,320
4,640
9,280
11,600
2,320
10,440
2,320
11,160
580
11,600
580
68,760
Total (Part 35 + Part 37) ...................................................................
........................
........................
........................
140,476
Recordkeeping .................................................................................................
sroberts on PROD1PC70 with RULES
ATC-related standards:
NERC/NAESB Team to develop ..............................................................
Review and comment by utility .................................................................
Implementation by each utility ..................................................................
Mandatory data exchanges .............................................................................
Explanation of change of ATC values .............................................................
Reevaluate CBM and post quarterly ...............................................................
Post OASIS metrics; requests accepted/denied .............................................
Post planning redispatch offers and reliability redispatch data .......................
Post curtailment data .......................................................................................
Post Planning and System Impact Studies .....................................................
Posting of metrics for System Impact Studies ................................................
Post all rules to OASIS ....................................................................................
Sub Total (Part 37) ...................................................................................
116
1
40
4,640
1755. Information Collection Costs:
No comments were received regarding
the Commission’s estimate of costs to
comply with these requirements. The
Commission has projected costs of
compliance as follows:
Total Annual Hours for Collection:
Reporting + recordkeeping hours =
152,396 + 4,640 = 157,036 hours.
Cost to Comply:
Reporting = $17,373,144
152,396 hours @ $114 an hour
(average cost of attorney ($200 per
hour), consultant ($150), technical
($80), and administrative support
($25))
Recordkeeping = $7,478,888
Labor (file/record clerk @ $17 an
hour) 4,640 hours @ $17/hour =
$78,880
Storage 8,000 sq. ft. × $925 (off site
storage) = $7,400,000
Total costs = $24,852,024
Labor $ ($17,373,144 + $78,880) +
Recordkeeping Storage Costs
($7,400,000)
Title: FERC–516, Electric Rate
Schedules and Tariff Filings; FERC–717
Standards for Business Practices and
Communication Protocols for Public
Utilities.
Action: Proposed Collections.
OMB Control Nos. 1902–0096 and
1902–0173.
Respondents: Business or other for
profit.
Frequency of responses: On occasion.
Necessity of the Information: The
Federal Energy Regulatory Commission
adopts these amendments to its
regulations adopted in Order Nos. 888
and 889, and to the pro forma open
access transmission tariff, to ensure that
transmission services are provided on a
basis that is just, reasonable and not
unduly discriminatory or preferential.
The purpose of this rulemaking is to
strengthen the pro forma OATT to
ensure that it achieves its original
purpose—remedying undue
discrimination—not to create new
market structures. We propose to
achieve this goal by increasing the
clarity and transparency of the rules
applicable to the planning and use of
the transmission system and by
addressing ambiguities and the lack of
sufficient detail in several important
areas of the pro forma OATT. The lack
of specificity in the pro forma OATT
creates opportunities for undue
discrimination as well as making the
undue discrimination that does occur
more difficult to detect. To accomplish
this we are proposing five objectives: (1)
To improve transparency and
consistency in several critical areas, by
providing for greater consistency in the
calculation of ATC, (2) to reform the
transmission planning requirements of
the pro forma OATT to eliminate
potential undue discrimination and
support the construction of adequate
transmission facilities to meet the needs
of all LSEs, (3) to remedy certain
portions of the pro forma OATT that
may have permitted utilities to
1001 These burden estimates applied only to the
Final Rule and do not reflect upon all of FERC–516
or FERC–717.
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discriminate against new merchant
generation, including intermittent
generation, (4) to provide for greater
transparency in the provision of
transmission service to allow
transmission customers better access to
information to make their resource
procurement and investment decisions,
as well as to increase the Commission’s
ability to detect any remaining incidents
of undue discrimination; and (5) to
reform and provide greater clarity in
areas that have generated recurring
disputes over the past 10 years, such as
rollover rights, ‘‘redirects,’’ and
generation redispatch. The reforms
proposed in this Final Rule are intended
to address deficiencies in the pro forma
OATT that have become apparent since
the implementation of Order No. 888 in
1996 and to facilitate improved
planning and operation of transmission
facilities.
1756. Interested persons may obtain
information on the reporting
requirements by contacting the
following: Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, Attention:
Michael Miller, Office of the Executive
Director, Phone: (202) 502–8415, fax:
(202) 273–0873, e-mail:
michael.miller@ferc.gov.
1757. For submitting comments
concerning the collections of
information and the associated burden
estimate(s), please send your comments
to the contact listed above and to the
Office of Information and Regulatory
Affairs, Office of Management and
Budget, 725 17th Street, NW.,
Washington, DC 20503 Attention: Desk
Officer for the Federal Energy
Regulatory Commission, phone (202)
395–3122, fax: (202) 395–7285. Due to
security concerns, comments should be
sent electronically to the following email address:
oira_submission@omb.eop.gov. Please
reference the docket number of this
rulemaking in your submission.
sroberts on PROD1PC70 with RULES
VII. Environmental Analysis
1758. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.1002 The Commission
concludes that neither an
Environmental Assessment nor an
Environmental Impact Statement is
required for this Final Rule under
section 380.4(a)(15) of the Commission’s
1002 Regulations Implementing the National
Environmental Policy Act, Order No. 486, 52 FR
47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783
(1987).
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regulations, which provides a
categorical exemption for approval of
actions under sections 205 and 206 of
the FPA relating to the filing of
schedules containing all rates and
charges for the transmission or sale
subject to the Commission’s
jurisdiction, plus the classification,
practices, contracts and regulations that
affect rates, charges, classifications and
services.1003
VIII. Regulatory Flexibility Act
Analysis
1759. The Regulatory Flexibility Act
of 1980 (RFA) 1004 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. This rule applies to public
utilities that own, control or operate
interstate transmission facilities other
than those that have received waiver of
the obligation to comply with Order
Nos. 888 and 889. The total number of
public utilities that, absent waiver,
would have to modify their current
OATTs by filing the revised pro forma
OATT is 116.1005 Of these only six
public utilities, or less than two percent,
have output of four million MWh or less
per year.1006 The Commission does not
consider this a substantial number and,
in any event, each of these entities
retains its rights to waiver of these
requirements.1007 The criteria for waiver
that would be applied under this
rulemaking for small entities is
unchanged from that used to evaluate
requests for waiver under Order Nos.
888 and 889. Accordingly, the
Commission certifies that the Final Rule
will not have a significant economic
1003 18
CFR 380.4(a)(15).
U.S.C. 601–612.
1005 The Commission has identified 116
transmission providers with tariffs on file. We note
that this figure is lower than our initial estimate in
the NOPR, based on FERC Form No. 1 and FERC
Form No. 1–F data.
1006 Id.
1007 The Regulatory Flexibility Act defines a
‘‘small entity’’ as ‘‘one which is independently
owned and operated and which is not dominant in
its field of operation.’’ See 5 U.S.C. 601(3) and
601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop.
v. FERC, 773 F.2d 327, 340–43 (D.C. Cir. 1985), the
court accepted the Commission’s conclusion that,
since virtually all of the public utilities that it
regulates do not fall within the meaning of the term
‘‘small entities’’ as defined in the Regulatory
Flexibility Act, the Commission did not need to
prepare a regulatory flexibility analysis in
connection with its proposed rule governing the
allocation of costs for construction work in progress
(CWIP). The CWIP rules applied to all public
utilities. The revised pro forma OATT will apply
only to those public utilities that own, control or
operate interstate transmission facilities. These
entities are a subset of the group of public utilities
found not to require preparation of a regulatory
flexibility analysis for the CWIP rule.
1004 5
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impact on a substantial number of small
entities.
IX. Document Availability
1760. In addition to publishing the
full text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the Internet through the
Commission’s Home Page (https://
www.ferc.gov) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE.,
Room 2A, Washington DC 20426.
1761. From the Commission’s Home
Page on the Internet, this information is
available in the Commission’s document
management system, eLibrary. The full
text of this document is available on
eLibrary in PDF and Microsoft Word
format for viewing, printing, and/or
downloading. To access this document
in eLibrary, type ‘‘RM05–25’’ or
‘‘RM05–17’’ in the docket number field.
1762. User assistance is available for
eLibrary and the Commission’s website
during normal business hours. For
assistance, please contact the
Commission’s Online Support at 1–866–
208–3676 (toll free) or 202–502–6652 (email at FERCOnlineSupport@FERC.gov),
or the Public Reference Room at 202–
502–8371, TTY 202–502–8659 (e-mail at
public.referenceroom@ferc.gov).
X. Effective Date and Congressional
Notification
1763. These regulations are effective
May 14, 2007. The Commission has
determined, with the concurrence of the
Administrator of the Office of
Information and Regulatory Affairs of
OMB, that this rule is not a ‘‘major rule’’
as defined in section 351 of the Small
Business Regulatory Enforcement
Fairness Act of 1996. The Commission
will submit the Final Rule to both
houses of Congress and to the General
Accounting Office.
List of Subjects
18 CFR Part 35
Electric power rates, Electric utilities,
Reporting and recordkeeping
requirements.
18 CFR Part 37
Conflict of interests, Electric power
plants, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission.
Magalie R. Salas,
Secretary.
In consideration of the foregoing, the
Commission amends parts 35 and 37,
I
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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations
Chapter I, Title 18 of the Code of
Federal Regulations, as follows:
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for part 35
continues to read as follows:
I
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 71–7352.
2. Amend § 35.28 as follows:
a. Paragraph (c) is revised.
b. Paragraphs (d)(i) and (d)(ii) are
redesignated as paragraphs (d)(1) and
(d)(2).
I c. Newly redesignated paragraph
(d)(1) is revised.
I d. Paragraph (e)(1) introductory text is
revised.
I e. Paragraph (e)(1)(ii) is revised.
I
I
I
§ 35.28 Non-discriminatory open access
transmission tariff.
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*
*
*
*
*
(c) Non-discriminatory open access
transmission tariffs. (1) Every public
utility that owns, controls, or operates
facilities used for the transmission of
electric energy in interstate commerce
must have on file with the Commission
a tariff of general applicability for
transmission services, including
ancillary services, over such facilities.
Such tariff must be the open access pro
forma tariff contained in Order No. 888,
FERC Stats. & Regs. ¶ 31,036 (Final Rule
on Open Access and Stranded Costs), as
revised by the open access pro forma
tariff contained in Order No. 890, FERC
Stats. & Regs. ¶ 31,241 (Final Rule on
Open Access Reforms), or such other
open access tariff as may be approved
by the Commission consistent with
Order No. 888, FERC Stats. & Regs
¶ 31,306 and Order No. 890, FERC Stats.
& Regs. ¶ 31,241.
(i) Subject to the exceptions in
paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv)
and (c)(1)(v) of this section, the pro
forma tariff contained in Order No. 888,
FERC Stats. & Regs. ¶ 31,036, as revised
by the open access pro forma tariff
contained in Order No. 890, FERC Stats.
& Regs. ¶ 31,241, and accompanying
rates, must be filed no later than 60 days
prior to the date on which a public
utility would engage in a sale of electric
energy at wholesale in interstate
commerce or in the transmission of
electric energy in interstate commerce.
(ii) If a public utility owns, controls,
or operates facilities used for the
transmission of electric energy in
interstate commerce as of May 14, 2007,
it must file the revisions to the pro
forma tariff contained in Order No. 890,
FERC Stats. & Regs. ¶ 31,241, pursuant
to section 206 of the FPA and
accompanying rates pursuant to section
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205 of the FPA in accordance with the
procedures set forth in Order No. 890,
FERC Stats. & Regs ¶ 31,241.
(iii) If a public utility owns, controls,
or operates transmission facilities used
for the transmission of electric energy in
interstate commerce as of May 14, 2007,
such facilities are jointly owned with a
non-public utility, and the joint
ownership contract prohibits
transmission service over the facilities
to third parties, the public utility with
respect to access over the public utility’s
share of the jointly owned facilities
must file no later than May 14, 2007 the
revisions to the pro forma tariff
contained in Order No. 890, FERC Stats.
& Regs. ¶ 31,241, pursuant to section
206 of the FPA and accompanying rates
pursuant to section 205 of the FPA.
(iv) Any public utility whose
transmission facilities are under the
independent control of a Commissionapproved ISO or RTO may satisfy its
obligation under paragraph (c)(1) of this
section, with respect to such facilities,
through the open access transmission
tariff filed by the ISO or RTO.
(v) If a public utility obtains a waiver
of the tariff requirement pursuant to
paragraph (d) of this section, it does not
need to file the pro forma tariff required
by this section.
(vi) Any public utility that seeks a
deviation from the pro forma tariff
contained in Order No. 888, FERC Stats.
& Regs. ¶ 31,036, as revised in Order No.
890, FERC Stats. & Regs. ¶ 31,241, must
demonstrate that the deviation is
consistent with the principles of Order
No. 888, FERC Stats. & Regs ¶ 31,036
and Order No. 890, FERC Stats. & Regs.
¶ 31,241.
(vii) Each public utility’s open access
transmission tariff must include the
standards incorporated by reference in
part 38 of this chapter.
(2) Subject to the exceptions in
paragraphs (c)(2)(i) and (c)(3)(iii) of this
section, every public utility that owns,
controls, or operates facilities used for
the transmission of electric energy in
interstate commerce, and that uses those
facilities to engage in wholesale sales
and/or purchases of electric energy, or
unbundled retail sales of electric energy,
must take transmission service for such
sales and/or purchases under the open
access transmission tariff filed pursuant
to this section.
(i) For sales of electric energy
pursuant to a requirements service
agreement executed on or before July 9,
1996, this requirement will not apply
unless separately ordered by the
Commission. For sales of electric energy
pursuant to a bilateral economy energy
coordination agreement executed on or
before July 9, 1996, this requirement is
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effective on December 31, 1996. For
sales of electric energy pursuant to a
bilateral non-economy energy
coordination agreement executed on or
before July 9, 1996, this requirement
will not apply unless separately ordered
by the Commission.
(ii) [Reserved.]
(3) Every public utility that owns,
controls, or operates facilities used for
the transmission of electric energy in
interstate commerce, and that is a
member of a power pool, public utility
holding company, or other multi-lateral
trading arrangement or agreement that
contains transmission rates, terms or
conditions, must have on file a joint
pool-wide or system-wide open access
transmission tariff, which tariff must be
the pro forma tariff contained in Order
No. 888, FERC Stats. & Regs. ¶ 31,036,
as revised by the pro forma tariff
contained in Order No. 890, FERC Stats.
& Regs. ¶ 31,241, or such other open
access tariff as may be approved by the
Commission consistent with Order No.
888, FERC Stats. & Regs. ¶ 31,036 and
Order No. 890, FERC Stats. & Regs.
¶ 31,241.
(i) For any power pool, public utility
holding company or other multi-lateral
arrangement or agreement that contains
transmission rates, terms or conditions
and that is executed after May 14, 2007,
this requirement is effective on the date
that transactions begin under the
arrangement or agreement.
(ii) For any power pool, public utility
holding company or other multi-lateral
arrangement or agreement that contains
transmission rates, terms or conditions
and that is executed on or before May
14, 2007, a public utility member of
such power pool, public utility holding
company or other multi-lateral
arrangement or agreement that owns,
controls, or operates facilities used for
the transmission of electric energy in
interstate commerce must file the
revisions to its joint pool-wide or
system-wide contained in Order No.
890, FERC Stats. & Regs. ¶ 31,241,
pursuant to section 206 of the FPA and
accompanying rates pursuant to section
205 of the FPA in accordance with the
procedures set forth in Order No. 890,
FERC Stats. & Regs ¶ 31,241.
(iii) A public utility member of a
power pool, public utility holding
company or other multi-lateral
arrangement or agreement that contains
transmission rates, terms or conditions
and that is executed on or before July 9,
1996 must take transmission service
under a joint pool-wide or system-wide
open access transmission tariff filed
pursuant to this section for wholesale
trades among the pool or system
members.
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(4) Consistent with paragraph (c)(1) of
this section, every Commissionapproved ISO or RTO must have on file
with the Commission a tariff of general
applicability for transmission services,
including ancillary services, over such
facilities. Such tariff must be the pro
forma tariff contained in Order No. 888,
FERC Stats. & Regs. ¶ 31,036, as revised
by the pro forma tariff contained in
Order No. 890, FERC Stats. & Regs.
¶ 31,241, or such other open access tariff
as may be approved by the Commission
consistent with Order No. 888, FERC
Stats. & Reg. ¶ 31,036 and Order No.
890, FERC Stats. & Regs. ¶ 31,241.
(i) Subject to paragraph (c)(4)(ii) of
this section, a Commission-approved
ISO or RTO must file the revisions to
the pro forma tariff contained in Order
No. 890, FERC Stats. & Regs. ¶ 31,241,
pursuant to section 206 of the FPA and
accompanying rates pursuant to section
205 of the FPA in accordance with the
procedures set forth in Order No. 890,
FERC Stats. & Regs ¶ 31,241.
(ii) If a Commission-approved ISO or
RTO can demonstrate that its existing
open access tariff is consistent with or
superior to the revisions to the pro
forma tariff contained in Order No. 888,
FERC Stats. & Regs. ¶ 31,036, as revised
by the pro forma tariff in Order No. 890,
FERC Stats. & Regs. ¶ 31,241, or any
portions thereof, the Commissionapproved ISO or RTO may instead set
forth such demonstration in its filing
pursuant to section 206 in accordance
with the procedures set forth in Order
No. 890, FERC Stats. & Regs ¶ 31,241.
(d) Waivers. * * *
(1) No later than May 14, 2007, or
*
*
*
*
*
(e) Non-public utility procedures for
tariff reciprocity compliance. (1) A nonpublic utility may submit a transmission
tariff and a request for declaratory order
that its voluntary transmission tariff
meets the requirements of Order No.
888, FERC Stats. & Regs. ¶ 31,036 and
Order No. 890, FERC Stats. & Regs.
¶ 31,241.
*
*
*
*
*
(ii) If the submittal is found to be an
acceptable transmission tariff, an
applicant in a Federal Power Act (FPA)
section 211 or 211A proceeding against
the non-public utility shall have the
burden of proof to show why service
under the open access tariff is not
sufficient and why a section 211 or
211A order should be granted.
*
*
*
*
*
PART 37—OPEN ACCESS SAME-TIME
INFORMATION SYSTEMS
3. The authority citation for part 37
continues to read as follows:
I
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Authority: 16 U.S.C. 791–825r, 2601–2645;
31 U.S.C. 9701; 42 U.S.C. 7101–7352.
4. Amend § 37.6 as follows:
a. Paragraph (a)(1) is revised.
b. Paragraph (b) introductory text is
revised.
I c. Paragraphs (b)(1)(v) through
(b)(1)(viii) are added.
I d. Paragraphs (b)(2)(i) through
(b)(2)(iii) are revised.
I e. Paragraph (b)(3) is revised.
I f. Paragraphs (c)(2) and (c)(5) are
revised.
I g. Paragraphs (e)(1) and (e)(2)(ii) are
revised.
I h. Paragraph (e)(3)(ii) is revised.
I i. Paragraphs (h), (i) and (j) are added.
I
I
I
§ 37.6 Information to be posted on the
OASIS.
(a) * * *
(1) Make requests for transmission
services offered by Transmission
Providers, Resellers and other providers
of ancillary services, request the
designation of a network resource, and
request the termination of the
designation of a network resource;
*
*
*
*
*
(b) Posting transfer capability. The
available transfer capability on the
Transmission Provider’s system (ATC)
and the total transfer capability (TTC) of
that system shall be calculated and
posted for each Posted Path as set out
in this section.
(1) * * *
(v) Available transfer capability or
ATC means the transfer capability
remaining in the physical transmission
network for further commercial activity
over and above already committed uses,
or such definition as contained in
Commission-approved Reliability
Standards.
(vi) Total transfer capability or TTC
means the amount of electric power that
can be moved or transferred reliably
from one area to another area of the
interconnected transmission systems by
way of all transmission lines (or paths)
between those areas under specified
system conditions, or such definition as
contained in Commission-approved
Reliability Standards.
(vii) Capacity Benefit Margin or CBM
means the amount of TTC preserved by
the Transmission Provider for loadserving entities, whose loads are located
on that Transmission Provider’s system,
to enable access by the load-serving
entities to generation from
interconnected systems to meet
generation reliability requirements, or
such definition as contained in
Commission-approved Reliability
Standards.
(viii) Transmission Reliability Margin
or TRM means the amount of TTC
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12493
necessary to provide reasonable
assurance that the interconnected
transmission network will be secure, or
such definition as contained in
Commission-approved Reliability
Standards.
(2) * * *
(i) Information used to calculate any
posting of ATC and TTC must be dated
and time-stamped and all calculations
shall be performed according to
consistently applied methodologies
referenced in the Transmission
Provider’s transmission tariff and shall
be based on Commission-approved
Reliability Standards as well as current
industry practices, standards and
criteria.
(ii) On request, the Responsible Party
must make all data used to calculate
ATC, TTC, CBM, and TRM for any
constrained posted paths publicly
available (including the limiting
element(s) and the cause of the limit
(e.g., thermal, voltage, stability), as well
as load forecast assumptions) in
electronic form within one week of the
posting. The information is required to
be provided only in the electronic
format in which it was created, along
with any necessary decoding
instructions, at a cost limited to the cost
of reproducing the material. This
information is to be retained for six
months after the applicable posting
period.
(iii) System planning studies,
facilities studies, and specific network
impact studies performed for customers
or the Transmission Provider’s own
network resources are to be made
publicly available in electronic form on
request and a list of such studies shall
be posted on the OASIS. A study is
required to be provided only in the
electronic format in which it was
created, along with any necessary
decoding instructions, at a cost limited
to the cost of reproducing the material.
These studies are to be retained for five
years.
(3) Posting. The ATC, TTC, CBM, and
TRM for all Posted Paths must be posted
in megawatts by specific direction and
in the manner prescribed in this
subsection.
(i) Constrained posted paths.—(A) For
firm ATC and TTC.
(1) The posting shall show ATC, TTC,
CBM, and TRM for a 30-day period. For
this period postings shall be: by the
hour, for the current hour and the 168
hours next following; and thereafter, by
the day. If the Transmission Provider
charges separately for on-peak and offpeak periods in its tariff, ATC, TTC,
CBM, and TRM will be posted daily for
each period.
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(2) Postings shall also be made by the
month, showing for the current month
and the 12 months next following.
(3) If planning and specific requested
transmission studies have been done,
seasonal capability shall be posted for
the year following the current year and
for each year following to the end of the
planning horizon but not to exceed 10
years.
(B) For non-firm ATC and TTC. The
posting shall show ATC, TTC, CBM and
TRM for a 30-day period by the hour
and days prescribed under paragraph
(b)(3)(i)(A)(1) of this section and, if so
requested, by the month and year as
prescribed under paragraph (b)(3)(i)(A)
(2) and (3) of this section. The posting
of non-firm ATC and TTC shall show
CBM as zero.
(C) Updating posted information for
constrained paths.
(1) The capability posted under
paragraphs (b)(3)(i)(A) and (B) of this
section must be updated when
transactions are reserved or service ends
or whenever the estimate for the path
changes by more than 10 percent.
(2) All updating of hourly information
shall be made on the hour.
(3) When the monthly and yearly
capability posted under paragraphs
(b)(3)(i)(A) and (B) of this section are
updated because of a change in TTC by
more than 10 percent, the Transmission
Provider shall post a brief, but specific,
narrative explanation of the reason for
the update. This narrative should
include, the specific events which gave
rise to the update (e.g., scheduling of
planned outages and occurrence of
forced transmission outages, de-ratings
of transmission facilities, scheduling of
planned generation outages and
occurrence of forced generation outages,
changes in load forecast, changes in new
facilities’ in-service dates, or other
events or assumption changes) and new
values for ATC on the path (as opposed
to all points on the network).
(4) When the monthly and yearly
capability posted under paragraphs
(b)(3)(i)(A) and (B) of this section
remain unchanged at a value of zero for
a period of six months, the
Transmission Provider shall post a brief,
but specific, narrative explanation of the
reason for the unavailability of ATC.
(ii) Unconstrained posted paths.
(A) Postings of firm and nonfirm ATC,
TTC, CBM, and TRM shall be posted
separately by the day, showing for the
current day and the next six days
following and thereafter, by the month
for the 12 months next following. If the
Transmission Provider charges
separately for on-peak and off-peak
periods in its tariff, ATC, TTC, CBM,
and TRM will be posted separately for
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the current day and the next six days
following for each period. These
postings are to be updated whenever the
ATC changes by more than 20 percent
of the Path’s TTC.
(B) If planning and specific requested
transmission studies have been done,
seasonal capability shall be posted for
the year following the current year and
for each year following until the end of
the planning horizon but not to exceed
10 years.
(iii) Calculation of CBM.
(A) The Transmission Provider must
reevaluate its CBM needs at least every
year.
(B) The Transmission Provider must
post its practices for reevaluating its
CBM needs.
(iv) Daily load. The Transmission
Provider must post on a daily basis, its
actual daily peak load for the prior day.
(c) * * *
(2) Transmission Providers must
provide a downloadable file of their
complete tariffs in the same electronic
format as the tariff that is filed with the
Commission. Transmission Providers
also must provide a link to all of the
rules, standards and practices that relate
to transmission services posted on the
Transmission Providers’ public Web
sites.
*
*
*
*
*
(5) Customers choosing to use the
OASIS to offer for resale transmission
capacity they have purchased must post
relevant information to the same OASIS
as used by the Transmission Provider
from whom the Reseller purchased the
transmission capacity. This information
must be posted on the same display
page, using the same tables, as similar
capability being sold by the
Transmission Provider, and the
information must be contained in the
same downloadable files as the
Transmission Provider’s own available
capability.
*
*
*
*
*
(e) Posting specific transmission and
ancillary service requests and responses.
(1) General rules.
(i) All requests for transmission and
ancillary service offered by
Transmission Providers under the pro
forma tariff, including requests for
discounts, and all requests to designate
or terminate a network resource, must
be made on the OASIS and posted prior
to the Transmission Provider
responding to the request, except as
discussed in paragraphs (e)(1)(ii) and
(iii) of this section. The Transmission
Provider must post all requests for
transmission service, for ancillary
service, and for the designation or
termination of a network resource
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comparably. Requests for transmission
service, ancillary service, and to
designate and terminate a network
resource, as well as the responses to
such requests, must be conducted in
accordance with the Transmission
Provider’s tariff, the Federal Power Act,
and Commission regulations.
(ii) The requirement in paragraph
(e)(1)(i) of this section, to post requests
for transmission and ancillary service
offered by Transmission Providers
under the pro forma tariff, including
requests for discounts, prior to the
Transmission Provider responding to
the request, does not apply to requests
for next-hour service made during Phase
I.
(iii) In the event that a discount is
being requested for ancillary services
that are not in support of basic
transmission service provided by the
Transmission Provider, such request
need not be posted on the OASIS.
(iv) In processing a request for
transmission or ancillary service, the
Responsible Party shall post the same
information as required in paragraphs
(c)(4) and (d)(3) of this section, and the
following information: the date and time
when the request is made, its place in
any queue, the status of that request,
and the result (accepted, denied,
withdrawn). In processing a request to
designate or terminate the designation
of a network resource, the Responsible
Party shall post the date and time when
the request is made.
(v) For any request to designate or
terminate a network resource, the
Transmission Provider (at the time
when the request is received), must post
on the OASIS (and make available for
download) information describing the
request (including: name of requestor,
identification of the resource, effective
time for the designation or termination,
identification of whether the transaction
involves the Transmission Provider’s
wholesale merchant function or any
affiliate; and any other relevant terms
and conditions) and shall keep such
information posted on the OASIS for at
least 30 days. A record of the
transaction must be retained and kept
available as part of the audit log
required in § 37.7.
(vi) The Transmission Provider shall
post a list of its current designated
network resources and all network
customers’ current designated network
resources on OASIS. The list of network
resources should include the name of
the resource, its geographic and
electrical location, its total installed
capacity, and the amount of capacity to
be designated as a network resource.
(2) * * *
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(ii) Information to support the reason
for the denial, including the operating
status of relevant facilities, must be
maintained for five years and provided,
upon request, to the potential
Transmission Customer and the
Commission’s Staff.
*
*
*
*
*
(3) * * *
(ii) Information to support any such
curtailment or interruption, including
the operating status of the facilities
involved in the constraint or
interruption, must be maintained and
made available upon request, to the
curtailed or interrupted customer, the
Commission’s Staff, and any other
person who requests it, for five years.
*
*
*
*
*
(h) Posting information summarizing
the time to complete transmission
service request studies. (1) For each
calendar quarter, the Responsible Party
must post the set of measures detailed
in paragraph (h)(1)(i) through paragraph
(h)(1)(vi) of this section related to the
Responsible Party’s processing of
transmission service request system
impact studies and facilities studies.
The Responsible Party must calculate
and post the measures in paragraph
(h)(1)(i) through paragraph (h)(1)(vi) of
this section separately for requests for
short-term firm point-to-point
transmission service, long-term firm
point-to-point transmission service, and
requests to designate a new network
resource and must be calculated and
posted separately for transmission
service requests from Affiliates and
transmission service requests from
Transmission Customers who are not
Affiliates. The Responsible Party is
required to include in the calculations
of the measures in paragraph (h)(1)(i)
through paragraph (h)(1)(vi) of this
section all studies the Responsible Party
conducts of transmission service
requests on another Transmission
Provider’s OASIS.
(i) Process time from initial service
request to offer of system impact study
agreement.
(A) Number of new system impact
study agreements delivered during the
reporting quarter to entities that request
transmission service,
(B) Number of new system impact
study agreements delivered during the
reporting quarter to entities that request
transmission service more than thirty
(30) days after the Responsible Party
received the request for transmission
service,
(C) Mean time (in days), for all
requests acted on by the Responsible
Party during the reporting quarter, from
the date when the Responsible Party
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received the request for transmission
service to when the Responsible Party
changed the transmission service
request status to indicate that the
Responsible Party could offer
transmission service or needed to
perform a system impact study,
(D) Mean time (in days), for all system
impact study agreements delivered by
the Responsible Party during the
reporting quarter, from the date when
the Responsible Party received the
request for transmission service to the
date when the Responsible Party
delivered a system impact study
agreement, and
(E) Number of new system impact
study agreements executed during the
reporting quarter.
(ii) System impact study processing
time.
(A) Number of system impact studies
completed by the Responsible Party
during the reporting quarter,
(B) Number of system impact studies
completed by the Responsible Party
during the reporting quarter more than
60 days after the Responsible Party
received an executed system impact
study agreement,
(C) For all system impact studies
completed more than 60 days after
receipt of an executed system impact
study agreement, average number of
days study was delayed due to
transmission customer’s actions (e.g.,
delays in providing needed data),
(D) Mean time (in days), for all system
impact studies completed by the
Responsible Party during the reporting
quarter, from the date when the
Responsible Party received the executed
system impact study agreement to the
date when the Responsible Party
provided the system impact study to the
entity who executed the system impact
study agreement, and
(E) Mean cost of system impact
studies completed by the Responsible
Party during the reporting quarter.
(iii) Transmission service requests
withdrawn from the system impact
study queue.
(A) Number of transmission service
requests withdrawn from the
Responsible Party’s system impact study
queue during the reporting quarter,
(B) Number of transmission service
requests withdrawn from the
Responsible Party’s system impact study
queue during the reporting quarter more
than 60 days after the Responsible Party
received the executed system impact
study agreement, and
(C) Mean time (in days), for all
transmission service requests
withdrawn from the Responsible Party’s
system impact study queue during the
reporting quarter, from the date the
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12495
Responsible Party received the executed
system impact study agreement to date
when request was withdrawn from the
Responsible Party’s system impact study
queue.
(iv) Process time from completed
system impact study to offer of facilities
study.
(A) Number of new facilities study
agreements delivered during the
reporting quarter to entities that request
transmission service,
(B) Number of new facilities study
agreements delivered during the
reporting quarter to entities that request
transmission service more than thirty
(30) days after the Responsible Party
completed the system impact study,
(C) Mean time (in days), for all
facilities study agreements delivered by
the Responsible Party during the
reporting quarter, from the date when
the Responsible Party completed the
system impact study to the date when
the Responsible Party delivered a
facilities study agreement, and
(D) Number of new facilities study
agreements executed during the
reporting quarter.
(v) Facilities study processing time.
(A) Number of facilities studies
completed by the Responsible Party
during the reporting quarter,
(B) Number of facilities studies
completed by the Responsible Party
during the reporting quarter more than
60 days after the Responsible Party
received an executed facilities study
agreement,
(C) For all facilities studies completed
more than 60 days after receipt of an
executed facilities study agreement,
average number of days study was
delayed due to transmission customer’s
actions (e.g., delays in providing needed
data),
(D) Mean time (in days), for all
facilities studies completed by the
Responsible Party during the reporting
quarter, from the date when the
Responsible Party received the executed
facilities study agreement to the date
when the Responsible Party provided
the facilities study to the entity who
executed the facilities study agreement,
(E) Mean cost of facilities studies
completed by the Responsible Party
during the reporting quarter, and
(F) Mean cost of upgrades
recommended in facilities studies
completed during the reporting quarter.
(vi) Service requests withdrawn from
facilities study queue.
(A) Number of transmission service
requests withdrawn from the
Responsible Party’s facilities study
queue during the reporting quarter,
(B) Number of transmission service
requests withdrawn from the
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Responsible Party’s facilities study
queue during the reporting quarter more
than 60 days after the Responsible Party
received the executed facilities study
agreement, and
(C) Mean time (in days), for all
transmission service requests
withdrawn from the Responsible Party’s
facilities study queue during the
reporting quarter, from the date the
Responsible Party received the executed
facilities study agreement to date when
request was withdrawn from the
Responsible Party’s facilities study
queue.
(2) The Responsible Party is required
to post the measures in paragraph
(h)(1)(i) through paragraph (h)(1)(vi) of
this section for each calendar quarter
within 15 days of the end of the
calendar quarter. The Responsible Party
will keep the quarterly measures posted
on OASIS for three calendar years.
(3) The Responsible Party will be
required to post on OASIS the measures
in paragraph (h)(3)(i) through paragraph
(h)(3)(iv) of this section in the event the
Responsible Party, for two consecutive
calendar quarters, completes more than
twenty (20) percent of the studies
associated with requests for
transmission service from entities that
are not Affiliates of the Responsible
Party more than sixty (60) days after the
Responsible Party delivers the
appropriate study agreement. The
Responsible Party will have to post the
measures in paragraph (h)(3)(i) through
paragraph (h)(3)(iv) of this section until
it processes at least ninety (90) percent
of all studies within 60 days after it has
received the appropriate executed study
agreement. For the purposes of
calculating the percent of studies
completed more than sixty (60) days
after the Responsible Party delivers the
appropriate study agreement, the
Responsible Party should aggregate all
system impact studies and facilities
studies that it completes during the
reporting quarter. The Responsible Party
must calculate and post the measures in
paragraph (h)(3)(i) through paragraph
(h)(3)(iv) of this section separately for
requests for short-term firm point-topoint transmission service, long-term
firm point-to-point transmission service,
and requests to designate a new network
resource and must be calculated and
posted separately for transmission
service requests from Affiliates and
transmission service requests from
Transmission Customers who are not
Affiliates.
(i) Mean, across all system impact
studies the Responsible Party completes
during the reporting quarter, of the
employee-hours expended per system
impact study the Responsible Party
completes during reporting period;
(ii) Mean, across all facilities studies
the Responsible Party completes during
the reporting quarter, of the employeehours expended per facilities study the
Responsible Party completes during
reporting period;
(iii) The number of employees the
Responsible Party has assigned to
process system impact studies;
(iv) The number of employees the
Responsible Party has assigned to
process facilities studies.
(4) The Responsible Party is required
to post the measures in paragraph
(h)(3)(i) through paragraph (h)(3)(iv) of
this section for each calendar quarter
within 15 days of the end of the
calendar quarter. The Responsible Party
will keep the quarterly measures posted
on OASIS for five calendar years.
(i) Posting data related to grants and
denials of service. The Responsible
Party is required to post data each
month listing, by path or flowgate, the
number of transmission service requests
that have been accepted and the number
of transmission service requests that
have been denied during the prior
month. This posting must distinguish
between the length of the service
request (e.g., short-term or long-term
requests) and between the type of
service requested (e.g., firm point-topoint, non-firm point-to-point or
network service). The posted data must
show:
(1) The number of non-Affiliate
requests for transmission service that
have been rejected,
(2) The total number of non-Affiliate
requests for transmission service that
have been made,
(3) The number of Affiliate requests
for transmission service that have been
rejected, and
(4) The total number of Affiliate
requests for transmission service that
have been made.
(j) Posting redispatch data.
(1) The Transmission Provider must
allow the posting on OASIS of any third
party offer to relieve a specified
congested transmission facility.
(2) The Transmission Provider must
post on OASIS (i) its monthly average
cost of planning and reliability
redispatch, for which it invoices
customers, at each internal transmission
facility or interface over which it
provides redispatch service and (ii) a
high and low redispatch cost for the
month for each of these same
transmission facilities. The transmission
provider must post this data on OASIS
as soon as practical after the end of each
month, but no later than when it sends
invoices to transmission customers for
redispatch-related services.
5. In § 37.7, paragraph (b) is revised to
read as follows:
I
§ 37.7 Auditing Transmission Service
Information.
*
*
*
*
*
(b) Audit data must remain available
for download on the OASIS for 90 days,
except ATC/TTC postings that must
remain available for download on the
OASIS for 20 days. The audit data are
to be retained and made available upon
request for download for five years from
the date when they are first posted in
the same electronic form as used when
they originally were posted on the
OASIS.
Note: The following appendices will not be
published in the Code of Federal
Regulations.
Appendix A: Summary of Compliance
Filing Requirements
For a more detailed description of
compliance obligations please refer to
the Final Rule paragraph number. For
further information related to the Final
Rule, such as electronic versions of the
pro forma OATT showing tariff changes
adopted in the Final Rule in redline/
strikeout format, and further
information regarding docketing of
compliance filings and specific filing
instructions, please visit our Web site at
the following location https://
www.ferc.gov/industries/electric/indusact/oatt-reform.asp.
Compliance action
30 ..............................................
sroberts on PROD1PC70 with RULES
Deadline (days after publication
in Federal Register)
Optional Implementation FPA section 205 filings allowing transmission providers to propose
previously approved variations from the pro forma OATT that have been affected by pro
forma OATT Final Rule reforms to remain in effect subject to a demonstration that such
variations continue to be consistent with or superior to the revised Final Rule pro forma
OATT (non RTO/ISO transmission providers). Such optional filings must request a 90 day
effective date to facilitate Commission review under section 205.
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Final rule
paragraph No.
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Deadline (days after publication
in Federal Register)
Compliance action
60 ..............................................
Non-ISO/RTO transmission providers submit FPA section 206 filings that contain the non-rate
terms and conditions set forth in Final Rule. These filings need only contain the revised
provisions adopted in the Final Rule. Transmission providers utilizing the optional Implementation FPA section 205 filing described above, need only submit tariff sheets necessary
to implement the remaining modifications required under the Final Rule, i.e., modifications
related to tariff provisions that did not implicate previously-approved variations.
Transmission Providers must post a ‘‘strawman’’ proposal for compliance with each of the
nine planning principles adopted in the Final Rule. This may be posted on the Transmission Providers Web site or its OASIS site.
NERC/NAESB status report and work plan for completion of ATC related business practices
and standards.
NAESB status report and work plan for completion of OASIS functionality or uniform business
practices (other than those related to ATC).
Transmission Providers must submit redesigned transmission charges that reflect the Capacity Benefit Margin set-aside through a limited issue section 205 rate filing as part of their
initial ATC related compliance filings.
Submit compliance filings with Attachment C (ATC) of the pro forma OATT .............................
ISOs and RTOs, and transmission providers located within an ISO/RTO footprint, submit FPA
section 206 filings that contain the non-rate terms and conditions set forth in the Final Rule.
These filings need only contain the revised provisions adopted in the Final Rule or a demonstration that previously approved variations continue to be consistent with or superior to
the revised pro forma OATT.
Submit compliance filings with Attachment K (Planning) of the pro forma OATT or RTOs and
ISOs file a demonstration that their planning processes are consistent with or superior to
the planning principles in the Final Rule.
Transmission Providers must file a revised Attachment C to incorporate any changes to
NERC’s and NAESB’s reliability and business practice standards to achieve consistency in
ATC within 60 days of completion of the NERC and NAESB processes.
After the submission of FPA section 206 compliance filings, transmission providers may submit FPA section 205 filings proposing rates for the services provided for in the tariff, as well
as non-rate terms and conditions that differ from those set forth in the Final Rule if those
provisions are ‘‘consistent with or superior to’’ the pro forma OATT.
75 ..............................................
90 ..............................................
120 ............................................
180 ............................................
210 ............................................
210 ............................................
N/A ............................................
N/A ............................................
12497
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paragraph No.
P 135
P 443
P 223
P 141
P 263
P 140
P 157, P 161
P 140, P 442
P 325
P 135
Appendix B: Commenting Party
Acronyms
INITIAL COMMENTERS
Abbreviation
Initial commenters
Alberta Intervenors .............................................................
Alberta Intervenors (TransCanada Energy Ltd., ENMAX Energy Marketing, Inc.;
EPCOR Merchant and Capital, LP; and TransAlta Corporation).
Alcoa Inc. and Alcoa Power Generating Inc.
Allegheny Power and Allegheny Energy Supply Company, LLC.
Ameren Services Company.
American Transmission Company LLC.
American Municipal Power-Ohio, Inc.
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California.
American Public Power Association.
Alliance for Retail Choice.
Arkansas Public Service Commission.
Arkansas Municipal Power Association.
American Wind Energy Association.
Barrick Goldstrike Mines Inc.
San Francisco Bay Area Rapid Transit District.
Bonneville Power Administration.
BP Energy Company.
U.S. Bureau of Reclamation.
Cogeneration Association of California (Coalinga Cogeneration Co., Mid-Set Cogeneration Co., Kern River Cogeneration Co., Sycamore Cogeneration Co., Sargent
Canyon Cogeneration Co., Salinas River Cogeneration Co., Midwest Sunset Cogeneration Co. and Watson Cogeneration Co.) and Energy Producers and Users
Coalition (Aera Energy LLC, BP American, Inc., Chevron USA, Inc., ConocoPhilips
Co., ExxonMobil Power and Gas Services, Inc., Shell Oil Products, US, THUMS
Long Beach Co., Occidental Elk Hills, Inc., and Valero Refining Co.—California).
California Independent System Operator Corporation.
Public Utilities Commission of the State of California.
Calpine Corporation.
John D. Chandley and William W. Hogan.
sroberts on PROD1PC70 with RULES
Alcoa ..................................................................................
Allegheny ............................................................................
Ameren ...............................................................................
American Transmission ......................................................
AMP-Ohio ...........................................................................
Anaheim .............................................................................
APPA ..................................................................................
ARC ....................................................................................
Arkansas Commission .......................................................
Arkansas Municipal ............................................................
AWEA .................................................................................
Barrick ................................................................................
BART ..................................................................................
Bonneville ...........................................................................
BP Energy ..........................................................................
Bureau of Reclamation ......................................................
CAC/EPUC .........................................................................
CAISO ................................................................................
California Commission .......................................................
Calpine ...............................................................................
Chandley-Hogan ................................................................
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INITIAL COMMENTERS—Continued
Abbreviation
Initial commenters
ColumbiaGrid .....................................................................
ColumbiaGrid Members (Bonneville Power Administration; Avista Corp.; Public Utility
District No. 1 of Chelan County, Washington; Public Utility District No. 2 of Grant
County, Washington; Puget Sound Energy, Inc.; Seattle City Light; and Tacoma
Power.
Community Power Alliance Members (Entergy, Progress Energy, Salt River Project
Agricultural Improvement and Power District, and Southern Co.).
Constellation Energy Group, Inc.
Committee on Regional Electric Power Corp.
Dominion Resources Services, Inc. (Armstrong Energy Limited Partnership, LLLP;
Dominion Energy Marketing, Inc.; Elwood Energy, LLC; Fairless Energy, LLC;
Pleasants Energy, LLC and Virginia Electric and Power Co. d/b/a Dominion Virginia Power).
Dow Chemical Corp.
Duke Energy Corp.
E.ON U.S. LLC.
East Texas Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.;
Sam Rayburn Generation and Electric Cooperative, Inc. and Tex-La Electric Cooperative of Texas, Inc.
Eastern NC Towns (Towns of Black Creek, NC; Lucama, NC; Stantonsburg, NC).
Edison Electric Institute.
Electricity Consumers Resource Council, American Iron and Steel Institute, and
American Forest & Paper Institute.
Emerald People’s Utility District.
Entegra Power Group LLC and LS Power Associates, L.P.
Entergy Services, Inc.
Electric Power Supply Association.
Exelon Corporation.
Public Works Commission of the City of Fayetteville, North Carolina.
Fertilizer Institute.
FirstEnergy Service Company (First Energy Solutions; American Transmission Systems, Inc.; Jersey Central Power and Light Co.; Metropolitan Edison Co.; and
Pennsylvania Electric Co.).
Flathead Electric Cooperative.
Florida Public Service Commission.
Florida Industrial Cogeneration Association.
Florida Municipal Power Agency and Midwest Municipal Transmission Group.
CE Generation, LLC; Ormat Technologies, Inc.; Caithness Energy, LLC; and Geothermal Energy Association.
Grant County PUD, Chelan County PUD and Pend Oreille County PUD.
Great Northern Power Development, L.P.
Imperial Irrigation District.
Indianapolis Power & Light Co.
Central Hudson Gas & Electric Corp.; Consolidated Edison Co. of New York, Inc.;
LIPA; New York Power Authority; New York State Electric & Gas Corp.; Orange
and Rockland Utilities, Inc.; and Rochester Gas and Electric Corp.
International Transmission Co. d/b/a ITCTransmission and Michigan Electric Transmission Co., LLC.
IRH Management Committee and the Schedule 20A Service Providers.
ISO New England, Inc. and New England Power Pool.
ISO/RTO Council.
Lassen Municipal Utility District.
City of Los Angeles Department of Water and Power.
Large Public Power Council.
Manitoba Hydro.
Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, and Public
Service Commission of Yazoo City.
MidAmerican Energy Company and PacifiCorp.
Midwest Independent Transmission System Operator, Inc.
Midwest ISO Transmission Owners.
Organization of MISO States and Organization of PJM States, Inc.
Morgan Stanley Capital Group Inc.
North American Energy Standards Board.
National Association of Regulatory Utility Commissioners.
National Grid USA.
North Carolina Electric Membership Corporation.
Northern California Power Agency.
North American Electric Reliability Corporation.
Public Utilities Commission of Nevada.
Nevada Power Company and Sierra Pacific Power Company.
New Jersey Board of Public Utilities.
New Mexico Attorney General.
New York State Public Service Commission.
Community Power Alliance ................................................
Constellation .......................................................................
CREPC ...............................................................................
Dominion ............................................................................
Dow ....................................................................................
Duke ...................................................................................
E.ON ...................................................................................
East Texas Cooperatives ...................................................
Eastern North Carolina ......................................................
EEI ......................................................................................
ELCON ...............................................................................
Emerald ..............................................................................
Entegra ...............................................................................
Entergy ...............................................................................
EPSA ..................................................................................
Exelon ................................................................................
Fayetteville .........................................................................
Fertilizer Institute ................................................................
FirstEnergy .........................................................................
Flathead .............................................................................
Florida Commission ...........................................................
Florida Industrial Cogeneration Association ......................
FMPA .................................................................................
Geothermal Producers .......................................................
Grant ..................................................................................
Great Northern ...................................................................
Imperial ...............................................................................
Indianapolis Power .............................................................
Indicated New York Transmission Owners ........................
International Transmission .................................................
sroberts on PROD1PC70 with RULES
IRH Management ...............................................................
ISO New England ..............................................................
ISO/RTO Council ...............................................................
Lassen ................................................................................
LDWP .................................................................................
LPPC ..................................................................................
Manitoba Hydro ..................................................................
MDEA .................................................................................
MidAmerican ......................................................................
MISO ..................................................................................
MISO Transmission Owners ..............................................
MISO/PJM States ...............................................................
Morgan Stanley ..................................................................
NAESB ...............................................................................
NARUC ...............................................................................
National Grid ......................................................................
NCEMC ..............................................................................
NCPA .................................................................................
NERC .................................................................................
Nevada Commission ..........................................................
Nevada Companies ............................................................
New Jersey Board ..............................................................
New Mexico Attorney General ...........................................
New York Commission .......................................................
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12499
INITIAL COMMENTERS—Continued
Abbreviation
Initial commenters
Newfoundland ....................................................................
Newmont Mining ................................................................
Northeast Utilities ...............................................................
Newfoundland and Labrador Hydro.
Newmont USA Limited, dba Newmont Mining Corp.
Northeast Utilities Service Company (Connecticut Light and Power Co.; Western
Massachusetts Electric Co.; Public Service Co. of New Hampshire; Holyoke Water
Power Co.; and Holyoke Power and Electric Co.).
Northwest Investor-Owned Utilities (Avista Corp., Portland General Electric Co., and
Puget Sound Energy, Inc.).
Northwest Parties (Avista Corp., Bonneville Power Administration, PacifiCorp, PNGC
Power, Portland General Electric Co., Public Power Council, Public Utility Commission of Oregon and Puget Sound Energy, Inc.).
NorthWestern Corporation.
Nebraska Public Power District.
National Rural Electric Cooperative Association.
NRG Energy, Inc.
New York Association of Public Power.
Occidental Chemical Corporation.
Oklahoma Corporation Commission.
Old Dominion Electric Cooperative.
Oversight Resources, LLC.
Public Generating Pool and Chelan County PUD.
Pinnacle West Capital Corporation; Arizona Public Service Company; and APS Energy Services Company, Inc.
PJM Interconnection, LLC.
Public Service Company of New Mexico and Texas-New Mexico Power Company.
Powerex Corp.
PPL Companies.
PPM Energy, Inc.
Progress Energy, Inc. (Carolina Power & Light Co. d/b/a Progress Energy Carolinas
and Florida Power Corp., d/b/a Progress Energy Florida; and Progress Ventures,
Inc.).
Project for Sustainable FERC Energy Policy (American Wind Energy Association,
Delaware Division of the Public Advocate, Environmental Law & Policy Center, Illinois Citizens Utility Board, Natural Resources Defense Council, Northwest Energy
Coalition, Office of the Ohio Consumers’ Counsel, Pace Energy Project, Project for
Sustainable FERC Energy Policy, Renewable Northwest Project, West Wind
Wires, and Wind on the Wires).
Public Service Electric and Gas Company; PSEG Power LLC; and PSEC Energy Resources & Trade LLC (PSEG Companies).
Public Power Council.
Reliant Energy, Inc.
Sacramento Municipal Utility District.
Salt River Project Agricultural Improvement and Power District.
San Diego Gas & Electric Company.
City of Santa Clara, California d/b/a Silicon Valley Power.
South Carolina Public Service Authority.
Southern California Edison.
City of Seattle—City Light Department.
Sempra Global.
South Carolina Electric & Gas Company.
South Carolina Office of Regulatory Staff.
Southern Company Services, Inc.
Southwest Area Transmission Sub-Regional Planning Group.
Southwestern Electric Cooperative, Inc.
Southwest Power Pool, Inc.
Steel Manufacturers Association.
Suez Energy North America, Inc.
Tacoma Power.
Transmission Agency of Northern California.
Transmission Access Policy Study Group.
Transmission Dependent Utilities Systems.
TransAlta Energy Marketing (US) Inc.
TranServ International, Inc.
Tucson Electric Power Company.
Tennessee Valley Authority.
Utah Associated Municipal Power Systems.
Western Area Power Administration.
Western Electricity Coordinating Council.
WestConnect Companies.
Western Governors’ Association.
Williams Power Company, Inc.
Wisconsin Electric Power Company.
Western Systems Power Pool, Inc.
Northwest IOUs ..................................................................
Northwest Parties ...............................................................
NorthWestern .....................................................................
NPPD .................................................................................
NRECA ...............................................................................
NRG ...................................................................................
NYAPP ...............................................................................
Occidental ..........................................................................
Oklahoma Commission ......................................................
Old Dominion .....................................................................
Oversight Resources ..........................................................
PGP ....................................................................................
Pinnacle ..............................................................................
PJM ....................................................................................
PNM–TNMP .......................................................................
Powerex .............................................................................
PPL .....................................................................................
PPM ....................................................................................
Progress Energy ................................................................
Project for Sustainable FERC Energy Policy ....................
sroberts on PROD1PC70 with RULES
PSEG .................................................................................
Public Power Council .........................................................
Reliant ................................................................................
Sacramento ........................................................................
Salt River ............................................................................
San Diego G&E ..................................................................
Santa Clara ........................................................................
Santee Cooper ...................................................................
SCE ....................................................................................
Seattle ................................................................................
Sempra Global ...................................................................
South Carolina E&G ...........................................................
South Carolina Regulatory Staff ........................................
Southern .............................................................................
Southwest Transmission ....................................................
Southwestern Coop ............................................................
SPP ....................................................................................
Steel Manufacturers Association .......................................
Suez Energy NA ................................................................
Tacoma ..............................................................................
TANC ..................................................................................
TAPS ..................................................................................
TDU Systems .....................................................................
TransAlta ............................................................................
TranServ .............................................................................
Tucson ................................................................................
TVA ....................................................................................
Utah Municipals ..................................................................
WAPA .................................................................................
WECC ................................................................................
WestConnect ......................................................................
Western Governors ............................................................
Williams ..............................................................................
Wisconsin Electric ..............................................................
WSPP .................................................................................
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INITIAL COMMENTERS—Continued
Abbreviation
Initial commenters
Xcel ....................................................................................
Xcel Energy Services, Inc.
REPLY COMMENTERS
Abbreviation
Reply commenters
Alberta Intervenors .............................................................
Alberta Intervenors (TransCanada Energy Ltd., ENMAX Energy Marketing, Inc.;
EPCOR Merchant and Capital, LP; and TransAlta Corporation).
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California.
American Public Power Association.
Barrick Goldstrike Mines Inc.
Bonneville Power Administration.
California Independent System Operator Corporation.
Public Utilities Commission of the State of California.
Canadian Electricity Association.
John D. Chandley and William W. Hogan.
California Municipal Utilities Association.
ColumbiaGrid Members (Bonneville Power Administration; Avista Corp.; Public Utility
District No. 1 of Chelan County, Washington; Public Utility District No. 2 of Grant
County, Washington; Puget Sound Energy, Inc.; Seattle City Light; and Tacoma
Power.
Community Power Alliance Members (Entergy, Progress Energy, Salt River Project
Agricultural Improvement and Power District, and Southern Co.).
Detroit Edison Co.
Duke Energy Corp.
Dynegy Power Marketing, Inc.
East Texas Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.;
Sam Rayburn Generation and Electric Cooperative, Inc. and Tex-La Electric Cooperative of Texas, Inc.
Edison Electric Institute.
ElectriCities of North Carolina, Inc.
Entegra Power Group LLC and LS Power Associates, L.P.
Entergy Services, Inc.
Electric Power Supply Association.
Exelon Corporation.
Public Works Commission of the City of Fayetteville, North Carolina.
Fertilizer Institute.
Florida Municipal Power Agency and Midwest Municipal Transmission Group.
Great Northern Power Development, L.P.
Hoosier Energy Rural Electric Cooperative, Inc.
H.Q. Energy Services (U.S.), Inc.
Indianapolis Power & Light Co.
Industrial Customers of Northwest Utilities (Air Liquide; Air Products; BPB Gypsum,
Inc.; Blue Heron Paper Company; Boeing; Boise Cascade; CNC Containers,
Northwest; Chemi-Con Materials Corporation; Dyno Nobel, Inc.; ConAgra Foods;
Eka Chemicals, Inc.; Evanite Fiber; Georgia-Pacific; Grays Harbor Paper, L.P.;
Hewlett-Packard; Inland Empire Paper Co.; Intel; J.R. Simplot; Kimberly-Clark Corporation; Longview Fibre; Microsoft Corporation; Norpac Foods; Noveon Kalama,
Inc.; Oregon Steel Mills; PCC Structurals, Inc.; Ponderay Newsprint Co; Shell Oil
Products US; Simpson Paper; Simpson Timber; Solar Grade Silicon LLC; SP
Newsprint Co.; Tesoro Refining and Marketing Co.; Wah Chang; West Linn Paper
Company; Weyerhaeuser).
International Transmission Co. d/b/a ITCTransmission and Michigan Electric Transmission Co., LLC.
ISO/RTO Council.
Lassen Municipal Utility District.
Large Public Power Council.
Mid-Continent Area Power Pool.
Mark B. Lively.
Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public
Service Commission of Yazoo City, Arkansas Electric Cooperative Corporation,
Municipal Energy Agency of Mississippi, and Lafayette Utilities System*.1008
MidAmerican Energy Company and PacifiCorp.
Midwest Independent Transmission System Operator, Inc.
Morgan Stanley Capital Group Inc.
National Association of Regulatory Utility Commissioners.
North Carolina Transmission Planning Collaborative Participants.
Northern California Power Agency.
Newmont USA Limited, dba Newmont Mining Corp.
North Carolina Utilities Commission; Public Staff of the North Carolina Utilities Commission; and the Attorney General of the State of North Carolina.
Anaheim .............................................................................
APPA ..................................................................................
Barrick ................................................................................
Bonneville ...........................................................................
CAISO ................................................................................
California Commission .......................................................
Canadian Electricity Association ........................................
Chandley-Hogan ................................................................
CMUA .................................................................................
ColumbiaGrid .....................................................................
Community Power Alliance ................................................
Detroit Edison .....................................................................
Duke ...................................................................................
Dynegy ...............................................................................
East Texas Cooperatives ...................................................
EEI ......................................................................................
ElectriCities ........................................................................
Entegra ...............................................................................
Entergy ...............................................................................
EPSA ..................................................................................
Exelon ................................................................................
Fayetteville .........................................................................
Fertilizer Institute ................................................................
FMPA .................................................................................
Great Northern ...................................................................
Hoosier ...............................................................................
H.Q. Energy .......................................................................
Indianapolis Power .............................................................
Industrial Customers of Northwest Utilities ........................
International Transmission .................................................
sroberts on PROD1PC70 with RULES
ISO/RTO Council ...............................................................
Lassen ................................................................................
LPPC ..................................................................................
MAPP .................................................................................
Mark Lively .........................................................................
MDEA .................................................................................
MidAmerican ......................................................................
MISO ..................................................................................
Morgan Stanley ..................................................................
NARUC ...............................................................................
NC Transmission Planning Participants ............................
NCPA .................................................................................
Newmont Mining ................................................................
North Carolina Commission ...............................................
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REPLY COMMENTERS—Continued
Abbreviation
Reply commenters
Northwest IOUs ..................................................................
Northwest Investor-Owned Utilities (Avista Corp., Portland General Electric Co., and
Puget Sound Energy, Inc.).
NorthWestern Corporation.
National Rural Electric Cooperative Association.
Occidental Chemical Corporation.
Oklahoma Gas and Electric Company.
Ohio Power Siting Board, American Municipal Power-Ohio, Inc. and Buckeye Power,
Inc.
Old Dominion Electric Cooperative; Southern Maryland Electric Cooperative, Inc.; Allegheny Electric Cooperative, Inc.; and North Carolina Electric Membership Corporation.
Omaha Public Power District.
Pennsylvania Public Utility Commission.
PJM Interconnection, LLC.
Public Service Company of New Mexico and Texas-New Mexico Power Company.
Powerex Corp.
PPM Energy, Inc.
Progress Energy, Inc. (Carolina Power & Light Co. d/b/a Progress Energy Carolinas
and Florida Power Corp., d/b/a Progress Energy Florida; and Progress Ventures,
Inc.).
Project for Sustainable FERC Energy Policy (Delaware Division of the Public Advocate, Environmental Law & Policy Center, Fresh Energy, Natural Resources Defense Council, Northwest Energy Coalition, Pace Energy Project, Project for Sustainable FERC Energy Policy, Renewable Northwest Project, West Wind Wires,
and Wind on the Wires).*
Public Power Council.
Sacramento Municipal Utility District.
Salt River Project Agricultural Improvement and Power District.
City of Santa Clara, California d/b/a Silicon Valley Power.
City of Seattle—City Light Department.
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Company.
Southern Company Services, Inc.
Southwest Power Pool, Inc.
Steel Manufacturers Association.
Strategic Energy, L.L.C.
Transmission Agency of Northern California.
Transmission Access Policy Study Group.
Transmission Dependent Utilities Systems.
PJM Interconnection, LLC; Electric Consumers Resource Council; Electric Power
Supply Association; Natural Resources Defense Council; Renewable Northwest
Project; Project for Sustainable FERC Energy Policy; Center for Energy Efficiency
& Renewable Technologies; Shell Trading Gas and Power Company; American
Wind Energy Association; and Exelon.
Utah Associated Municipal Power Systems.
WestConnect Companies.
Williams Power Company, Inc.
Wolverine Power Supply Cooperative, Inc.
WPS Companies (Wisconsin Public Service Corporation and Upper Peninsula Power
Company).
Western Systems Power Pool, Inc.
Xcel Energy Services, Inc.
NorthWestern .....................................................................
NRECA ...............................................................................
Occidental ..........................................................................
OG&E .................................................................................
Ohio Power Siting Board ...................................................
Old Dominion .....................................................................
Omaha Public Power .........................................................
Pennsylvania Commission .................................................
PJM ....................................................................................
PNM-TNMP ........................................................................
Powerex .............................................................................
PPM ....................................................................................
Progress Energy ................................................................
Project for Sustainable FERC Energy Policy ....................
Public Power Council .........................................................
Sacramento ........................................................................
Salt River ............................................................................
Santa Clara ........................................................................
Seattle ................................................................................
Seminole ............................................................................
South Carolina E&G ...........................................................
Southern .............................................................................
SPP ....................................................................................
Steel Manufacturers Association .......................................
Strategic Energy .................................................................
TANC ..................................................................................
TAPS ..................................................................................
TDU Systems .....................................................................
Transparent Dispatch Advocates .......................................
Utah Municipals ..................................................................
WestConnect ......................................................................
Williams ..............................................................................
Wolverine ...........................................................................
WPS Companies ................................................................
WSPP .................................................................................
Xcel ....................................................................................
TECHNICAL CONFERENCE COMMENTERS
sroberts on PROD1PC70 with RULES
Abbreviation
Technical conference commenters
APPA* ................................................................................
APS* ...................................................................................
Bonneville* .........................................................................
Constellation* .....................................................................
EEI* ....................................................................................
EPSA*1009 ..........................................................................
Exelon* ...............................................................................
NAESB* ..............................................................................
NARUC* .............................................................................
National Grid* .....................................................................
National Grid/Central Hudson ............................................
American Public Power Association.
Arizona Public Service Company.
Bonneville Power Administration.
Constellation Energy Group, Inc.
Exelon Corporation on behalf of Edison Electric Institute (EEI).
Electric Power Supply Association.
Exelon.
North American Energy Standards Board.
National Association of Regulatory Utility Commissioners.
National Grid USA.
National Grid USA, Central Hudson Gas & Electric Corporation, and American Wind
Energy.
Prague Power, LLC, on behalf of the North American Electric Reliability Corporation.
NERC* ................................................................................
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TECHNICAL CONFERENCE COMMENTERS—Continued
Abbreviation
Technical conference commenters
New York Parties ...............................................................
Consolidated Edison Co. of New York, Inc., Orange and Rockland Utilities, Inc., New
York Power Authority, and Independent Power Producers of New York, Inc.
Great River Energy on behalf of National Rural Electric Cooperative Association
(NRECA).
NRG Energy, Inc. on behalf of Electric Power Supply Association (EPSA).
PacifiCorp.
PJM Interconnection, LLC.
PPM Energy, Inc. on behalf of American Wind Energy Association
Progress Energy, Inc. (Carolina Power & Light Company, d/b/a. Progress Energy
Carolinas, Inc. and Florida Power Corporation, d/b/a Progress Energy Florida,
Inc.).
Renewable Northwest Project.
San Diego Gas & Electric Company.
Southern Minnesota Municipal Power Agency and Transmission Access Policy Study
Group.
Transmission Dependent Utilities Systems.
South Carolina Office of Regulatory Staff.
Southern Company Services, Inc.
Western Electricity Coordinating Council.
Williams Power.
Williams Power Company, Inc.
Xcel Energy Services, Inc.
NRECA* .............................................................................
NRG on behalf of EPSA* ...................................................
PacifiCorp ...........................................................................
PJM* ...................................................................................
AWEA* ...............................................................................
Progress Energy* ...............................................................
Renewable Northwest Project* ..........................................
San Diego G&E ..................................................................
TAPS* .................................................................................
TDU Systems .....................................................................
South Carolina Regulatory Staff ........................................
Southern* ...........................................................................
WECC* ...............................................................................
Williams* .............................................................................
Williams* .............................................................................
Xcel* ...................................................................................
SUPPLEMENTAL COMMENTERS
Abbreviation
Supplemental commenters
Alabama Commission ........................................................
Ameren ...............................................................................
APPA ..................................................................................
Barrick ................................................................................
Bonneville ...........................................................................
BP Energy ..........................................................................
California Commission .......................................................
Community Power Alliance ................................................
Alabama Public Service Commission.
Ameren Services Company.
American Public Power Association.
Barrick Goldstrike Mines Inc.
Bonneville Power Administration.
BP Energy Company.
Public Utilities Commission of the State of California.
Community Power Alliance Members (Entergy, Progress Energy, Salt River Project
Agricultural Improvement and Power District, and Southern Co.).
Constellation Energy Group, Inc.
Duke Energy Corp.
E.ON U.S. LLC.
Edison Electric Institute.
Entergy Services, Inc.
Electric Power Supply Association and American Wind Energy Association.
Florida Public Service Commission.
Georgia Public Service Commission.
Large Public Power Council.
Mark B. Lively.
Midwest Independent Transmission System Operator, Inc.
Nevada Power Company and Sierra Pacific Power Company.
North Carolina Utilities Commission; Public Staff of the North Carolina Utilities Commission; and the Attorney General of the State of North Carolina.
National Rural Electric Cooperative Association.
Oklahoma Gas and Electric Company.
Pacific Coast Parties (Avista Corporation, Bonneville Power Administration,
PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc., the
Sacramento Municipal Utility District and the Transmission Agency of Northern
California).
Public Generating Pool.
Pinnacle West Companies, Public Service Company of New Mexico, Texas-New
Mexico Power Company, and UniSource Energy Corporation.
Public Service Company of New Mexico and Texas-New Mexico Power Company.
Powerex Corp.
PPL Companies.
PPM Energy, Inc.
Progress Energy, Inc. (Carolina Power & Light Company, d/b/a. Progress Energy
Carolinas, Inc. and Florida Power Corporation, d/b/a Progress Energy Florida,
Inc.).
Progress Energy, Inc. and MidAmerican Energy Company.
Public Power Council.
Southeastern Association of Regulatory Utility Commissioners.
South Carolina Electric & Gas Company.
South Carolina Office of Regulatory Staff.
Constellation .......................................................................
Duke ...................................................................................
E.ON ...................................................................................
EEI ......................................................................................
Entergy ...............................................................................
EPSA and AWEA ...............................................................
Florida Commission ...........................................................
Georgia Commission ..........................................................
LPPC ..................................................................................
Mark Lively .........................................................................
MISO ..................................................................................
Nevada Companies ............................................................
North Carolina Commission ...............................................
NRECA ...............................................................................
OG&E .................................................................................
Pacific Coast Parties ..........................................................
PGP ....................................................................................
Southwest Utilities ..............................................................
sroberts on PROD1PC70 with RULES
PNM-TNMP ........................................................................
Powerex .............................................................................
PPL .....................................................................................
PPM ....................................................................................
Progress Energy ................................................................
Progress Energy and MidAmerican ...................................
Public Power Council .........................................................
SEARUC ............................................................................
South Carolina E&G ...........................................................
South Carolina Regulatory Staff ........................................
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SUPPLEMENTAL COMMENTERS—Continued
Abbreviation
Supplemental commenters
Southern .............................................................................
Tacoma ..............................................................................
TAPS ..................................................................................
TDU Systems .....................................................................
Transparent Dispatch Advocates .......................................
Southern Company Services, Inc.
Tacoma Power.
Transmission Access Policy Study Group.
Transmission Dependent Utilities Systems.
Transparent Dispatch Advocates (American Wind Energy Association; Center for Energy Efficiency & Renewable Technologies; Electric Consumers Resource Council;
Electric Power Supply Association; Exelon Corporation; Natural Resources Defense Council; PJM Interconnection, LLC; PPM Energy; Project for Sustainable
FERC Energy Policy; Renewable Northwest Project; and Shell Trading Gas and
Power Company)*1010
Western Governors’ Association.
Williams Power Company, Inc.
WIRES.
Xcel Energy Services, Inc.
Western Governors ............................................................
Williams ..............................................................................
WIRES ................................................................................
Xcel ....................................................................................
Appendix C: Pro Forma Open Access
Transmission Tariff
Table of Contents
sroberts on PROD1PC70 with RULES
I. Common Service Provisions
1 Definitions
1.1 Affiliate
1.2 Ancillary Services
1.3 Annual Transmission Costs
1.4 Application
1.5 Commission
1.6 Completed Application
1.7 Control Area
1.8 Curtailment
1.9 Delivering Party
1.10 Designated Agent
1.11 Direct Assignment Facilities
1.12 Eligible Customer
1.13 Facilities Study
1.14 Firm Point-To-Point Transmission
Service
1.15 Good Utility Practice
1.16 Interruption
1.17 Load Ratio Share
1.18 Load Shedding
1.19 Long-Term Firm Point-To-Point
Transmission Service
1.20 Native Load Customers
1.21 Network Customer
1.22 Network Integration Transmission
Service
1.23 Network Load
1.24 Network Operating Agreement
1.25 Network Operating Committee
1.26 Network Resource
1.27 Network Upgrades
1.28 Non-Firm Point-To-Point
Transmission Service
1.29 Non-Firm Sale
1.30 Open Access Same-Time
Information System (OASIS)
1.31 Part I
1.32 Part II
1.33 Part III
1.34 Parties
1.35 Point(s) of Delivery
1.36 Point(s) of Receipt
1008 A ‘‘*’’ indicates that the composition of this
group has altered in the reply comment filing.
1009 A ‘‘*’’ indicates that this party submitted
speaker materials at the October 12 Technical
Conference.
1010 A ‘‘*’’ indicates that the composition of this
group has altered in this filing.
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1.37 Point-To-Point Transmission Service
1.38 Power Purchaser
1.39 Pre-Confirmed Application
1.40 Receiving Party
1.41 Regional Transmission Group (RTG)
1.42 Reserved Capacity
1.43 Service Agreement
1.44 Service Commencement Date
1.45 Short-Term Firm Point-To-Point
Transmission Service
1.46 System Condition
1.47 System Impact Study
1.48 Third-Party Sale
1.49 Transmission Customer
1.50 Transmission Provider
1.51 Transmission Provider’s Monthly
Transmission System Peak
1.52 Transmission Service
1.53 Transmission System
2 Initial Allocation and Renewal
Procedures
2.1 Initial Allocation of Available
Transfer Capability
2.2 Reservation Priority for Existing Firm
Service Customers
3 Ancillary Services
3.1 Scheduling, System Control and
Dispatch Service
3.2 Reactive Supply and Voltage Control
From Generation or Other Sources
Service
3.3 Regulation and Frequency Response
Service
3.4 Energy Imbalance Service
3.5 Operating Reserve—Spinning Reserve
Service
3.6 Operating Reserve—Supplemental
Reserve Service
3.7 Generator Imbalance Service
4 Open Access Same-Time Information
System (OASIS)
5 Local Furnishing Bonds
5.1 Transmission Providers That Own
Facilities Financed by Local Furnishing
Bonds
5.2 Alternative Procedures for Requesting
Transmission Service
6 Reciprocity
7 Billing and Payment
7.1 Billing Procedure:
7.2 Interest on Unpaid Balances
7.3 Customer Default
8 Accounting for the Transmission
Provider’s Use of the Tariff
8.1 Transmission Revenues
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8.2 Study Costs and Revenues
9 Regulatory Filings
10 Force Majeure and Indemnification
10.1 Force Majeure
10.2 Indemnification
11 Creditworthiness
12 Dispute Resolution Procedures
12.1 Internal Dispute Resolution
Procedures
12.2 External Arbitration Procedures
12.3 Arbitration Decisions
12.4 Costs
12.5 Rights Under the Federal Power Act
II. Point-to-Point Transmission Service
13 Nature of Firm Point-to-Point
Transmission Service
13.1 Term
13.2 Reservation Priority
13.3 Use of Firm Transmission Service by
the Transmission Provider
13.4 Service Agreements
13.5 Transmission Customer Obligations
for Facility Additions or Redispatch
Costs
13.6 Curtailment of Firm Transmission
Service
13.7 Classification of Firm Transmission
Service
13.8 Scheduling of Firm Point-To-Point
Transmission Service
14 Nature of Non-Firm Point-to-Point
Transmission Service
14.1 Term
14.2 Reservation Priority
14.3 Use of Non-Firm Point-To-Point
Transmission Service by the
Transmission Provider
14.4 Service Agreements
14.5 Classification of Non-Firm Point-ToPoint Transmission Service
14.6 Scheduling of Non-Firm Point-ToPoint Transmission Service
14.7 Curtailment or Interruption of
Service
15 Service Availability
15.1 General Conditions
15.2 Determination of Available Transfer
Capability
15.3 Initiating Service in the Absence of
an Executed Service Agreement
15.4 Obligation to Provide Transmission
Service that Requires Expansion or
Modification of the Transmission
System, Redispatch or Conditional
Curtailment
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15.5 Deferral of Service
15.6 Other Transmission Service
Schedules
15.7 Real Power Losses
16 Transmission Customer
Responsibilities
16.1 Conditions Required of
Transmission Customers
16.2 Transmission Customer
Responsibility for Third-Party
Arrangements
17 Procedures For Arranging Firm Pointto-Point Transmission Service
17.1 Application
17.2 Completed Application
17.3 Deposit
17.4 Notice of Deficient Application
17.5 Response to a Completed
Application
17.6 Execution of Service Agreement
17.7 Extensions for Commencement of
Service
18 Procedures for Arranging Non-Firm
Point-to-Point Transmission Service
18.1 Application
18.2 Completed Application
18.3 Reservation of Non-Firm Point-toPoint Transmission Service
18.4 Determination of Available Transfer
Capability
19 Additional Study Procedures For Firm
Point-to-Point Transmission Service
Requests
19.1 Notice of Need for System Impact
Study
19.2 System Impact Study Agreement and
Cost Reimbursement
19.3 System Impact Study Procedures
19.4 Facilities Study Procedures
19.5 Facilities Study Modifications
19.6 Due Diligence in Completing New
Facilities
19.7 Partial Interim Service
19.8 Expedited Procedures for New
Facilities
19.9 Penalties for Failure to Meet Study
Deadlines
20 Procedures if the Transmission
Provider is Unable to Complete New
Transmission Facilities for Firm Pointto-Point Transmission Service
20.1 Delays in Construction of New
Facilities:
20.2 Alternatives to the Original Facility
Additions
20.3 Refund Obligation for Unfinished
Facility Additions
21 Provisions Relating to Transmission
Construction and Services on the
Systems of Other Utilities
21.1 Responsibility for Third-Party
System Additions
21.2 Coordination of Third-Party System
Additions
22 Changes in Service Specifications
22.1 Modifications On a Non-Firm Basis
22.2 Modification On a Firm Basis
23 Sale or Assignment of Transmission
Service
23.1 Procedures for Assignment or
Transfer of Service
23.2 Limitations on Assignment or
Transfer of Service
23.3 Information on Assignment or
Transfer of Service
24 Metering and Power Factor Correction
at Receipt and Delivery Points(s)
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24.1 Transmission Customer Obligations
24.2 Transmission Provider Access to
Metering Data
24.3 Power Factor
25 Compensation for Transmission
Service
26 Stranded Cost Recovery
27 Compensation for New Facilities and
Redispatch Costs
III. Network Integration Transmission Service
28 Nature of Network Integration
Transmission Service
28.1 Scope of Service
28.2 Transmission Provider
Responsibilities
28.3 Network Integration Transmission
Service
28.4 Secondary Service
28.5 Real Power Losses
28.6 Restrictions on Use of Service
29 Initiating Service
29.1 Condition Precedent for Receiving
Service
29.2 Application Procedures
29.3 Technical Arrangements to be
Completed Prior to Commencement of
Service
29.4 Network Customer Facilities
29.5 Filing of Service Agreement
30 Network Resources
30.1 Designation of Network Resources
30.2 Designation of New Network
Resources
30.3 Termination of Network Resources
30.4 Operation of Network Resources
30.5 Network Customer Redispatch
Obligation
30.6 Transmission Arrangements for
Network Resources Not Physically
Interconnected With the Transmission
Provider
30.7 Limitation on Designation of
Network Resources
30.8 Use of Interface Capacity by the
Network Customer
30.9 Network Customer Owned
Transmission Facilities
31 Designation of Network Load
31.1 Network Load
31.2 New Network Loads Connected With
the Transmission Provider
31.3 Network Load Not Physically
Interconnected With the Transmission
Provider
31.4 New Interconnection Points
31.5 Changes in Service Requests
31.6 Annual Load and Resource
Information Updates
32 Additional Study Procedures for
Network Integration Transmission
Service Requests
32.1 Notice of Need for System Impact
Study
32.2 System Impact Study Agreement and
Cost Reimbursement
32.3 System Impact Study Procedures
32.4 Facilities Study Procedures
32.5 Penalties for Failure to Meet Study
Deadlines
33 Load Shedding and Curtailments
33.1 Procedures
33.2 Transmission Constraints
33.3 Cost Responsibility for Relieving
Transmission Constraints
33.4 Curtailments of Scheduled
Deliveries
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33.5 Allocation of Curtailments
33.6 Load Shedding
33.7 System Reliability
34 Rates and Charges
34.1 Monthly Demand Charge
34.2 Determination of Network
Customer’s Monthly Network Load
34.3 Determination of Transmission
Provider’s Monthly Transmission System
Load
34.4 Redispatch Charge
34.5 Stranded Cost Recovery
35 Operating Arrangements
35.1 Operation Under The Network
Operating Agreement
35.2 Network Operating Agreement
35.3 Network Operating Committee
Schedule 1
Scheduling, System Control and Dispatch
Service
Schedule 2
Reactive Supply and Voltage Control From
Generation Sources Service
Schedule 3
Regulation and Frequency Response
Service
Schedule 4
Energy Imbalance Service
Schedule 5
Operating Reserve—Spinning Reserve
Service
Schedule 6
Operating Reserve—Supplemental Reserve
Service
Schedule 7
Long-Term Firm and Short-Term Firm
Point-to-Point
Schedule 8
Non-Firm Point-to-Point Transmission
Service
Schedule 9
Generator Imbalance Service
Attachment A
Form of Service Agreement for Firm Pointto-Point Transmission Service
Attachment A–1
Form of Service Agreement for the Resale,
Reassignment or Transfer of Long-Term
Firm Point-to-Point Transmission
Service
Attachment B
Form of Service Agreement for Non-Firm
Point-to-Point Transmission Service
Attachment C
Methodology to Assess Available Transfer
Capability
Attachment D
Methodology for Completing a System
Impact Study
Attachment E
Index of Point-to-Point Transmission
Service Customers
Attachment F
Service Agreement for Network Integration
Transmission Service
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Attachment G
Network Operating Agreement
Attachment H
Annual Transmission Revenue
Requirement for Network Integration
Transmission Service
Attachment I
Index of Network Integration Transmission
Service Customers
Attachment J
Procedures for Addressing Parallel Flows
Attachment K
Transmission Planning Process
Attachment L
Creditworthiness Procedures
I. Common Service Provisions
1. Match, at all times, the power
output of the generators within the
electric power system(s) and capacity
and energy purchased from entities
outside the electric power system(s),
with the load within the electric power
system(s);
2. Maintain scheduled interchange
with other Control Areas, within the
limits of Good Utility Practice;
3. Maintain the frequency of the
electric power system(s) within
reasonable limits in accordance with
Good Utility Practice; and
4. Provide sufficient generating
capacity to maintain operating reserves
in accordance with Good Utility
Practice.
1
1.8
Definitions
Curtailment
1.1 Affiliate
With respect to a corporation,
partnership or other entity, each such
other corporation, partnership or other
entity that directly or indirectly,
through one or more intermediaries,
controls, is controlled by, or is under
common control with, such corporation,
partnership or other entity.
A reduction in firm or non-firm
transmission service in response to a
transfer capability shortage as a result of
system reliability conditions.
1.2 Ancillary Services
Those services that are necessary to
support the transmission of capacity
and energy from resources to loads
while maintaining reliable operation of
the Transmission Provider’s
Transmission System in accordance
with Good Utility Practice.
1.10
1.3 Annual Transmission Costs
The total annual cost of the
Transmission System for purposes of
Network Integration Transmission
Service shall be the amount specified in
Attachment H until amended by the
Transmission Provider or modified by
the Commission.
1.4 Application
A request by an Eligible Customer for
transmission service pursuant to the
provisions of the Tariff.
Facilities or portions of facilities that
are constructed by the Transmission
Provider for the sole use/benefit of a
particular Transmission Customer
requesting service under the Tariff.
Direct Assignment Facilities shall be
specified in the Service Agreement that
governs service to the Transmission
Customer and shall be subject to
Commission approval.
1.12
1.5 Commission
The Federal Energy Regulatory
Commission.
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1.6 Completed Application
An Application that satisfies all of the
information and other requirements of
the Tariff, including any required
deposit.
1.7 Control Area
An electric power system or
combination of electric power systems
to which a common automatic
generation control scheme is applied in
order to:
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1.9
Delivering Party
The entity supplying capacity and
energy to be transmitted at Point(s) of
Receipt.
Designated Agent
Any entity that performs actions or
functions on behalf of the Transmission
Provider, an Eligible Customer, or the
Transmission Customer required under
the Tariff.
1.11
Direct Assignment Facilities
Eligible Customer
i. Any electric utility (including the
Transmission Provider and any power
marketer), Federal power marketing
agency, or any person generating
electric energy for sale for resale is an
Eligible Customer under the Tariff.
Electric energy sold or produced by
such entity may be electric energy
produced in the United States, Canada
or Mexico. However, with respect to
transmission service that the
Commission is prohibited from ordering
by Section 212(h) of the Federal Power
Act, such entity is eligible only if the
service is provided pursuant to a state
requirement that the Transmission
Provider offer the unbundled
transmission service, or pursuant to a
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voluntary offer of such service by the
Transmission Provider.
ii. Any retail customer taking
unbundled transmission service
pursuant to a state requirement that the
Transmission Provider offer the
transmission service, or pursuant to a
voluntary offer of such service by the
Transmission Provider, is an Eligible
Customer under the Tariff.
1.13
Facilities Study
An engineering study conducted by
the Transmission Provider to determine
the required modifications to the
Transmission Provider’s Transmission
System, including the cost and
scheduled completion date for such
modifications, that will be required to
provide the requested transmission
service.
1.14 Firm Point-To-Point
Transmission Service
Transmission Service under this
Tariff that is reserved and/or scheduled
between specified Points of Receipt and
Delivery pursuant to Part II of this
Tariff.
1.15
Good Utility Practice
Any of the practices, methods and
acts engaged in or approved by a
significant portion of the electric utility
industry during the relevant time
period, or any of the practices, methods
and acts which, in the exercise of
reasonable judgment in light of the facts
known at the time the decision was
made, could have been expected to
accomplish the desired result at a
reasonable cost consistent with good
business practices, reliability, safety and
expedition. Good Utility Practice is not
intended to be limited to the optimum
practice, method, or act to the exclusion
of all others, but rather to be acceptable
practices, methods, or acts generally
accepted in the region, including those
practices required by Federal Power Act
section 215(a)(4).
1.16
Interruption
A reduction in non-firm transmission
service due to economic reasons
pursuant to Section 14.7.
1.17
Load Ratio Share
Ratio of a Transmission Customer’s
Network Load to the Transmission
Provider’s total load computed in
accordance with Sections 34.2 and 34.3
of the Network Integration Transmission
Service under Part III of the Tariff and
calculated on a rolling twelve month
basis.
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1.18 Load Shedding
The systematic reduction of system
demand by temporarily decreasing load
in response to transmission system or
area capacity shortages, system
instability, or voltage control
considerations under Part III of the
Tariff.
1.19 Long-Term Firm Point-To-Point
Transmission Service
Firm Point-To-Point Transmission
Service under Part II of the Tariff with
a term of one year or more.
1.20 Native Load Customers
The wholesale and retail power
customers of the Transmission Provider
on whose behalf the Transmission
Provider, by statute, franchise,
regulatory requirement, or contract, has
undertaken an obligation to construct
and operate the Transmission Provider’s
system to meet the reliable electric
needs of such customers.
1.21 Network Customer
An entity receiving transmission
service pursuant to the terms of the
Transmission Provider’s Network
Integration Transmission Service under
Part III of the Tariff.
1.22 Network Integration Transmission
Service
The transmission service provided
under Part III of the Tariff.
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1.23 Network Load
The load that a Network Customer
designates for Network Integration
Transmission Service under Part III of
the Tariff. The Network Customer’s
Network Load shall include all load
served by the output of any Network
Resources designated by the Network
Customer. A Network Customer may
elect to designate less than its total load
as Network Load but may not designate
only part of the load at a discrete Point
of Delivery. Where a Eligible Customer
has elected not to designate a particular
load at discrete points of delivery as
Network Load, the Eligible Customer is
responsible for making separate
arrangements under Part II of the Tariff
for any Point-To-Point Transmission
Service that may be necessary for such
non-designated load.
1.24 Network Operating Agreement
An executed agreement that contains
the terms and conditions under which
the Network Customer shall operate its
facilities and the technical and
operational matters associated with the
implementation of Network Integration
Transmission Service under Part III of
the Tariff.
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1.25
Network Operating Committee
A group made up of representatives
from the Network Customer(s) and the
Transmission Provider established to
coordinate operating criteria and other
technical considerations required for
implementation of Network Integration
Transmission Service under Part III of
this Tariff.
1.26
Network Resource
Any designated generating resource
owned, purchased or leased by a
Network Customer under the Network
Integration Transmission Service Tariff.
Network Resources do not include any
resource, or any portion thereof, that is
committed for sale to third parties or
otherwise cannot be called upon to meet
the Network Customer’s Network Load
on a non-interruptible basis.
1.27
Network Upgrades
Modifications or additions to
transmission-related facilities that are
integrated with and support the
Transmission Provider’s overall
Transmission System for the general
benefit of all users of such Transmission
System.
1.28 Non-Firm Point-To-Point
Transmission Service
Point-To-Point Transmission Service
under the Tariff that is reserved and
scheduled on an as-available basis and
is subject to Curtailment or Interruption
as set forth in Section 14.7 under Part
II of this Tariff. Non-Firm Point-ToPoint Transmission Service is available
on a stand-alone basis for periods
ranging from one hour to one month.
1.29
Non-Firm Sale
Provisions of Part I and appropriate
Schedules and Attachments.
1.33 Part III
Tariff Sections 28 through 35
pertaining to Network Integration
Transmission Service in conjunction
with the applicable Common Service
Provisions of Part I and appropriate
Schedules and Attachments.
1.34 Parties
The Transmission Provider and the
Transmission Customer receiving
service under the Tariff.
1.35 Point(s) of Delivery
Point(s) on the Transmission
Provider’s Transmission System where
capacity and energy transmitted by the
Transmission Provider will be made
available to the Receiving Party under
Part II of the Tariff. The Point(s) of
Delivery shall be specified in the
Service Agreement for Long-Term Firm
Point-To-Point Transmission Service.
1.36 Point(s) of Receipt
Point(s) of interconnection on the
Transmission Provider’s Transmission
System where capacity and energy will
be made available to the Transmission
Provider by the Delivering Party under
Part II of the Tariff. The Point(s) of
Receipt shall be specified in the Service
Agreement for Long-Term Firm PointTo-Point Transmission Service.
1.37 Point-To-Point Transmission
Service
The reservation and transmission of
capacity and energy on either a firm or
non-firm basis from the Point(s) of
Receipt to the Point(s) of Delivery under
Part II of the Tariff.
An energy sale for which receipt or
delivery may be interrupted for any
reason or no reason, without liability on
the part of either the buyer or seller.
1.38 Power Purchaser
The entity that is purchasing the
capacity and energy to be transmitted
under the Tariff.
1.30 Open Access Same-Time
Information System (OASIS)
1.39 Pre-Confirmed Application
An Application that commits the
Transmission Customer to execute a
Service Agreement upon receipt of
notification that the Transmission
Provider can provide the requested
Transmission Service.
The information system and standards
of conduct contained in Part 37 of the
Commission’s regulations and all
additional requirements implemented
by subsequent Commission orders
dealing with OASIS.
1.31
Part I
Tariff Definitions and Common
Service Provisions contained in
Sections 2 through 12.
1.32
Part II
Tariff Sections 13 through 27
pertaining to Point-To-Point
Transmission Service in conjunction
with the applicable Common Service
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1.40 Receiving Party
The entity receiving the capacity and
energy transmitted by the Transmission
Provider to Point(s) of Delivery.
1.41 Regional Transmission Group
(RTG)
A voluntary organization of
transmission owners, transmission users
and other entities approved by the
Commission to efficiently coordinate
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transmission planning (and expansion),
operation and use on a regional (and
interregional) basis.
1.42 Reserved Capacity
The maximum amount of capacity
and energy that the Transmission
Provider agrees to transmit for the
Transmission Customer over the
Transmission Provider’s Transmission
System between the Point(s) of Receipt
and the Point(s) of Delivery under Part
II of the Tariff. Reserved Capacity shall
be expressed in terms of whole
megawatts on a sixty (60) minute
interval (commencing on the clock
hour) basis.
1.43 Service Agreement
The initial agreement and any
amendments or supplements thereto
entered into by the Transmission
Customer and the Transmission
Provider for service under the Tariff.
1.49
Transmission Customer
Any Eligible Customer (or its
Designated Agent) that (i) executes a
Service Agreement, or (ii) requests in
writing that the Transmission Provider
file with the Commission, a proposed
unexecuted Service Agreement to
receive transmission service under Part
II of the Tariff. This term is used in the
Part I Common Service Provisions to
include customers receiving
transmission service under Part II and
Part III of this Tariff.
1.50
Transmission Provider
The public utility (or its Designated
Agent) that owns, controls, or operates
facilities used for the transmission of
electric energy in interstate commerce
and provides transmission service under
the Tariff.
1.51 Transmission Provider’s Monthly
Transmission System Peak
1.44 Service Commencement Date
The date the Transmission Provider
begins to provide service pursuant to
the terms of an executed Service
Agreement, or the date the Transmission
Provider begins to provide service in
accordance with Section 15.3 or Section
29.1 under the Tariff.
The maximum firm usage of the
Transmission Provider’s Transmission
System in a calendar month.
1.45 Short-Term Firm Point-To-Point
Transmission Service
Firm Point-To-Point Transmission
Service under Part II of the Tariff with
a term of less than one year.
1.53
1.46 System Condition
A specified condition on the
Transmission Provider’s system or on a
neighboring system, such as a
constrained transmission element or
flowgate, that may trigger Curtailment of
Long-Term Firm Point-to-Point
Transmission Service using the
curtailment priority pursuant to Section
13.6. Such conditions must be identified
in the Transmission Customer’s Service
Agreement.
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1.47 System Impact Study
An assessment by the Transmission
Provider of (i) the adequacy of the
Transmission System to accommodate a
request for either Firm Point-To-Point
Transmission Service or Network
Integration Transmission Service and
(ii) whether any additional costs may be
incurred in order to provide
transmission service.
1.48 Third-Party Sale
Any sale for resale in interstate
commerce to a Power Purchaser that is
not designated as part of Network Load
under the Network Integration
Transmission Service.
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1.52
Transmission Service
Point-To-Point Transmission Service
provided under Part II of the Tariff on
a firm and non-firm basis.
Transmission System
The facilities owned, controlled or
operated by the Transmission Provider
that are used to provide transmission
service under Part II and Part III of the
Tariff.
2 Initial Allocation and Renewal
Procedures
2.1 Initial Allocation of Available
Transfer Capability
For purposes of determining whether
existing capability on the Transmission
Provider’s Transmission System is
adequate to accommodate a request for
firm service under this Tariff, all
Completed Applications for new firm
transmission service received during the
initial sixty (60) day period
commencing with the effective date of
the Tariff will be deemed to have been
filed simultaneously. A lottery system
conducted by an independent party
shall be used to assign priorities for
Completed Applications filed
simultaneously. All Completed
Applications for firm transmission
service received after the initial sixty
(60) day period shall be assigned a
priority pursuant to Section 13.2.
2.2 Reservation Priority For Existing
Firm Service Customers
Existing firm service customers
(wholesale requirements and
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12507
transmission-only, with a contract term
of five years or more), have the right to
continue to take transmission service
from the Transmission Provider when
the contract expires, rolls over or is
renewed. This transmission reservation
priority is independent of whether the
existing customer continues to purchase
capacity and energy from the
Transmission Provider or elects to
purchase capacity and energy from
another supplier. If at the end of the
contract term, the Transmission
Provider’s Transmission System cannot
accommodate all of the requests for
transmission service, the existing firm
service customer must agree to accept a
contract term at least equal to the longer
of a competing request by any new
Eligible Customer or five years and to
pay the current just and reasonable rate,
as approved by the Commission, for
such service. The existing firm service
customer must provide notice to the
Transmission Provider whether it will
exercise its right of first refusal no less
than one year prior to the expiration
date of its transmission service
agreement. This transmission
reservation priority for existing firm
service customers is an ongoing right
that may be exercised at the end of all
firm contract terms of five years or
longer. Service agreements subject to a
right of first refusal entered into prior to
[the acceptance by the Commission of
the Transmission Provider’s Attachment
K], unless terminated, will become
subject to the five year/one year
requirement on the first rollover date
after [the acceptance by the Commission
of the Transmission Provider’s
Attachment K].
3
Ancillary Services
Ancillary Services are needed with
transmission service to maintain
reliability within and among the Control
Areas affected by the transmission
service. The Transmission Provider is
required to provide (or offer to arrange
with the local Control Area operator as
discussed below), and the Transmission
Customer is required to purchase, the
following Ancillary Services (i)
Scheduling, System Control and
Dispatch, and (ii) Reactive Supply and
Voltage Control from Generation or
Other Sources.
The Transmission Provider is
required to offer to provide (or offer to
arrange with the local Control Area
operator as discussed below) the
following Ancillary Services only to the
Transmission Customer serving load
within the Transmission Provider’s
Control Area (i) Regulation and
Frequency Response, (ii) Energy
Imbalance, (iii) Operating Reserve—
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Spinning, (iv) Operating Reserve—
Supplemental, and (v) Generator
Imbalance. The Transmission Customer
serving load within the Transmission
Provider’s Control Area is required to
acquire these Ancillary Services,
whether from the Transmission
Provider, from a third party, or by selfsupply. The Transmission Customer
may not decline the Transmission
Provider’s offer of Ancillary Services
unless it demonstrates that it has
acquired the Ancillary Services from
another source. The Transmission
Customer must list in its Application
which Ancillary Services it will
purchase from the Transmission
Provider. A Transmission Customer that
exceeds its firm reserved capacity at any
Point of Receipt or Point of Delivery or
an Eligible Customer that uses
Transmission Service at a Point of
Receipt or Point of Delivery that it has
not reserved is required to pay for all of
the Ancillary Services identified in this
section that were provided by the
Transmission Provider associated with
the unreserved service. The
Transmission Customer or Eligible
Customer will pay for Ancillary
Services based on the amount of
transmission service it used but did not
reserve.
If the Transmission Provider is a
public utility providing transmission
service but is not a Control Area
operator, it may be unable to provide
some or all of the Ancillary Services. In
this case, the Transmission Provider can
fulfill its obligation to provide Ancillary
Services by acting as the Transmission
Customer’s agent to secure these
Ancillary Services from the Control
Area operator. The Transmission
Customer may elect to (i) have the
Transmission Provider act as its agent,
(ii) secure the Ancillary Services
directly from the Control Area operator,
or (iii) secure the Ancillary Services
(discussed in Schedules 3, 4, 5, 6 and
9) from a third party or by self-supply
when technically feasible.
The Transmission Provider shall
specify the rate treatment and all related
terms and conditions in the event of an
unauthorized use of Ancillary Services
by the Transmission Customer.
The specific Ancillary Services, prices
and/or compensation methods are
described on the Schedules that are
attached to and made a part of the
Tariff. Three principal requirements
apply to discounts for Ancillary
Services provided by the Transmission
Provider in conjunction with its
provision of transmission service as
follows: (1) Any offer of a discount
made by the Transmission Provider
must be announced to all Eligible
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Customers solely by posting on the
OASIS, (2) any customer-initiated
requests for discounts (including
requests for use by one’s wholesale
merchant or an affiliate’s use) must
occur solely by posting on the OASIS,
and (3) once a discount is negotiated,
details must be immediately posted on
the OASIS. A discount agreed upon for
an Ancillary Service must be offered for
the same period to all Eligible
Customers on the Transmission
Provider’s system. Sections 3.1 through
3.7 below list the seven Ancillary
Services.
3.1 Scheduling, System Control and
Dispatch Service
The rates and/or methodology are
described in Schedule 1.
3.2 Reactive Supply and Voltage
Control from Generation or Other
Sources Service
The rates and/or methodology are
described in Schedule 2.
3.3 Regulation and Frequency
Response Service
Where applicable the rates and/or
methodology are described in Schedule
3.
3.4
Energy Imbalance Service
Where applicable the rates and/or
methodology are described in Schedule
4.
3.5 Operating Reserve—Spinning
Reserve Service
Where applicable the rates and/or
methodology are described in Schedule
5.
3.6 Operating Reserve—Supplemental
Reserve Service
Where applicable the rates and/or
methodology are described in Schedule
6.
3.7
Generator Imbalance Service
Where applicable the rates and/or
methodology are described in Schedule
9.
4 Open Access Same-Time
Information System (OASIS)
Terms and conditions regarding Open
Access Same-Time Information System
and standards of conduct are set forth in
18 CFR part 37 of the Commission’s
regulations (Open Access Same-Time
Information System and Standards of
Conduct for Public Utilities) and 18 CFR
part 38 of the Commission’s regulations
(Business Practice Standards and
Communication Protocols for Public
Utilities). In the event available transfer
capability as posted on the OASIS is
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insufficient to accommodate a request
for firm transmission service, additional
studies may be required as provided by
this Tariff pursuant to Sections 19 and
32.
The Transmission Provider shall post
on its public Web site all rules,
standards and practices that (i) relate to
the terms and conditions of
transmission service, (ii) are not subject
to a North American Energy Standards
Board (NAESB) copyright restriction,
and (iii) are not otherwise included in
this Tariff. The Transmission Provider
shall post on OASIS an electronic link
to these rules, standards and practices,
and shall post on its public Web site an
electronic link to the NAESB Web site
where any rules, standards and
practices that are protected by copyright
may be obtained. The Transmission
Provider shall also make available on its
public Web site a statement of the
process by which the Transmission
Provider shall add, delete or otherwise
modify the rules, standards and
practices that are posted on its website.
Such process shall set forth the means
by which the Transmission Provider
shall provide reasonable advance notice
to Transmission Customers and Eligible
Customers of any such additions,
deletions or modifications, the
associated effective date, and any
additional implementation procedures
that the Transmission Provider deems
appropriate.
5
Local Furnishing Bonds
5.1 Transmission Providers That Own
Facilities Financed by Local Furnishing
Bonds
This provision is applicable only to
Transmission Providers that have
financed facilities for the local
furnishing of electric energy with taxexempt bonds, as described in Section
142(f) of the Internal Revenue Code
(‘‘local furnishing bonds’’).
Notwithstanding any other provision of
this Tariff, the Transmission Provider
shall not be required to provide
transmission service to any Eligible
Customer pursuant to this Tariff if the
provision of such transmission service
would jeopardize the tax-exempt status
of any local furnishing bond(s) used to
finance the Transmission Provider’s
facilities that would be used in
providing such transmission service.
5.2 Alternative Procedures for
Requesting Transmission Service
(i) If the Transmission Provider
determines that the provision of
transmission service requested by an
Eligible Customer would jeopardize the
tax-exempt status of any local
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furnishing bond(s) used to finance its
facilities that would be used in
providing such transmission service, it
shall advise the Eligible Customer
within thirty (30) days of receipt of the
Completed Application.
(ii) If the Eligible Customer thereafter
renews its request for the same
transmission service referred to in (i) by
tendering an application under Section
211 of the Federal Power Act, the
Transmission Provider, within ten (10)
days of receiving a copy of the Section
211 application, will waive its rights to
a request for service under Section
213(a) of the Federal Power Act and to
the issuance of a proposed order under
Section 212(c) of the Federal Power Act.
The Commission, upon receipt of the
Transmission Provider’s waiver of its
rights to a request for service under
Section 213(a) of the Federal Power Act
and to the issuance of a proposed order
under Section 212(c) of the Federal
Power Act, shall issue an order under
Section 211 of the Federal Power Act.
Upon issuance of the order under
Section 211 of the Federal Power Act,
the Transmission Provider shall be
required to provide the requested
transmission service in accordance with
the terms and conditions of this Tariff.
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6
Reciprocity
A Transmission Customer receiving
transmission service under this Tariff
agrees to provide comparable
transmission service that it is capable of
providing to the Transmission Provider
on similar terms and conditions over
facilities used for the transmission of
electric energy owned, controlled or
operated by the Transmission Customer
and over facilities used for the
transmission of electric energy owned,
controlled or operated by the
Transmission Customer’s corporate
affiliates. A Transmission Customer that
is a member of, or takes transmission
service from, a power pool, Regional
Transmission Group, Regional
Transmission Organization (RTO),
Independent System Operator (ISO) or
other transmission organization
approved by the Commission for the
operation of transmission facilities also
agrees to provide comparable
transmission service to the members of
such power pool and Regional
Transmission Group, RTO, ISO or other
transmission organization on similar
terms and conditions over facilities used
for the transmission of electric energy
owned, controlled or operated by the
Transmission Customer and over
facilities used for the transmission of
electric energy owned, controlled or
operated by the Transmission
Customer’s corporate affiliates.
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This reciprocity requirement applies
not only to the Transmission Customer
that obtains transmission service under
the Tariff, but also to all parties to a
transaction that involves the use of
transmission service under the Tariff,
including the power seller, buyer and
any intermediary, such as a power
marketer. This reciprocity requirement
also applies to any Eligible Customer
that owns, controls or operates
transmission facilities that uses an
intermediary, such as a power marketer,
to request transmission service under
the Tariff. If the Transmission Customer
does not own, control or operate
transmission facilities, it must include
in its Application a sworn statement of
one of its duly authorized officers or
other representatives that the purpose of
its Application is not to assist an
Eligible Customer to avoid the
requirements of this provision.
7
7.1
Billing and Payment
Billing Procedure
Within a reasonable time after the first
day of each month, the Transmission
Provider shall submit an invoice to the
Transmission Customer for the charges
for all services furnished under the
Tariff during the preceding month. The
invoice shall be paid by the
Transmission Customer within twenty
(20) days of receipt. All payments shall
be made in immediately available funds
payable to the Transmission Provider, or
by wire transfer to a bank named by the
Transmission Provider.
7.2
Interest on Unpaid Balances
Interest on any unpaid amounts
(including amounts placed in escrow)
shall be calculated in accordance with
the methodology specified for interest
on refunds in the Commission’s
regulations at 18 CFR 35.19a(a)(2)(iii).
Interest on delinquent amounts shall be
calculated from the due date of the bill
to the date of payment. When payments
are made by mail, bills shall be
considered as having been paid on the
date of receipt by the Transmission
Provider.
7.3
Customer Default
In the event the Transmission
Customer fails, for any reason other than
a billing dispute as described below, to
make payment to the Transmission
Provider on or before the due date as
described above, and such failure of
payment is not corrected within thirty
(30) calendar days after the
Transmission Provider notifies the
Transmission Customer to cure such
failure, a default by the Transmission
Customer shall be deemed to exist.
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12509
Upon the occurrence of a default, the
Transmission Provider may initiate a
proceeding with the Commission to
terminate service but shall not terminate
service until the Commission so
approves any such request. In the event
of a billing dispute between the
Transmission Provider and the
Transmission Customer, the
Transmission Provider will continue to
provide service under the Service
Agreement as long as the Transmission
Customer (i) continues to make all
payments not in dispute, and (ii) pays
into an independent escrow account the
portion of the invoice in dispute,
pending resolution of such dispute. If
the Transmission Customer fails to meet
these two requirements for continuation
of service, then the Transmission
Provider may provide notice to the
Transmission Customer of its intention
to suspend service in sixty (60) days, in
accordance with Commission policy.
8 Accounting for the Transmission
Provider’s Use of the Tariff
The Transmission Provider shall
record the following amounts, as
outlined below.
8.1 Transmission Revenues
Include in a separate operating
revenue account or subaccount the
revenues it receives from Transmission
Service when making Third-Party Sales
under Part II of the Tariff.
8.2 Study Costs and Revenues
Include in a separate transmission
operating expense account or
subaccount, costs properly chargeable to
expense that are incurred to perform
any System Impact Studies or Facilities
Studies which the Transmission
Provider conducts to determine if it
must construct new transmission
facilities or upgrades necessary for its
own uses, including making Third-Party
Sales under the Tariff; and include in a
separate operating revenue account or
subaccount the revenues received for
System Impact Studies or Facilities
Studies performed when such amounts
are separately stated and identified in
the Transmission Customer’s billing
under the Tariff.
9
Regulatory Filings
Nothing contained in the Tariff or any
Service Agreement shall be construed as
affecting in any way the right of the
Transmission Provider to unilaterally
make application to the Commission for
a change in rates, terms and conditions,
charges, classification of service, Service
Agreement, rule or regulation under
Section 205 of the Federal Power Act
and pursuant to the Commission’s rules
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and regulations promulgated
thereunder.
Nothing contained in the Tariff or any
Service Agreement shall be construed as
affecting in any way the ability of any
Party receiving service under the Tariff
to exercise its rights under the Federal
Power Act and pursuant to the
Commission’s rules and regulations
promulgated thereunder.
10
Force Majeure and Indemnification
10.1 Force Majeure
An event of Force Majeure means any
act of God, labor disturbance, act of the
public enemy, war, insurrection, riot,
fire, storm or flood, explosion, breakage
or accident to machinery or equipment,
any Curtailment, order, regulation or
restriction imposed by governmental
military or lawfully established civilian
authorities, or any other cause beyond a
Party’s control. A Force Majeure event
does not include an act of negligence or
intentional wrongdoing.
Neither the Transmission Provider
nor the Transmission Customer will be
considered in default as to any
obligation under this Tariff if prevented
from fulfilling the obligation due to an
event of Force Majeure. However, a
Party whose performance under this
Tariff is hindered by an event of Force
Majeure shall make all reasonable
efforts to perform its obligations under
this Tariff.
10.2 Indemnification
The Transmission Customer shall at
all times indemnify, defend, and save
the Transmission Provider harmless
from, any and all damages, losses,
claims, including claims and actions
relating to injury to or death of any
person or damage to property, demands,
suits, recoveries, costs and expenses,
court costs, attorney fees, and all other
obligations by or to third parties, arising
out of or resulting from the
Transmission Provider’s performance of
its obligations under this Tariff on
behalf of the Transmission Customer,
except in cases of negligence or
intentional wrongdoing by the
Transmission Provider.
11 Creditworthiness
The Transmission Provider will
specify its Creditworthiness procedures
in Attachment L.
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12
Dispute Resolution Procedures
12.1 Internal Dispute Resolution
Procedures
Any dispute between a Transmission
Customer and the Transmission
Provider involving transmission service
under the Tariff (excluding applications
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for rate changes or other changes to the
Tariff, or to any Service Agreement
entered into under the Tariff, which
shall be presented directly to the
Commission for resolution) shall be
referred to a designated senior
representative of the Transmission
Provider and a senior representative of
the Transmission Customer for
resolution on an informal basis as
promptly as practicable. In the event the
designated representatives are unable to
resolve the dispute within thirty (30)
days [or such other period as the Parties
may agree upon] by mutual agreement,
such dispute may be submitted to
arbitration and resolved in accordance
with the arbitration procedures set forth
below.
12.2 External Arbitration Procedures
Any arbitration initiated under the
Tariff shall be conducted before a single
neutral arbitrator appointed by the
Parties. If the Parties fail to agree upon
a single arbitrator within ten (10) days
of the referral of the dispute to
arbitration, each Party shall choose one
arbitrator who shall sit on a threemember arbitration panel. The two
arbitrators so chosen shall within
twenty (20) days select a third arbitrator
to chair the arbitration panel. In either
case, the arbitrators shall be
knowledgeable in electric utility
matters, including electric transmission
and bulk power issues, and shall not
have any current or past substantial
business or financial relationships with
any party to the arbitration (except prior
arbitration). The arbitrator(s) shall
provide each of the Parties an
opportunity to be heard and, except as
otherwise provided herein, shall
generally conduct the arbitration in
accordance with the Commercial
Arbitration Rules of the American
Arbitration Association and any
applicable Commission regulations or
Regional Transmission Group rules.
12.3 Arbitration Decisions
Unless otherwise agreed, the
arbitrator(s) shall render a decision
within ninety (90) days of appointment
and shall notify the Parties in writing of
such decision and the reasons therefor.
The arbitrator(s) shall be authorized
only to interpret and apply the
provisions of the Tariff and any Service
Agreement entered into under the Tariff
and shall have no power to modify or
change any of the above in any manner.
The decision of the arbitrator(s) shall be
final and binding upon the Parties, and
judgment on the award may be entered
in any court having jurisdiction. The
decision of the arbitrator(s) may be
appealed solely on the grounds that the
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conduct of the arbitrator(s), or the
decision itself, violated the standards
set forth in the Federal Arbitration Act
and/or the Administrative Dispute
Resolution Act. The final decision of the
arbitrator must also be filed with the
Commission if it affects jurisdictional
rates, terms and conditions of service or
facilities.
12.4
Costs
Each Party shall be responsible for its
own costs incurred during the
arbitration process and for the following
costs, if applicable:
1. The cost of the arbitrator chosen by
the Party to sit on the three member
panel and one half of the cost of the
third arbitrator chosen; or
2. One half the cost of the single
arbitrator jointly chosen by the Parties.
12.5
Act
Rights Under the Federal Power
Nothing in this section shall restrict
the rights of any party to file a
Complaint with the Commission under
relevant provisions of the Federal Power
Act.
II. Point-To-Point Transmission Service
Preamble
The Transmission Provider will
provide Firm and Non-Firm Point-ToPoint Transmission Service pursuant to
the applicable terms and conditions of
this Tariff. Point-To-Point Transmission
Service is for the receipt of capacity and
energy at designated Point(s) of Receipt
and the transfer of such capacity and
energy to designated Point(s) of
Delivery.
13 Nature of Firm Point-To-Point
Transmission Service
13.1
Term
The minimum term of Firm Point-ToPoint Transmission Service shall be one
day and the maximum term shall be
specified in the Service Agreement.
13.2
Reservation Priority
(i) Long-Term Firm Point-To-Point
Transmission Service shall be available
on a first-come, first-served basis, i.e., in
the chronological sequence in which
each Transmission Customer has
requested service.
(ii) Reservations for Short-Term Firm
Point-To-Point Transmission Service
will be conditional based upon the
length of the requested transaction.
However, Pre-Confirmed Applications
for Short-Term Point-to-Point
Transmission Service will receive
priority over earlier-submitted requests
that are not Pre-Confirmed and that
have equal or shorter duration. Among
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requests with the same duration and
pre-confirmation status (Pre-Confirmed
or not confirmed), priority will be given
to an Eligible Customer’s request that
offers the highest price, followed by the
date and time of the request.
(iii) If the Transmission System
becomes oversubscribed, requests for
longer term service may preempt
requests for shorter term service up to
the following deadlines: one day before
the commencement of daily service, one
week before the commencement of
weekly service, and one month before
the commencement of monthly service.
Before the conditional reservation
deadline, if available transfer capability
is insufficient to satisfy all Applications,
an Eligible Customer with a reservation
for shorter term service or equal
duration service and lower price has the
right of first refusal to match any longer
term request or equal duration service
with a higher price before losing its
reservation priority. A longer term
competing request for Short-Term Firm
Point-To-Point Transmission Service
will be granted if the Eligible Customer
with the right of first refusal does not
agree to match the competing request
within 24 hours (or earlier if necessary
to comply with the scheduling
deadlines provided in section 13.8) from
being notified by the Transmission
Provider of a longer-term competing
request for Short-Term Firm Point-ToPoint Transmission Service. When a
longer duration request preempts
multiple shorter duration requests, the
shorter duration requests shall have
simultaneous opportunities to exercise
the right of first refusal. Duration, preconfirmation status, price and time of
response will be used to determine the
order by which the multiple shorter
duration requests will be able to
exercise the right of first refusal. After
the conditional reservation deadline,
service will commence pursuant to the
terms of Part II of the Tariff.
(iv) Firm Point-To-Point Transmission
Service will always have a reservation
priority over Non-Firm Point-To-Point
Transmission Service under the Tariff.
All Long-Term Firm Point-To-Point
Transmission Service will have equal
reservation priority with Native Load
Customers and Network Customers.
Reservation priorities for existing firm
service customers are provided in
Section 2.2.
date sixty (60) days after publication in
Federal Register] or (ii) agreements
executed prior to the aforementioned
date that the Commission requires to be
unbundled, by the date specified by the
Commission. The Transmission
Provider will maintain separate
accounting, pursuant to Section 8, for
any use of the Point-To-Point
Transmission Service to make ThirdParty Sales.
13.3 Use of Firm Transmission Service
by the Transmission Provider
The Transmission Provider will be
subject to the rates, terms and
conditions of Part II of the Tariff when
making Third-Party Sales under (i)
agreements executed on or after [insert
13.5 Transmission Customer
Obligations for Facility Additions or
Redispatch Costs
In cases where the Transmission
Provider determines that the
Transmission System is not capable of
providing Firm Point-To-Point
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13.4 Service Agreements
The Transmission Provider shall offer
a standard form Firm Point-To-Point
Transmission Service Agreement
(Attachment A) to an Eligible Customer
when it submits a Completed
Application for Long-Term Firm PointTo-Point Transmission Service. The
Transmission Provider shall offer a
standard form Firm Point-To-Point
Transmission Service Agreement
(Attachment A) to an Eligible Customer
when it first submits a Completed
Application for Short-Term Firm PointTo-Point Transmission Service pursuant
to the Tariff. Executed Service
Agreements that contain the information
required under the Tariff shall be filed
with the Commission in compliance
with applicable Commission
regulations. An Eligible Customer that
uses Transmission Service at a Point of
Receipt or Point of Delivery that it has
not reserved and that has not executed
a Service Agreement will be deemed, for
purposes of assessing any appropriate
charges and penalties, to have executed
the appropriate Service Agreement. The
Service Agreement shall, when
applicable, specify any conditional
curtailment options selected by the
Transmission Customer. Where the
Service Agreement contains conditional
curtailment options and is subject to a
biennial reassessment as described in
Section 15.4, the Transmission Provider
shall provide the Transmission
Customer notice of any changes to the
curtailment conditions no less than 90
days prior to the date for imposition of
new curtailment conditions. Concurrent
with such notice, the Transmission
Provider shall provide the Transmission
Customer with the reassessment study
and a narrative description of the study,
including the reasons for changes to the
number of hours per year or System
Conditions under which conditional
curtailment may occur.
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12511
Transmission Service without (1)
degrading or impairing the reliability of
service to Native Load Customers,
Network Customers and other
Transmission Customers taking Firm
Point-To-Point Transmission Service, or
(2) interfering with the Transmission
Provider’s ability to meet prior firm
contractual commitments to others, the
Transmission Provider will be obligated
to expand or upgrade its Transmission
System pursuant to the terms of Section
15.4. The Transmission Customer must
agree to compensate the Transmission
Provider for any necessary transmission
facility additions pursuant to the terms
of Section 27. To the extent the
Transmission Provider can relieve any
system constraint by redispatching the
Transmission Provider’s resources, it
shall do so, provided that the Eligible
Customer agrees to compensate the
Transmission Provider pursuant to the
terms of Section 27 and agrees to either
(i) compensate the Transmission
Provider for any necessary transmission
facility additions or (ii) accept the
service subject to a biennial
reassessment by the Transmission
Provider of redispatch requirements as
described in Section 15.4. Any
redispatch, Network Upgrade or Direct
Assignment Facilities costs to be
charged to the Transmission Customer
on an incremental basis under the Tariff
will be specified in the Service
Agreement prior to initiating service.
13.6 Curtailment of Firm Transmission
Service
In the event that a Curtailment on the
Transmission Provider’s Transmission
System, or a portion thereof, is required
to maintain reliable operation of such
system and the system directly and
indirectly interconnected with
Transmission Provider’s Transmission
System, Curtailments will be made on a
non-discriminatory basis to the
transaction(s) that effectively relieve the
constraint. Transmission Provider may
elect to implement such Curtailments
pursuant to the Transmission Loading
Relief procedures specified in
Attachment J. If multiple transactions
require Curtailment, to the extent
practicable and consistent with Good
Utility Practice, the Transmission
Provider will curtail service to Network
Customers and Transmission Customers
taking Firm Point-To-Point
Transmission Service on a basis
comparable to the curtailment of service
to the Transmission Provider’s Native
Load Customers. All Curtailments will
be made on a non-discriminatory basis,
however, Non-Firm Point-To-Point
Transmission Service shall be
subordinate to Firm Transmission
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Service. Long-Term Firm Point-to-Point
Service subject to conditions described
in Section 15.4 shall be curtailed with
secondary service in cases where the
conditions apply, but otherwise will be
curtailed on a pro rata basis with other
Firm Transmission Service. When the
Transmission Provider determines that
an electrical emergency exists on its
Transmission System and implements
emergency procedures to Curtail Firm
Transmission Service, the Transmission
Customer shall make the required
reductions upon request of the
Transmission Provider. However, the
Transmission Provider reserves the right
to Curtail, in whole or in part, any Firm
Transmission Service provided under
the Tariff when, in the Transmission
Provider’s sole discretion, an emergency
or other unforeseen condition impairs or
degrades the reliability of its
Transmission System. The Transmission
Provider will notify all affected
Transmission Customers in a timely
manner of any scheduled Curtailments.
13.7 Classification of Firm
Transmission Service
(a) The Transmission Customer taking
Firm Point-To-Point Transmission
Service may (1) change its Receipt and
Delivery Points to obtain service on a
non-firm basis consistent with the terms
of Section 22.1 or (2) request a
modification of the Points of Receipt or
Delivery on a firm basis pursuant to the
terms of Section 22.2.
(b) The Transmission Customer may
purchase transmission service to make
sales of capacity and energy from
multiple generating units that are on the
Transmission Provider’s Transmission
System. For such a purchase of
transmission service, the resources will
be designated as multiple Points of
Receipt, unless the multiple generating
units are at the same generating plant in
which case the units would be treated
as a single Point of Receipt.
(c) The Transmission Provider shall
provide firm deliveries of capacity and
energy from the Point(s) of Receipt to
the Point(s) of Delivery. Each Point of
Receipt at which firm transmission
capacity is reserved by the Transmission
Customer shall be set forth in the Firm
Point-To-Point Service Agreement for
Long-Term Firm Transmission Service
along with a corresponding capacity
reservation associated with each Point
of Receipt. Points of Receipt and
corresponding capacity reservations
shall be as mutually agreed upon by the
Parties for Short-Term Firm
Transmission. Each Point of Delivery at
which firm transfer capability is
reserved by the Transmission Customer
shall be set forth in the Firm Point-To-
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Point Service Agreement for Long-Term
Firm Transmission Service along with a
corresponding capacity reservation
associated with each Point of Delivery.
Points of Delivery and corresponding
capacity reservations shall be as
mutually agreed upon by the Parties for
Short-Term Firm Transmission. The
greater of either (1) the sum of the
capacity reservations at the Point(s) of
Receipt, or (2) the sum of the capacity
reservations at the Point(s) of Delivery
shall be the Transmission Customer’s
Reserved Capacity. The Transmission
Customer will be billed for its Reserved
Capacity under the terms of Schedule 7.
The Transmission Customer may not
exceed its firm capacity reserved at each
Point of Receipt and each Point of
Delivery except as otherwise specified
in Section 22. The Transmission
Provider shall specify the rate treatment
and all related terms and conditions
applicable in the event that a
Transmission Customer (including
Third-Party Sales by the Transmission
Provider) exceeds its firm reserved
capacity at any Point of Receipt or Point
of Delivery or uses Transmission
Service at a Point of Receipt or Point of
Delivery that it has not reserved.
13.8 Scheduling of Firm Point-ToPoint Transmission Service
Schedules for the Transmission
Customer’s Firm Point-To-Point
Transmission Service must be submitted
to the Transmission Provider no later
than 10 a.m. [or a reasonable time that
is generally accepted in the region and
is consistently adhered to by the
Transmission Provider] of the day prior
to commencement of such service.
Schedules submitted after 10 a.m. will
be accommodated, if practicable. Hourto-hour schedules of any capacity and
energy that is to be delivered must be
stated in increments of 1,000 kW per
hour [or a reasonable increment that is
generally accepted in the region and is
consistently adhered to by the
Transmission Provider]. Transmission
Customers within the Transmission
Provider’s service area with multiple
requests for Transmission Service at a
Point of Receipt, each of which is under
1,000 kW per hour, may consolidate
their service requests at a common point
of receipt into units of 1,000 kW per
hour for scheduling and billing
purposes. Scheduling changes will be
permitted up to twenty (20) minutes [or
a reasonable time that is generally
accepted in the region and is
consistently adhered to by the
Transmission Provider] before the start
of the next clock hour provided that the
Delivering Party and Receiving Party
also agree to the schedule modification.
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The Transmission Provider will furnish
to the Delivering Party’s system
operator, hour-to-hour schedules equal
to those furnished by the Receiving
Party (unless reduced for losses) and
shall deliver the capacity and energy
provided by such schedules. Should the
Transmission Customer, Delivering
Party or Receiving Party revise or
terminate any schedule, such party shall
immediately notify the Transmission
Provider, and the Transmission Provider
shall have the right to adjust
accordingly the schedule for capacity
and energy to be received and to be
delivered.
14 Nature of Non-Firm Point-To-Point
Transmission Service
14.1 Term
Non-Firm Point-To-Point
Transmission Service will be available
for periods ranging from one (1) hour to
one (1) month. However, a Purchaser of
Non-Firm Point-To-Point Transmission
Service will be entitled to reserve a
sequential term of service (such as a
sequential monthly term without having
to wait for the initial term to expire
before requesting another monthly term)
so that the total time period for which
the reservation applies is greater than
one month, subject to the requirements
of Section 18.3.
14.2 Reservation Priority
Non-Firm Point-To-Point
Transmission Service shall be available
from transfer capability in excess of that
needed for reliable service to Native
Load Customers, Network Customers
and other Transmission Customers
taking Long-Term and Short-Term Firm
Point-To-Point Transmission Service. A
higher priority will be assigned first to
reservations with a longer duration of
service and second to Pre-Confirmed
Applications. In the event the
Transmission System is constrained,
competing requests of the same PreConfirmation status and equal duration
will be prioritized based on the highest
price offered by the Eligible Customer
for the Transmission Service. Eligible
Customers that have already reserved
shorter term service have the right of
first refusal to match any longer term
reservation before being preempted. A
longer term competing request for NonFirm Point-To-Point Transmission
Service will be granted if the Eligible
Customer with the right of first refusal
does not agree to match the competing
request: (a) Immediately for hourly NonFirm Point-To-Point Transmission
Service after notification by the
Transmission Provider; and, (b) within
24 hours (or earlier if necessary to
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comply with the scheduling deadlines
provided in section 14.6) for Non-Firm
Point-To-Point Transmission Service
other than hourly transactions after
notification by the Transmission
Provider. Transmission service for
Network Customers from resources
other than designated Network
Resources will have a higher priority
than any Non-Firm Point-To-Point
Transmission Service. Non-Firm PointTo-Point Transmission Service over
secondary Point(s) of Receipt and
Point(s) of Delivery will have the lowest
reservation priority under the Tariff.
14.3 Use of Non-Firm Point-To-Point
Transmission Service by the
Transmission Provider
The Transmission Provider will be
subject to the rates, terms and
conditions of Part II of the Tariff when
making Third-Party Sales under (i)
agreements executed on or after May 14,
2007 or (ii) agreements executed prior to
the aforementioned date that the
Commission requires to be unbundled,
by the date specified by the
Commission. The Transmission
Provider will maintain separate
accounting, pursuant to Section 8, for
any use of Non-Firm Point-To-Point
Transmission Service to make ThirdParty Sales.
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14.4 Service Agreements
The Transmission Provider shall offer
a standard form Non-Firm Point-ToPoint Transmission Service Agreement
(Attachment B) to an Eligible Customer
when it first submits a Completed
Application for Non-Firm Point-ToPoint Transmission Service pursuant to
the Tariff. Executed Service Agreements
that contain the information required
under the Tariff shall be filed with the
Commission in compliance with
applicable Commission regulations.
14.5 Classification of Non-Firm PointTo-Point Transmission Service
Non-Firm Point-To-Point
Transmission Service shall be offered
under terms and conditions contained
in Part II of the Tariff. The Transmission
Provider undertakes no obligation under
the Tariff to plan its Transmission
System in order to have sufficient
capacity for Non-Firm Point-To-Point
Transmission Service. Parties requesting
Non-Firm Point-To-Point Transmission
Service for the transmission of firm
power do so with the full realization
that such service is subject to
availability and to Curtailment or
Interruption under the terms of the
Tariff. The Transmission Provider shall
specify the rate treatment and all related
terms and conditions applicable in the
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event that a Transmission Customer
(including Third-Party Sales by the
Transmission Provider) exceeds its nonfirm capacity reservation. Non-Firm
Point-To-Point Transmission Service
shall include transmission of energy on
an hourly basis and transmission of
scheduled short-term capacity and
energy on a daily, weekly or monthly
basis, but not to exceed one month’s
reservation for any one Application,
under Schedule 8.
14.6 Scheduling of Non-Firm PointTo-Point Transmission Service
Schedules for Non-Firm Point-ToPoint Transmission Service must be
submitted to the Transmission Provider
no later than 2 p.m. [or a reasonable
time that is generally accepted in the
region and is consistently adhered to by
the Transmission Provider] of the day
prior to commencement of such service.
Schedules submitted after 2 p.m. will be
accommodated, if practicable. Hour-tohour schedules of energy that is to be
delivered must be stated in increments
of 1,000 kW per hour [or a reasonable
increment that is generally accepted in
the region and is consistently adhered to
by the Transmission Provider].
Transmission Customers within the
Transmission Provider’s service area
with multiple requests for Transmission
Service at a Point of Receipt, each of
which is under 1,000 kW per hour, may
consolidate their schedules at a
common Point of Receipt into units of
1,000 kW per hour. Scheduling changes
will be permitted up to twenty (20)
minutes [or a reasonable time that is
generally accepted in the region and is
consistently adhered to by the
Transmission Provider] before the start
of the next clock hour provided that the
Delivering Party and Receiving Party
also agree to the schedule modification.
The Transmission Provider will furnish
to the Delivering Party’s system
operator, hour-to-hour schedules equal
to those furnished by the Receiving
Party (unless reduced for losses) and
shall deliver the capacity and energy
provided by such schedules. Should the
Transmission Customer, Delivering
Party or Receiving Party revise or
terminate any schedule, such party shall
immediately notify the Transmission
Provider, and the Transmission Provider
shall have the right to adjust
accordingly the schedule for capacity
and energy to be received and to be
delivered.
14.7 Curtailment or Interruption of
Service
The Transmission Provider reserves
the right to Curtail, in whole or in part,
Non-Firm Point-To-Point Transmission
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12513
Service provided under the Tariff for
reliability reasons when an emergency
or other unforeseen condition threatens
to impair or degrade the reliability of its
Transmission System or the systems
directly and indirectly interconnected
with Transmission Provider’s
Transmission System. Transmission
Provider may elect to implement such
Curtailments pursuant to the
Transmission Loading Relief procedures
specified in Attachment J. The
Transmission Provider reserves the right
to Interrupt, in whole or in part, NonFirm Point-To-Point Transmission
Service provided under the Tariff for
economic reasons in order to
accommodate (1) a request for Firm
Transmission Service, (2) a request for
Non-Firm Point-To-Point Transmission
Service of greater duration, (3) a request
for Non-Firm Point-To-Point
Transmission Service of equal duration
with a higher price, (4) transmission
service for Network Customers from
non-designated resources, or (5)
transmission service for Firm Point-toPoint Transmission Service during
conditional curtailment periods as
described in Section 15.4. The
Transmission Provider also will
discontinue or reduce service to the
Transmission Customer to the extent
that deliveries for transmission are
discontinued or reduced at the Point(s)
of Receipt. Where required,
Curtailments or Interruptions will be
made on a non-discriminatory basis to
the transaction(s) that effectively relieve
the constraint, however, Non-Firm
Point-To-Point Transmission Service
shall be subordinate to Firm
Transmission Service. If multiple
transactions require Curtailment or
Interruption, to the extent practicable
and consistent with Good Utility
Practice, Curtailments or Interruptions
will be made to transactions of the
shortest term (e.g., hourly non-firm
transactions will be Curtailed or
Interrupted before daily non-firm
transactions and daily non-firm
transactions will be Curtailed or
Interrupted before weekly non-firm
transactions). Transmission service for
Network Customers from resources
other than designated Network
Resources will have a higher priority
than any Non-Firm Point-To-Point
Transmission Service under the Tariff.
Non-Firm Point-To-Point Transmission
Service over secondary Point(s) of
Receipt and Point(s) of Delivery will
have a lower priority than any Non-Firm
Point-To-Point Transmission Service
under the Tariff. The Transmission
Provider will provide advance notice of
Curtailment or Interruption where such
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notice can be provided consistent with
Good Utility Practice.
15
Service Availability
15.1 General Conditions
The Transmission Provider will
provide Firm and Non-Firm Point-ToPoint Transmission Service over, on or
across its Transmission System to any
Transmission Customer that has met the
requirements of Section 16.
15.2 Determination of Available
Transfer Capability
A description of the Transmission
Provider’s specific methodology for
assessing available transfer capability
posted on the Transmission Provider’s
OASIS (Section 4) is contained in
Attachment C of the Tariff. In the event
sufficient transfer capability may not
exist to accommodate a service request,
the Transmission Provider will respond
by performing a System Impact Study.
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15.3 Initiating Service in the Absence
of an Executed Service Agreement
If the Transmission Provider and the
Transmission Customer requesting Firm
or Non-Firm Point-To-Point
Transmission Service cannot agree on
all the terms and conditions of the
Point-To-Point Service Agreement, the
Transmission Provider shall file with
the Commission, within thirty (30) days
after the date the Transmission
Customer provides written notification
directing the Transmission Provider to
file, an unexecuted Point-To-Point
Service Agreement containing terms and
conditions deemed appropriate by the
Transmission Provider for such
requested Transmission Service. The
Transmission Provider shall commence
providing Transmission Service subject
to the Transmission Customer agreeing
to (i) compensate the Transmission
Provider at whatever rate the
Commission ultimately determines to be
just and reasonable, and (ii) comply
with the terms and conditions of the
Tariff including posting appropriate
security deposits in accordance with the
terms of Section 17.3.
15.4 Obligation To Provide
Transmission Service That Requires
Expansion or Modification of the
Transmission System, Redispatch or
Conditional Curtailment
(a) If the Transmission Provider
determines that it cannot accommodate
a Completed Application for Firm PointTo-Point Transmission Service because
of insufficient capability on its
Transmission System, the Transmission
Provider will use due diligence to
expand or modify its Transmission
System to provide the requested Firm
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Transmission Service, consistent with
its planning obligations in Attachment
K, provided the Transmission Customer
agrees to compensate the Transmission
Provider for such costs pursuant to the
terms of Section 27. The Transmission
Provider will conform to Good Utility
Practice and its planning obligations in
Attachment K, in determining the need
for new facilities and in the design and
construction of such facilities. The
obligation applies only to those facilities
that the Transmission Provider has the
right to expand or modify.
(b) If the Transmission Provider
determines that it cannot accommodate
a Completed Application for Firm PointTo-Point Transmission Service because
of insufficient capability on its
Transmission System, the Transmission
Provider will use due diligence to
provide redispatch from its own
resources until (i) Network Upgrades are
completed for the Transmission
Customer, (ii) the Transmission
Provider determines through a biennial
reassessment that it can no longer
reliably provide the redispatch, or (iii)
the Transmission Customer terminates
the service because of redispatch
changes resulting from the
reassessment. A Transmission Provider
shall not unreasonably deny selfprovided redispatch or redispatch
arranged by the Transmission Customer
from a third party resource.
(c) If the Transmission Provider
determines that it cannot accommodate
a Completed Application for Firm PointTo-Point Transmission Service because
of insufficient capability on its
Transmission System, the Transmission
Provider will offer the Firm
Transmission Service with the
condition that the Transmission
Provider may curtail the service prior to
the curtailment of other Firm
Transmission Service for a specified
number of hours per year or during
System Condition(s). If the
Transmission Customer accepts the
service, the Transmission Provider will
use due diligence to provide the service
until (i) Network Upgrades are
completed for the Transmission
Customer, (ii) the Transmission
Provider determines through a biennial
reassessment that it can no longer
reliably provide such service, or (iii) the
Transmission Customer terminates the
service because the reassessment
increased the number of hours per year
of conditional curtailment or changed
the System Conditions.
15.5 Deferral of Service
The Transmission Provider may defer
providing service until it completes
construction of new transmission
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facilities or upgrades needed to provide
Firm Point-To-Point Transmission
Service whenever the Transmission
Provider determines that providing the
requested service would, without such
new facilities or upgrades, impair or
degrade reliability to any existing firm
services.
15.6 Other Transmission Service
Schedules
Eligible Customers receiving
transmission service under other
agreements on file with the Commission
may continue to receive transmission
service under those agreements until
such time as those agreements may be
modified by the Commission.
15.7
Real Power Losses
Real Power Losses are associated with
all transmission service. The
Transmission Provider is not obligated
to provide Real Power Losses. The
Transmission Customer is responsible
for replacing losses associated with all
transmission service as calculated by
the Transmission Provider. The
applicable Real Power Loss factors are
as follows: [To be completed by the
Transmission Provider].
16 Transmission Customer
Responsibilities
16.1 Conditions Required of
Transmission Customers
Point-To-Point Transmission Service
shall be provided by the Transmission
Provider only if the following
conditions are satisfied by the
Transmission Customer:
(a) The Transmission Customer has
pending a Completed Application for
service;
(b) The Transmission Customer meets
the creditworthiness criteria set forth in
Section 11;
(c) The Transmission Customer will
have arrangements in place for any
other transmission service necessary to
effect the delivery from the generating
source to the Transmission Provider
prior to the time service under Part II of
the Tariff commences;
(d) The Transmission Customer agrees
to pay for any facilities constructed and
chargeable to such Transmission
Customer under Part II of the Tariff,
whether or not the Transmission
Customer takes service for the full term
of its reservation;
(e) The Transmission Customer
provides the information required by
the Transmission Provider’s planning
process established in Attachment K;
and
(f) The Transmission Customer has
executed a Point-To-Point Service
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Agreement or has agreed to receive
service pursuant to Section 15.3.
16.2 Transmission Customer
Responsibility for Third-Party
Arrangements
Any scheduling arrangements that
may be required by other electric
systems shall be the responsibility of the
Transmission Customer requesting
service. The Transmission Customer
shall provide, unless waived by the
Transmission Provider, notification to
the Transmission Provider identifying
such systems and authorizing them to
schedule the capacity and energy to be
transmitted by the Transmission
Provider pursuant to Part II of the Tariff
on behalf of the Receiving Party at the
Point of Delivery or the Delivering Party
at the Point of Receipt. However, the
Transmission Provider will undertake
reasonable efforts to assist the
Transmission Customer in making such
arrangements, including without
limitation, providing any information or
data required by such other electric
system pursuant to Good Utility
Practice.
17 Procedures for Arranging Firm
Point-To-Point Transmission Service
sroberts on PROD1PC70 with RULES
17.1
Application
A request for Firm Point-To-Point
Transmission Service for periods of one
year or longer must contain a written
Application to: [Transmission Provider
Name and Address], at least sixty (60)
days in advance of the calendar month
in which service is to commence. The
Transmission Provider will consider
requests for such firm service on shorter
notice when feasible. Requests for firm
service for periods of less than one year
shall be subject to expedited procedures
that shall be negotiated between the
Parties within the time constraints
provided in Section 17.5. All Firm
Point-To-Point Transmission Service
requests should be submitted by
entering the information listed below on
the Transmission Provider’s OASIS.
Prior to implementation of the
Transmission Provider’s OASIS, a
Completed Application may be
submitted by (i) transmitting the
required information to the
Transmission Provider by telefax, or (ii)
providing the information by telephone
over the Transmission Provider’s time
recorded telephone line. Each of these
methods will provide a time-stamped
record for establishing the priority of the
Application.
17.2
Completed Application
A Completed Application shall
provide all of the information included
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in 18 CFR 2.20 including but not limited
to the following:
(i) The identity, address, telephone
number and facsimile number of the
entity requesting service;
(ii) A statement that the entity
requesting service is, or will be upon
commencement of service, an Eligible
Customer under the Tariff;
(iii) The location of the Point(s) of
Receipt and Point(s) of Delivery and the
identities of the Delivering Parties and
the Receiving Parties;
(iv) The location of the generating
facility(ies) supplying the capacity and
energy and the location of the load
ultimately served by the capacity and
energy transmitted. The Transmission
Provider will treat this information as
confidential except to the extent that
disclosure of this information is
required by this Tariff, by regulatory or
judicial order, for reliability purposes
pursuant to Good Utility Practice or
pursuant to RTG transmission
information sharing agreements. The
Transmission Provider shall treat this
information consistent with the
standards of conduct contained in Part
37 of the Commission’s regulations;
(v) A description of the supply
characteristics of the capacity and
energy to be delivered;
(vi) An estimate of the capacity and
energy expected to be delivered to the
Receiving Party;
(vii) The Service Commencement Date
and the term of the requested
Transmission Service;
(viii) The transmission capacity
requested for each Point of Receipt and
each Point of Delivery on the
Transmission Provider’s Transmission
System; customers may combine their
requests for service in order to satisfy
the minimum transmission capacity
requirement;
(ix) A statement indicating whether
the Transmission Customer commits to
a Pre-Confirmed Request, i.e., will
execute a Service Agreement upon
receipt of notification that the
Transmission Provider can provide the
requested Transmission Service; and
(x) Any additional information
required by the Transmission Provider’s
planning process established in
Attachment K.
The Transmission Provider shall treat
this information consistent with the
standards of conduct contained in Part
37 of the Commission’s regulations.
17.3 Deposit
A Completed Application for Firm
Point-To-Point Transmission Service
also shall include a deposit of either one
month’s charge for Reserved Capacity or
the full charge for Reserved Capacity for
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12515
service requests of less than one month.
If the Application is rejected by the
Transmission Provider because it does
not meet the conditions for service as
set forth herein, or in the case of
requests for service arising in
connection with losing bidders in a
Request For Proposals (RFP), said
deposit shall be returned with interest
less any reasonable costs incurred by
the Transmission Provider in
connection with the review of the losing
bidder’s Application. The deposit also
will be returned with interest less any
reasonable costs incurred by the
Transmission Provider if the
Transmission Provider is unable to
complete new facilities needed to
provide the service. If an Application is
withdrawn or the Eligible Customer
decides not to enter into a Service
Agreement for Firm Point-To-Point
Transmission Service, the deposit shall
be refunded in full, with interest, less
reasonable costs incurred by the
Transmission Provider to the extent
such costs have not already been
recovered by the Transmission Provider
from the Eligible Customer. The
Transmission Provider will provide to
the Eligible Customer a complete
accounting of all costs deducted from
the refunded deposit, which the Eligible
Customer may contest if there is a
dispute concerning the deducted costs.
Deposits associated with construction of
new facilities are subject to the
provisions of Section 19. If a Service
Agreement for Firm Point-To-Point
Transmission Service is executed, the
deposit, with interest, will be returned
to the Transmission Customer upon
expiration or termination of the Service
Agreement for Firm Point-To-Point
Transmission Service. Applicable
interest shall be computed in
accordance with the Commission’s
regulations at 18 CFR 35.19a(a)(2)(iii),
and shall be calculated from the day the
deposit check is credited to the
Transmission Provider’s account.
17.4 Notice of Deficient Application
If an Application fails to meet the
requirements of the Tariff, the
Transmission Provider shall notify the
entity requesting service within fifteen
(15) days of receipt of the reasons for
such failure. The Transmission Provider
will attempt to remedy minor
deficiencies in the Application through
informal communications with the
Eligible Customer. If such efforts are
unsuccessful, the Transmission Provider
shall return the Application, along with
any deposit, with interest. Upon receipt
of a new or revised Application that
fully complies with the requirements of
Part II of the Tariff, the Eligible
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Customer shall be assigned a new
priority consistent with the date of the
new or revised Application.
17.5 Response to a Completed
Application
Following receipt of a Completed
Application for Firm Point-To-Point
Transmission Service, the Transmission
Provider shall make a determination of
available transfer capability as required
in Section 15.2. The Transmission
Provider shall notify the Eligible
Customer as soon as practicable, but not
later than thirty (30) days after the date
of receipt of a Completed Application
either (i) if it will be able to provide
service without performing a System
Impact Study or (ii) if such a study is
needed to evaluate the impact of the
Application pursuant to Section 19.1.
Responses by the Transmission Provider
must be made as soon as practicable to
all completed applications (including
applications by its own merchant
function) and the timing of such
responses must be made on a nondiscriminatory basis.
sroberts on PROD1PC70 with RULES
17.6 Execution of Service Agreement
Whenever the Transmission Provider
determines that a System Impact Study
is not required and that the service can
be provided, it shall notify the Eligible
Customer as soon as practicable but no
later than thirty (30) days after receipt
of the Completed Application. Where a
System Impact Study is required, the
provisions of Section 19 will govern the
execution of a Service Agreement.
Failure of an Eligible Customer to
execute and return the Service
Agreement or request the filing of an
unexecuted service agreement pursuant
to Section 15.3, within fifteen (15) days
after it is tendered by the Transmission
Provider will be deemed a withdrawal
and termination of the Application and
any deposit submitted shall be refunded
with interest. Nothing herein limits the
right of an Eligible Customer to file
another Application after such
withdrawal and termination.
17.7 Extensions for Commencement of
Service
The Transmission Customer can
obtain up to five (5) one-year extensions
for the commencement of service. The
Transmission Customer may postpone
service by paying a non-refundable
annual reservation fee equal to onemonth’s charge for Firm Transmission
Service for each year or fraction thereof.
If the Eligible Customer does not pay
this non-refundable reservation fee
within 15 days of notifying the
Transmission Provider it intends to
extend the commencement of service,
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Jkt 211001
then the Eligible Customer’s application
shall be deemed withdrawn and its
deposit, pursuant to Section 17.3, shall
be returned with interest. If during any
extension for the commencement of
service an Eligible Customer submits a
Completed Application for Firm
Transmission Service, and such request
can be satisfied only by releasing all or
part of the Transmission Customer’s
Reserved Capacity, the original
Reserved Capacity will be released
unless the following condition is
satisfied. Within thirty (30) days, the
original Transmission Customer agrees
to pay the Firm Point-To-Point
transmission rate for its Reserved
Capacity concurrent with the new
Service Commencement Date. In the
event the Transmission Customer elects
to release the Reserved Capacity, the
reservation fees or portions thereof
previously paid will be forfeited.
18 Procedures for Arranging Non-Firm
Point-To-Point Transmission Service
18.1 Application
Eligible Customers seeking Non-Firm
Point-To-Point Transmission Service
must submit a Completed Application
to the Transmission Provider.
Applications should be submitted by
entering the information listed below on
the Transmission Provider’s OASIS.
Prior to implementation of the
Transmission Provider’s OASIS, a
Completed Application may be
submitted by (i) transmitting the
required information to the
Transmission Provider by telefax, or (ii)
providing the information by telephone
over the Transmission Provider’s time
recorded telephone line. Each of these
methods will provide a time-stamped
record for establishing the service
priority of the Application.
18.2 Completed Application
A Completed Application shall
provide all of the information included
in 18 CFR 2.20 including but not limited
to the following:
(i) The identity, address, telephone
number and facsimile number of the
entity requesting service;
(ii) A statement that the entity
requesting service is, or will be upon
commencement of service, an Eligible
Customer under the Tariff;
(iii) The Point(s) of Receipt and the
Point(s) of Delivery;
(iv) The maximum amount of capacity
requested at each Point of Receipt and
Point of Delivery; and
(v) The proposed dates and hours for
initiating and terminating transmission
service hereunder.
In addition to the information
specified above, when required to
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properly evaluate system conditions, the
Transmission Provider also may ask the
Transmission Customer to provide the
following:
(vi) The electrical location of the
initial source of the power to be
transmitted pursuant to the
Transmission Customer’s request for
service; and
(vii) The electrical location of the
ultimate load.
The Transmission Provider will treat
this information in (vi) and (vii) as
confidential at the request of the
Transmission Customer except to the
extent that disclosure of this
information is required by this Tariff, by
regulatory or judicial order, for
reliability purposes pursuant to Good
Utility Practice, or pursuant to RTG
transmission information sharing
agreements. The Transmission Provider
shall treat this information consistent
with the standards of conduct contained
in Part 37 of the Commission’s
regulations.
(viii) A statement indicating whether
the Transmission Customer commits to
a Pre-Confirmed Request, i.e., will
execute a Service Agreement upon
receipt of notification that the
Transmission Provider can provide the
requested Transmission Service.
18.3 Reservation of Non-Firm Point-toPoint Transmission Service
Requests for monthly service shall be
submitted no earlier than sixty (60) days
before service is to commence; requests
for weekly service shall be submitted no
earlier than fourteen (14) days before
service is to commence, requests for
daily service shall be submitted no
earlier than two (2) days before service
is to commence, and requests for hourly
service shall be submitted no earlier
than noon the day before service is to
commence. Requests for service
received later than 2 p.m. prior to the
day service is scheduled to commence
will be accommodated if practicable [or
such reasonable times that are generally
accepted in the region and are
consistently adhered to by the
Transmission Provider].
18.4 Determination of Available
Transfer Capability
Following receipt of a tendered
schedule the Transmission Provider will
make a determination on a nondiscriminatory basis of available transfer
capability pursuant to Section 15.2.
Such determination shall be made as
soon as reasonably practicable after
receipt, but not later than the following
time periods for the following terms of
service (i) thirty (30) minutes for hourly
service, (ii) thirty (30) minutes for daily
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service, (iii) four (4) hours for weekly
service, and (iv) two (2) days for
monthly service. [Or such reasonable
times that are generally accepted in the
region and are consistently adhered to
by the Transmission Provider].
19 Additional Study Procedures for
Firm Point-to-Point Transmission
Service Requests
sroberts on PROD1PC70 with RULES
19.1 Notice of Need for System Impact
Study
After receiving a request for service,
the Transmission Provider shall
determine on a non-discriminatory basis
whether a System Impact Study is
needed. A description of the
Transmission Provider’s methodology
for completing a System Impact Study is
provided in Attachment D. If the
Transmission Provider determines that a
System Impact Study is necessary to
accommodate the requested service, it
shall so inform the Eligible Customer, as
soon as practicable. Once informed, the
Eligible Customer shall timely notify the
Transmission Provider if it elects not to
have the Transmission Provider study
redispatch or conditional curtailment as
part of the System Impact Study. If
notification is provided prior to tender
of the System Impact Study Agreement,
the Eligible Customer can avoid the
costs associated with the study of these
options. The Transmission Provider
shall within thirty (30) days of receipt
of a Completed Application, tender a
System Impact Study Agreement
pursuant to which the Eligible Customer
shall agree to reimburse the
Transmission Provider for performing
the required System Impact Study. For
a service request to remain a Completed
Application, the Eligible Customer shall
execute the System Impact Study
Agreement and return it to the
Transmission Provider within fifteen
(15) days. If the Eligible Customer elects
not to execute the System Impact Study
Agreement, its application shall be
deemed withdrawn and its deposit,
pursuant to Section 17.3, shall be
returned with interest.
19.2 System Impact Study Agreement
and Cost Reimbursement
(i) The System Impact Study
Agreement will clearly specify the
Transmission Provider’s estimate of the
actual cost, and time for completion of
the System Impact Study. The charge
shall not exceed the actual cost of the
study. In performing the System Impact
Study, the Transmission Provider shall
rely, to the extent reasonably
practicable, on existing transmission
planning studies. The Eligible Customer
will not be assessed a charge for such
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Jkt 211001
existing studies; however, the Eligible
Customer will be responsible for charges
associated with any modifications to
existing planning studies that are
reasonably necessary to evaluate the
impact of the Eligible Customer’s
request for service on the Transmission
System.
(ii) If in response to multiple Eligible
Customers requesting service in relation
to the same competitive solicitation, a
single System Impact Study is sufficient
for the Transmission Provider to
accommodate the requests for service,
the costs of that study shall be pro-rated
among the Eligible Customers.
(iii) For System Impact Studies that
the Transmission Provider conducts on
its own behalf, the Transmission
Provider shall record the cost of the
System Impact Studies pursuant to
Section 20.
19.3 System Impact Study Procedures
Upon receipt of an executed System
Impact Study Agreement, the
Transmission Provider will use due
diligence to complete the required
System Impact Study within a sixty (60)
day period. The System Impact Study
shall identify (1) any system constraints,
identified with specificity by
transmission element or flowgate, (2)
redispatch options (when requested by
a Transmission Customer) including an
estimate of the cost of redispatch, (3)
conditional curtailment options (when
requested by a Transmission Customer)
including the number of hours per year
and the System Conditions during
which conditional curtailment may
occur, and (4) additional Direct
Assignment Facilities or Network
Upgrades required to provide the
requested service. For customers
requesting the study of redispatch
options, the System Impact Study shall
(1) identify all resources located within
the Transmission Provider’s Control
Area that can significantly contribute
toward relieving the system constraint
and (2) provide a measurement of each
resource’s impact on the system
constraint. If the Transmission Provider
possesses information indicating that
any resource outside its Control Area
could relieve the constraint, it shall
identify each such resource in the
System Impact Study. In the event that
the Transmission Provider is unable to
complete the required System Impact
Study within such time period, it shall
so notify the Eligible Customer and
provide an estimated completion date
along with an explanation of the reasons
why additional time is required to
complete the required studies. A copy of
the completed System Impact Study and
related work papers shall be made
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12517
available to the Eligible Customer as
soon as the System Impact Study is
complete. The Transmission Provider
will use the same due diligence in
completing the System Impact Study for
an Eligible Customer as it uses when
completing studies for itself. The
Transmission Provider shall notify the
Eligible Customer immediately upon
completion of the System Impact Study
if the Transmission System will be
adequate to accommodate all or part of
a request for service or that no costs are
likely to be incurred for new
transmission facilities or upgrades. In
order for a request to remain a
Completed Application, within fifteen
(15) days of completion of the System
Impact Study the Eligible Customer
must execute a Service Agreement or
request the filing of an unexecuted
Service Agreement pursuant to Section
15.3, or the Application shall be deemed
terminated and withdrawn.
19.4 Facilities Study Procedures
If a System Impact Study indicates
that additions or upgrades to the
Transmission System are needed to
supply the Eligible Customer’s service
request, the Transmission Provider,
within thirty (30) days of the
completion of the System Impact Study,
shall tender to the Eligible Customer a
Facilities Study Agreement pursuant to
which the Eligible Customer shall agree
to reimburse the Transmission Provider
for performing the required Facilities
Study. For a service request to remain
a Completed Application, the Eligible
Customer shall execute the Facilities
Study Agreement and return it to the
Transmission Provider within fifteen
(15) days. If the Eligible Customer elects
not to execute the Facilities Study
Agreement, its application shall be
deemed withdrawn and its deposit,
pursuant to Section 17.3, shall be
returned with interest. Upon receipt of
an executed Facilities Study Agreement,
the Transmission Provider will use due
diligence to complete the required
Facilities Study within a sixty (60) day
period. If the Transmission Provider is
unable to complete the Facilities Study
in the allotted time period, the
Transmission Provider shall notify the
Transmission Customer and provide an
estimate of the time needed to reach a
final determination along with an
explanation of the reasons that
additional time is required to complete
the study. When completed, the
Facilities Study will include a good
faith estimate of (i) the cost of Direct
Assignment Facilities to be charged to
the Transmission Customer, (ii) the
Transmission Customer’s appropriate
share of the cost of any required
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Network Upgrades as determined
pursuant to the provisions of Part II of
the Tariff, and (iii) the time required to
complete such construction and initiate
the requested service. The Transmission
Customer shall provide the
Transmission Provider with a letter of
credit or other reasonable form of
security acceptable to the Transmission
Provider equivalent to the costs of new
facilities or upgrades consistent with
commercial practices as established by
the Uniform Commercial Code. The
Transmission Customer shall have thirty
(30) days to execute a Service
Agreement or request the filing of an
unexecuted Service Agreement and
provide the required letter of credit or
other form of security or the request will
no longer be a Completed Application
and shall be deemed terminated and
withdrawn.
19.5 Facilities Study Modifications
Any change in design arising from
inability to site or construct facilities as
proposed will require development of a
revised good faith estimate. New good
faith estimates also will be required in
the event of new statutory or regulatory
requirements that are effective before
the completion of construction or other
circumstances beyond the control of the
Transmission Provider that significantly
affect the final cost of new facilities or
upgrades to be charged to the
Transmission Customer pursuant to the
provisions of Part II of the Tariff.
sroberts on PROD1PC70 with RULES
19.6 Due Diligence in Completing New
Facilities
The Transmission Provider shall use
due diligence to add necessary facilities
or upgrade its Transmission System
within a reasonable time. The
Transmission Provider will not upgrade
its existing or planned Transmission
System in order to provide the
requested Firm Point-To-Point
Transmission Service if doing so would
impair system reliability or otherwise
impair or degrade existing firm service.
19.7 Partial Interim Service
If the Transmission Provider
determines that it will not have
adequate transfer capability to satisfy
the full amount of a Completed
Application for Firm Point-To-Point
Transmission Service, the Transmission
Provider nonetheless shall be obligated
to offer and provide the portion of the
requested Firm Point-To-Point
Transmission Service that can be
accommodated without addition of any
facilities and through redispatch.
However, the Transmission Provider
shall not be obligated to provide the
incremental amount of requested Firm
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Point-To-Point Transmission Service
that requires the addition of facilities or
upgrades to the Transmission System
until such facilities or upgrades have
been placed in service.
19.8 Expedited Procedures for New
Facilities
In lieu of the procedures set forth
above, the Eligible Customer shall have
the option to expedite the process by
requesting the Transmission Provider to
tender at one time, together with the
results of required studies, an
‘‘Expedited Service Agreement’’
pursuant to which the Eligible Customer
would agree to compensate the
Transmission Provider for all costs
incurred pursuant to the terms of the
Tariff. In order to exercise this option,
the Eligible Customer shall request in
writing an expedited Service Agreement
covering all of the above-specified items
within thirty (30) days of receiving the
results of the System Impact Study
identifying needed facility additions or
upgrades or costs incurred in providing
the requested service. While the
Transmission Provider agrees to provide
the Eligible Customer with its best
estimate of the new facility costs and
other charges that may be incurred, such
estimate shall not be binding and the
Eligible Customer must agree in writing
to compensate the Transmission
Provider for all costs incurred pursuant
to the provisions of the Tariff. The
Eligible Customer shall execute and
return such an Expedited Service
Agreement within fifteen (15) days of its
receipt or the Eligible Customer’s
request for service will cease to be a
Completed Application and will be
deemed terminated and withdrawn.
19.9 Penalties for Failure To Meet
Study Deadlines
Sections 19.3 and 19.4 require a
Transmission Provider to use due
diligence to meet 60-day study
completion deadlines for System Impact
Studies and Facilities Studies.
(i) The Transmission Provider is
required to file a notice with the
Commission in the event that more than
twenty (20) percent of non-Affiliates’
System Impact Studies and Facilities
Studies completed by the Transmission
Provider in any two consecutive
calendar quarters are not completed
within the 60-day study completion
deadlines. Such notice must be filed
within thirty (30) days of the end of the
calendar quarter triggering the notice
requirement.
(ii) For the purposes of calculating the
percent of non-Affiliates’ System Impact
Studies and Facilities Studies processed
outside of the 60-day study completion
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deadlines, the Transmission Provider
shall consider all System Impact Studies
and Facilities Studies that it completes
for non-Affiliates during the calendar
quarter. The percentage should be
calculated by dividing the number of
those studies which are completed on
time by the total number of completed
studies. The Transmission Provider may
provide an explanation in its
notification filing to the Commission if
it believes there are extenuating
circumstances that prevented it from
meeting the 60-day study completion
deadlines.
(iii) The Transmission Provider is
subject to an operational penalty if it
completes ten (10) percent or more of
non-Affiliates’ System Impact Studies
and Facilities Studies outside of the 60day study completion deadlines for each
of the two calendar quarters
immediately following the quarter that
triggered its notification filing to the
Commission. The operational penalty
will be assessed for each calendar
quarter for which an operational penalty
applies, starting with the calendar
quarter immediately following the
quarter that triggered the Transmission
Provider’s notification filing to the
Commission. The operational penalty
will continue to be assessed each
quarter until the Transmission Provider
completes at least ninety (90) percent of
all non-Affiliates’ System Impact
Studies and Facilities Studies within
the 60-day deadline.
(iv) For penalties assessed in
accordance with subsection (iii) above,
the penalty amount for each System
Impact Study or Facilities Study shall
be equal to $500 for each day the
Transmission Provider takes to
complete that study beyond the 60-day
deadline.
20 Procedures if the Transmission
Provider Is Unable To Complete New
Transmission Facilities for Firm Pointto-Point Transmission Service
20.1 Delays in Construction of New
Facilities
If any event occurs that will
materially affect the time for completion
of new facilities, or the ability to
complete them, the Transmission
Provider shall promptly notify the
Transmission Customer. In such
circumstances, the Transmission
Provider shall within thirty (30) days of
notifying the Transmission Customer of
such delays, convene a technical
meeting with the Transmission
Customer to evaluate the alternatives
available to the Transmission Customer.
The Transmission Provider also shall
make available to the Transmission
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Customer studies and work papers
related to the delay, including all
information that is in the possession of
the Transmission Provider that is
reasonably needed by the Transmission
Customer to evaluate any alternatives.
20.2 Alternatives to the Original
Facility Additions
When the review process of Section
20.1 determines that one or more
alternatives exist to the originally
planned construction project, the
Transmission Provider shall present
such alternatives for consideration by
the Transmission Customer. If, upon
review of any alternatives, the
Transmission Customer desires to
maintain its Completed Application
subject to construction of the alternative
facilities, it may request the
Transmission Provider to submit a
revised Service Agreement for Firm
Point-To-Point Transmission Service. If
the alternative approach solely involves
Non-Firm Point-To-Point Transmission
Service, the Transmission Provider shall
promptly tender a Service Agreement
for Non-Firm Point-To-Point
Transmission Service providing for the
service. In the event the Transmission
Provider concludes that no reasonable
alternative exists and the Transmission
Customer disagrees, the Transmission
Customer may seek relief under the
dispute resolution procedures pursuant
to Section 12 or it may refer the dispute
to the Commission for resolution.
20.3 Refund Obligation for Unfinished
Facility Additions
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If the Transmission Provider and the
Transmission Customer mutually agree
that no other reasonable alternatives
exist and the requested service cannot
be provided out of existing capability
under the conditions of Part II of the
Tariff, the obligation to provide the
requested Firm Point-To-Point
Transmission Service shall terminate
and any deposit made by the
Transmission Customer shall be
returned with interest pursuant to
Commission regulations
35.19a(a)(2)(iii). However, the
Transmission Customer shall be
responsible for all prudently incurred
costs by the Transmission Provider
through the time construction was
suspended.
21 Provisions Relating to Transmission
Construction and Services on the
Systems of Other Utilities
21.1 Responsibility for Third-Party
System Additions
The Transmission Provider shall not
be responsible for making arrangements
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for any necessary engineering,
permitting, and construction of
transmission or distribution facilities on
the system(s) of any other entity or for
obtaining any regulatory approval for
such facilities. The Transmission
Provider will undertake reasonable
efforts to assist the Transmission
Customer in obtaining such
arrangements, including without
limitation, providing any information or
data required by such other electric
system pursuant to Good Utility
Practice.
21.2 Coordination of Third-Party
System Additions
In circumstances where the need for
transmission facilities or upgrades is
identified pursuant to the provisions of
Part II of the Tariff, and if such upgrades
further require the addition of
transmission facilities on other systems,
the Transmission Provider shall have
the right to coordinate construction on
its own system with the construction
required by others. The Transmission
Provider, after consultation with the
Transmission Customer and
representatives of such other systems,
may defer construction of its new
transmission facilities, if the new
transmission facilities on another
system cannot be completed in a timely
manner. The Transmission Provider
shall notify the Transmission Customer
in writing of the basis for any decision
to defer construction and the specific
problems which must be resolved before
it will initiate or resume construction of
new facilities. Within sixty (60) days of
receiving written notification by the
Transmission Provider of its intent to
defer construction pursuant to this
section, the Transmission Customer may
challenge the decision in accordance
with the dispute resolution procedures
pursuant to Section 12 or it may refer
the dispute to the Commission for
resolution.
22
Changes in Service Specifications
22.1 Modifications On a Non-Firm
Basis
The Transmission Customer taking
Firm Point-To-Point Transmission
Service may request the Transmission
Provider to provide transmission service
on a non-firm basis over Receipt and
Delivery Points other than those
specified in the Service Agreement
(‘‘Secondary Receipt and Delivery
Points’’), in amounts not to exceed its
firm capacity reservation, without
incurring an additional Non-Firm PointTo-Point Transmission Service charge or
executing a new Service Agreement,
subject to the following conditions.
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(a) Service provided over Secondary
Receipt and Delivery Points will be nonfirm only, on an as-available basis and
will not displace any firm or non-firm
service reserved or scheduled by thirdparties under the Tariff or by the
Transmission Provider on behalf of its
Native Load Customers.
(b) The sum of all Firm and non-firm
Point-To-Point Transmission Service
provided to the Transmission Customer
at any time pursuant to this section
shall not exceed the Reserved Capacity
in the relevant Service Agreement under
which such services are provided.
(c) The Transmission Customer shall
retain its right to schedule Firm PointTo-Point Transmission Service at the
Receipt and Delivery Points specified in
the relevant Service Agreement in the
amount of its original capacity
reservation.
(d) Service over Secondary Receipt
and Delivery Points on a non-firm basis
shall not require the filing of an
Application for Non-Firm Point-ToPoint Transmission Service under the
Tariff. However, all other requirements
of Part II of the Tariff (except as to
transmission rates) shall apply to
transmission service on a non-firm basis
over Secondary Receipt and Delivery
Points.
22.2
Modification On a Firm Basis
Any request by a Transmission
Customer to modify Receipt and
Delivery Points on a firm basis shall be
treated as a new request for service in
accordance with Section 17 hereof,
except that such Transmission Customer
shall not be obligated to pay any
additional deposit if the capacity
reservation does not exceed the amount
reserved in the existing Service
Agreement. While such new request is
pending, the Transmission Customer
shall retain its priority for service at the
existing firm Receipt and Delivery
Points specified in its Service
Agreement.
23 Sale or Assignment of Transmission
Service
23.1 Procedures for Assignment or
Transfer of Service
Subject to Commission approval of
any necessary filings, a Transmission
Customer may sell, assign, or transfer all
or a portion of its rights under its
Service Agreement, but only to another
Eligible Customer (the Assignee). The
Transmission Customer that sells,
assigns or transfers its rights under its
Service Agreement is hereafter referred
to as the Reseller. Compensation to
Resellers shall be at rates established by
agreement with the Assignee. The
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Assignee must execute a service
agreement with the Transmission
Provider prior to the date on which the
reassigned service commences that will
govern the provision of reassigned
service. The Transmission Provider
shall credit or charge the Reseller, as
appropriate, for any differences between
the price reflected in the Assignee’s
Service Agreement and the Reseller’s
Service Agreement with the
Transmission Provider. If the Assignee
does not request any change in the
Point(s) of Receipt or the Point(s) of
Delivery, or a change in any other term
or condition set forth in the original
Service Agreement, the Assignee will
receive the same services as did the
Reseller and the priority of service for
the Assignee will be the same as that of
the Reseller. The Assignee will be
subject to all terms and conditions of
this Tariff. If the Assignee requests a
change in service, the reservation
priority of service will be determined by
the Transmission Provider pursuant to
Section 13.2.
24 Metering and Power Factor
Correction at Receipt and Delivery
Points(s)
23.2 Limitations on Assignment or
Transfer of Service
Unless otherwise agreed, the
Transmission Customer is required to
maintain a power factor within the same
range as the Transmission Provider
pursuant to Good Utility Practices. The
power factor requirements are specified
in the Service Agreement where
applicable.
If the Assignee requests a change in
the Point(s) of Receipt or Point(s) of
Delivery, or a change in any other
specifications set forth in the original
Service Agreement, the Transmission
Provider will consent to such change
subject to the provisions of the Tariff,
provided that the change will not impair
the operation and reliability of the
Transmission Provider’s generation,
transmission, or distribution systems.
The Assignee shall compensate the
Transmission Provider for performing
any System Impact Study needed to
evaluate the capability of the
Transmission System to accommodate
the proposed change and any additional
costs resulting from such change. The
Reseller shall remain liable for the
performance of all obligations under the
Service Agreement, except as
specifically agreed to by the
Transmission Provider and the Reseller
through an amendment to the Service
Agreement.
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23.3 Information on Assignment or
Transfer of Service
In accordance with Section 4, all sales
or assignments of capacity must be
conducted through or otherwise posted
on the Transmission Provider’s OASIS
on or before the date the reassigned
service commences and are subject to
Section 23.1. Resellers may also use the
Transmission Provider’s OASIS to post
transmission capacity available for
resale.
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24.1 Transmission Customer
Obligations
Unless otherwise agreed, the
Transmission Customer shall be
responsible for installing and
maintaining compatible metering and
communications equipment to
accurately account for the capacity and
energy being transmitted under Part II of
the Tariff and to communicate the
information to the Transmission
Provider. Such equipment shall remain
the property of the Transmission
Customer.
24.2 Transmission Provider Access to
Metering Data
The Transmission Provider shall have
access to metering data, which may
reasonably be required to facilitate
measurements and billing under the
Service Agreement.
24.3
Power Factor
25 Compensation for Transmission
Service
Rates for Firm and Non-Firm PointTo-Point Transmission Service are
provided in the Schedules appended to
the Tariff: Firm Point-To-Point
Transmission Service (Schedule 7); and
Non-Firm Point-To-Point Transmission
Service (Schedule 8). The Transmission
Provider shall use Part II of the Tariff to
make its Third-Party Sales. The
Transmission Provider shall account for
such use at the applicable Tariff rates,
pursuant to Section 8.
26
Stranded Cost Recovery
The Transmission Provider may seek
to recover stranded costs from the
Transmission Customer pursuant to this
Tariff in accordance with the terms,
conditions and procedures set forth in
FERC Order No. 888. However, the
Transmission Provider must separately
file any specific proposed stranded cost
charge under Section 205 of the Federal
Power Act.
27 Compensation for New Facilities
and Redispatch Costs
Whenever a System Impact Study
performed by the Transmission Provider
in connection with the provision of
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Firm Point-To-Point Transmission
Service identifies the need for new
facilities, the Transmission Customer
shall be responsible for such costs to the
extent consistent with Commission
policy. Whenever a System Impact
Study performed by the Transmission
Provider identifies capacity constraints
that may be relieved by redispatching
the Transmission Provider’s resources to
eliminate such constraints, the
Transmission Customer shall be
responsible for the redispatch costs to
the extent consistent with Commission
policy.
III. Network Integration Transmission
Service
Preamble
The Transmission Provider will
provide Network Integration
Transmission Service pursuant to the
applicable terms and conditions
contained in the Tariff and Service
Agreement. Network Integration
Transmission Service allows the
Network Customer to integrate,
economically dispatch and regulate its
current and planned Network Resources
to serve its Network Load in a manner
comparable to that in which the
Transmission Provider utilizes its
Transmission System to serve its Native
Load Customers. Network Integration
Transmission Service also may be used
by the Network Customer to deliver
economy energy purchases to its
Network Load from non-designated
resources on an as-available basis
without additional charge. Transmission
service for sales to non-designated loads
will be provided pursuant to the
applicable terms and conditions of Part
II of the Tariff.
28 Nature of Network Integration
Transmission Service
28.1 Scope of Service
Network Integration Transmission
Service is a transmission service that
allows Network Customers to efficiently
and economically utilize their Network
Resources (as well as other nondesignated generation resources) to
serve their Network Load located in the
Transmission Provider’s Control Area
and any additional load that may be
designated pursuant to Section 31.3 of
the Tariff. The Network Customer taking
Network Integration Transmission
Service must obtain or provide
Ancillary Services pursuant to Section
3.
28.2 Transmission Provider
Responsibilities
The Transmission Provider will plan,
construct, operate and maintain its
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Transmission System in accordance
with Good Utility Practice and its
planning obligations in Attachment K in
order to provide the Network Customer
with Network Integration Transmission
Service over the Transmission
Provider’s Transmission System. The
Transmission Provider, on behalf of its
Native Load Customers, shall be
required to designate resources and
loads in the same manner as any
Network Customer under Part III of this
Tariff. This information must be
consistent with the information used by
the Transmission Provider to calculate
available transfer capability. The
Transmission Provider shall include the
Network Customer’s Network Load in
its Transmission System planning and
shall, consistent with Good Utility
Practice and Attachment K, endeavor to
construct and place into service
sufficient transfer capability to deliver
the Network Customer’s Network
Resources to serve its Network Load on
a basis comparable to the Transmission
Provider’s delivery of its own generating
and purchased resources to its Native
Load Customers.
28.3 Network Integration Transmission
Service
The Transmission Provider will
provide firm transmission service over
its Transmission System to the Network
Customer for the delivery of capacity
and energy from its designated Network
Resources to service its Network Loads
on a basis that is comparable to the
Transmission Provider’s use of the
Transmission System to reliably serve
its Native Load Customers.
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28.4 Secondary Service
The Network Customer may use the
Transmission Provider’s Transmission
System to deliver energy to its Network
Loads from resources that have not been
designated as Network Resources. Such
energy shall be transmitted, on an asavailable basis, at no additional charge.
Secondary service shall not require the
filing of an Application for Network
Integration Transmission Service under
the Tariff. However, all other
requirements of Part III of the Tariff
(except for transmission rates) shall
apply to secondary service. Deliveries
from resources other than Network
Resources will have a higher priority
than any Non-Firm Point-To-Point
Transmission Service under Part II of
the Tariff.
28.5 Real Power Losses
Real Power Losses are associated with
all transmission service. The
Transmission Provider is not obligated
to provide Real Power Losses. The
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Network Customer is responsible for
replacing losses associated with all
transmission service as calculated by
the Transmission Provider. The
applicable Real Power Loss factors are
as follows: [To be completed by the
Transmission Provider].
28.6
Restrictions on Use of Service
The Network Customer shall not use
Network Integration Transmission
Service for (i) sales of capacity and
energy to non-designated loads, or (ii)
direct or indirect provision of
transmission service by the Network
Customer to third parties. All Network
Customers taking Network Integration
Transmission Service shall use PointTo-Point Transmission Service under
Part II of the Tariff for any Third-Party
Sale which requires use of the
Transmission Provider’s Transmission
System. The Transmission Provider
shall specify any appropriate charges
and penalties and all related terms and
conditions applicable in the event that
a Network Customer uses Network
Integration Transmission Service or
secondary service pursuant to Section
28.4 to facilitate a wholesale sale that
does not serve a Network Load.
29
Initiating Service
29.1 Condition Precedent for
Receiving Service
Subject to the terms and conditions of
Part III of the Tariff, the Transmission
Provider will provide Network
Integration Transmission Service to any
Eligible Customer, provided that (i) the
Eligible Customer completes an
Application for service as provided
under Part III of the Tariff, (ii) the
Eligible Customer and the Transmission
Provider complete the technical
arrangements set forth in Sections 29.3
and 29.4, (iii) the Eligible Customer
executes a Service Agreement pursuant
to Attachment F for service under Part
III of the Tariff or requests in writing
that the Transmission Provider file a
proposed unexecuted Service
Agreement with the Commission, and
(iv) the Eligible Customer executes a
Network Operating Agreement with the
Transmission Provider pursuant to
Attachment G, or requests in writing
that the Transmission Provider file a
proposed unexecuted Network
Operating Agreement.
29.2
Application Procedures
An Eligible Customer requesting
service under Part III of the Tariff must
submit an Application, with a deposit
approximating the charge for one month
of service, to the Transmission Provider
as far as possible in advance of the
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12521
month in which service is to commence.
Unless subject to the procedures in
Section 2, Completed Applications for
Network Integration Transmission
Service will be assigned a priority
according to the date and time the
Application is received, with the
earliest Application receiving the
highest priority. Applications should be
submitted by entering the information
listed below on the Transmission
Provider’s OASIS. Prior to
implementation of the Transmission
Provider’s OASIS, a Completed
Application may be submitted by (i)
transmitting the required information to
the Transmission Provider by telefax, or
(ii) providing the information by
telephone over the Transmission
Provider’s time recorded telephone line.
Each of these methods will provide a
time-stamped record for establishing the
service priority of the Application. A
Completed Application shall provide all
of the information included in 18 CFR
2.20 including but not limited to the
following:
(i) The identity, address, telephone
number and facsimile number of the
party requesting service;
(ii) A statement that the party
requesting service is, or will be upon
commencement of service, an Eligible
Customer under the Tariff;
(iii) A description of the Network
Load at each delivery point. This
description should separately identify
and provide the Eligible Customer’s best
estimate of the total loads to be served
at each transmission voltage level, and
the loads to be served from each
Transmission Provider substation at the
same transmission voltage level. The
description should include a ten (10)
year forecast of summer and winter load
and resource requirements beginning
with the first year after the service is
scheduled to commence;
(iv) The amount and location of any
interruptible loads included in the
Network Load. This shall include the
summer and winter capacity
requirements for each interruptible load
(had such load not been interruptible),
that portion of the load subject to
interruption, the conditions under
which an interruption can be
implemented and any limitations on the
amount and frequency of interruptions.
An Eligible Customer should identify
the amount of interruptible customer
load (if any) included in the 10 year
load forecast provided in response to
(iii) above;
(v) A description of Network
Resources (current and 10-year
projection). For each on-system Network
Resource, such description shall
include:
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• Unit size and amount of capacity
from that unit to be designated as
Network Resource
• VAR capability (both leading and
lagging) of all generators
• Operating restrictions
—Any periods of restricted operations
throughout the year
—Maintenance schedules
—Minimum loading level of unit
—Normal operating level of unit
—Any must-run unit designations
required for system reliability or
contract reasons
• Approximate variable generating
cost ($/MWH) for redispatch
computations
• Arrangements governing sale and
delivery of power to third parties from
generating facilities located in the
Transmission Provider Control Area,
where only a portion of unit output is
designated as a Network Resource;
For each off-system Network
Resource, such description shall
include:
• Identification of the Network
Resource as an off-system resource
• Amount of power to which the
customer has rights
• Identification of the control area(s)
from which the power will originate
• Delivery point(s) to the
Transmission Provider’s Transmission
System
• Transmission arrangements on the
external transmission system(s)
• Operating restrictions, if any
—Any periods of restricted operations
throughout the year
—Maintenance schedules
—Minimum loading level of unit
—Normal operating level of unit
—Any must-run unit designations
required for system reliability or
contract reasons
• Approximate variable generating
cost ($/MWH) for redispatch
computations;
(vi) Description of Eligible Customer’s
transmission system:
• Load flow and stability data, such
as real and reactive parts of the load,
lines, transformers, reactive devices and
load type, including normal and
emergency ratings of all transmission
equipment in a load flow format
compatible with that used by the
Transmission Provider
• Operating restrictions needed for
reliability
• Operating guides employed by
system operators
• Contractual restrictions or
committed uses of the Eligible
Customer’s transmission system, other
than the Eligible Customer’s Network
Loads and Resources
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• Location of Network Resources
described in subsection (v) above
• 10 year projection of system
expansions or upgrades
• Transmission System maps that
include any proposed expansions or
upgrades
• Thermal ratings of Eligible
Customer’s Control Area ties with other
Control Areas;
(vii) Service Commencement Date and
the term of the requested Network
Integration Transmission Service. The
minimum term for Network Integration
Transmission Service is one year;
(viii) A statement signed by an
authorized officer from or agent of the
Network Customer attesting that all of
the network resources listed pursuant to
Section 29.2(v) satisfy the following
conditions:
(1) The Network Customer owns the
resource, has committed to purchase
generation pursuant to an executed
contract, or has committed to purchase
generation where execution of a contract
is contingent upon the availability of
transmission service under Part III of the
Tariff; and (2) the Network Resources do
not include any resources, or any
portion thereof, that are committed for
sale to non-designated third party load
or otherwise cannot be called upon to
meet the Network Customer’s Network
Load on a non-interruptible basis; and
(ix) Any additional information
required of the Transmission Customer
as specified in the Transmission
Provider’s planning process established
in Attachment K.
Unless the Parties agree to a different
time frame, the Transmission Provider
must acknowledge the request within
ten (10) days of receipt. The
acknowledgement must include a date
by which a response, including a
Service Agreement, will be sent to the
Eligible Customer. If an Application
fails to meet the requirements of this
section, the Transmission Provider shall
notify the Eligible Customer requesting
service within fifteen (15) days of
receipt and specify the reasons for such
failure. Wherever possible, the
Transmission Provider will attempt to
remedy deficiencies in the Application
through informal communications with
the Eligible Customer. If such efforts are
unsuccessful, the Transmission Provider
shall return the Application without
prejudice to the Eligible Customer filing
a new or revised Application that fully
complies with the requirements of this
section. The Eligible Customer will be
assigned a new priority consistent with
the date of the new or revised
Application. The Transmission Provider
shall treat this information consistent
with the standards of conduct contained
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in Part 37 of the Commission’s
regulations.
29.3 Technical Arrangements to be
Completed Prior to Commencement of
Service
Network Integration Transmission
Service shall not commence until the
Transmission Provider and the Network
Customer, or a third party, have
completed installation of all equipment
specified under the Network Operating
Agreement consistent with Good Utility
Practice and any additional
requirements reasonably and
consistently imposed to ensure the
reliable operation of the Transmission
System. The Transmission Provider
shall exercise reasonable efforts, in
coordination with the Network
Customer, to complete such
arrangements as soon as practicable
taking into consideration the Service
Commencement Date.
29.4
Network Customer Facilities
The provision of Network Integration
Transmission Service shall be
conditioned upon the Network
Customer’s constructing, maintaining
and operating the facilities on its side of
each delivery point or interconnection
necessary to reliably deliver capacity
and energy from the Transmission
Provider’s Transmission System to the
Network Customer. The Network
Customer shall be solely responsible for
constructing or installing all facilities on
the Network Customer’s side of each
such delivery point or interconnection.
29.5
Filing of Service Agreement
The Transmission Provider will file
Service Agreements with the
Commission in compliance with
applicable Commission regulations.
30
Network Resources
30.1
Designation of Network Resources
Network Resources shall include all
generation owned, purchased or leased
by the Network Customer designated to
serve Network Load under the Tariff.
Network Resources may not include
resources, or any portion thereof, that
are committed for sale to nondesignated third party load or otherwise
cannot be called upon to meet the
Network Customer’s Network Load on a
non-interruptible basis. Any owned or
purchased resources that were serving
the Network Customer’s loads under
firm agreements entered into on or
before the Service Commencement Date
shall initially be designated as Network
Resources until the Network Customer
terminates the designation of such
resources.
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30.2 Designation of New Network
Resources
The Network Customer may designate
a new Network Resource by providing
the Transmission Provider with as much
advance notice as practicable. A
designation of a new Network Resource
must be made through the Transmission
Provider’s OASIS by a request for
modification of service pursuant to an
Application under Section 29. This
request must include a statement that
the new network resource satisfies the
following conditions: (1) the Network
Customer owns the resource, has
committed to purchase generation
pursuant to an executed contract, or has
committed to purchase generation
where execution of a contract is
contingent upon the availability of
transmission service under Part III of the
Tariff; and (2) The Network Resources
do not include any resources, or any
portion thereof, that are committed for
sale to non-designated third party load
or otherwise cannot be called upon to
meet the Network Customer’s Network
Load on a non-interruptible basis. The
Network Customer’s request will be
deemed deficient if it does not include
this statement and the Transmission
Provider will follow the procedures for
a deficient application as described in
Section 29.2 of the Tariff.
30.3 Termination of Network
Resources
The Network Customer may terminate
the designation of all or part of a
generating resource as a Network
Resource by providing notification to
the Transmission Provider through
OASIS as soon as reasonably
practicable, but not later than the firm
scheduling deadline for the period of
termination. Any request for
termination of Network Resource status
must be submitted on OASIS, and
should indicate whether the request is
for indefinite or temporary termination.
A request for indefinite termination of
Network Resource status must indicate
the date and time that the termination
is to be effective, and the identification
and capacity of the resource(s) or
portions thereof to be indefinitely
terminated. A request for temporary
termination of Network Resource status
must include the following:
(i) Effective date and time of
temporary termination;
(ii) Effective date and time of
redesignation, following period of
temporary termination;
(iii) Identification and capacity of
resource(s) or portions thereof to be
temporarily terminated;
(iv) Resource description and
attestation for redesignating the network
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resource following the temporary
termination, in accordance with Section
30.2; and
(v) Identification of any related
transmission service requests to be
evaluated concomitantly with the
request for temporary termination, such
that the requests for undesignation and
the request for these related
transmission service requests must be
approved or denied as a single request.
The evaluation of these related
transmission service requests must take
into account the termination of the
network resources identified in (iii)
above, as well as all competing
transmission service requests of higher
priority.
As part of a temporary termination, a
Network Customer may only redesignate
the same resource that was originally
designated, or a portion thereof.
Requests to redesignate a different
resource and/or a resource with
increased capacity will be deemed
deficient and the Transmission Provider
will follow the procedures for a
deficient application as described in
Section 29.2 of the Tariff.
30.4 Operation of Network Resources
The Network Customer shall not
operate its designated Network
Resources located in the Network
Customer’s or Transmission Provider’s
Control Area such that the output of
those facilities exceeds its designated
Network Load, plus Non-Firm Sales
delivered pursuant to Part II of the
Tariff, plus losses. This limitation shall
not apply to changes in the operation of
a Transmission Customer’s Network
Resources at the request of the
Transmission Provider to respond to an
emergency or other unforeseen
condition which may impair or degrade
the reliability of the Transmission
System. For all Network Resources not
physically connected with the
Transmission Provider’s Transmission
System, the Network Customer may not
schedule delivery of energy in excess of
the Network Resource’s capacity, as
specified in the Network Customer’s
Application pursuant to Section 29,
unless the Network Customer supports
such delivery within the Transmission
Provider’s Transmission System by
either obtaining Point-to-Point
Transmission Service or utilizing
secondary service pursuant to Section
28.4. The Transmission Provider shall
specify the rate treatment and all related
terms and conditions applicable in the
event that a Network Customer’s
schedule at the delivery point for a
Network Resource not physically
interconnected with the Transmission
Provider’s Transmission System exceeds
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12523
the Network Resource’s designated
capacity, excluding energy delivered
using secondary service or Point-toPoint Transmission Service.
30.5 Network Customer Redispatch
Obligation
As a condition to receiving Network
Integration Transmission Service, the
Network Customer agrees to redispatch
its Network Resources as requested by
the Transmission Provider pursuant to
Section 33.2. To the extent practical, the
redispatch of resources pursuant to this
section shall be on a least cost, nondiscriminatory basis between all
Network Customers, and the
Transmission Provider.
30.6 Transmission Arrangements for
Network Resources Not Physically
Interconnected With The Transmission
Provider
The Network Customer shall be
responsible for any arrangements
necessary to deliver capacity and energy
from a Network Resource not physically
interconnected with the Transmission
Provider’s Transmission System. The
Transmission Provider will undertake
reasonable efforts to assist the Network
Customer in obtaining such
arrangements, including without
limitation, providing any information or
data required by such other entity
pursuant to Good Utility Practice.
30.7 Limitation on Designation of
Network Resources
The Network Customer must
demonstrate that it owns or has
committed to purchase generation
pursuant to an executed contract in
order to designate a generating resource
as a Network Resource. Alternatively,
the Network Customer may establish
that execution of a contract is
contingent upon the availability of
transmission service under Part III of the
Tariff.
30.8 Use of Interface Capacity by the
Network Customer
There is no limitation upon a Network
Customer’s use of the Transmission
Provider’s Transmission System at any
particular interface to integrate the
Network Customer’s Network Resources
(or substitute economy purchases) with
its Network Loads. However, a Network
Customer’s use of the Transmission
Provider’s total interface capacity with
other transmission systems may not
exceed the Network Customer’s Load.
30.9 Network Customer Owned
Transmission Facilities
The Network Customer that owns
existing transmission facilities that are
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integrated with the Transmission
Provider’s Transmission System may be
eligible to receive consideration either
through a billing credit or some other
mechanism. In order to receive such
consideration the Network Customer
must demonstrate that its transmission
facilities are integrated into the plans or
operations of the Transmission
Provider, to serve its power and
transmission customers. For facilities
added by the Network Customer
subsequent to the [the effective date of
a Final Rule in RM05–25–000], the
Network Customer shall receive credit
for such transmission facilities added if
such facilities are integrated into the
operations of the Transmission
Provider’s facilities; provided however,
the Network Customer’s transmission
facilities shall be presumed to be
integrated if such transmission facilities,
if owned by the Transmission Provider,
would be eligible for inclusion in the
Transmission Provider’s annual
transmission revenue requirement as
specified in Attachment H. Calculation
of any credit under this subsection shall
be addressed in either the Network
Customer’s Service Agreement or any
other agreement between the Parties.
31
31.1
Designation of Network Load
Network Load
The Network Customer must
designate the individual Network Loads
on whose behalf the Transmission
Provider will provide Network
Integration Transmission Service. The
Network Loads shall be specified in the
Service Agreement.
sroberts on PROD1PC70 with RULES
31.2 New Network Loads Connected
With the Transmission Provider
The Network Customer shall provide
the Transmission Provider with as much
advance notice as reasonably practicable
of the designation of new Network Load
that will be added to its Transmission
System. A designation of new Network
Load must be made through a
modification of service pursuant to a
new Application. The Transmission
Provider will use due diligence to
install any transmission facilities
required to interconnect a new Network
Load designated by the Network
Customer. The costs of new facilities
required to interconnect a new Network
Load shall be determined in accordance
with the procedures provided in Section
32.4 and shall be charged to the
Network Customer in accordance with
Commission policies.
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31.3 Network Load Not Physically
Interconnected With the Transmission
Provider
This section applies to both initial
designation pursuant to Section 31.1
and the subsequent addition of new
Network Load not physically
interconnected with the Transmission
Provider. To the extent that the Network
Customer desires to obtain transmission
service for a load outside the
Transmission Provider’s Transmission
System, the Network Customer shall
have the option of (1) electing to include
the entire load as Network Load for all
purposes under Part III of the Tariff and
designating Network Resources in
connection with such additional
Network Load, or (2) excluding that
entire load from its Network Load and
purchasing Point-To-Point Transmission
Service under Part II of the Tariff. To the
extent that the Network Customer gives
notice of its intent to add a new
Network Load as part of its Network
Load pursuant to this section the
request must be made through a
modification of service pursuant to a
new Application.
31.4 New Interconnection Points
To the extent the Network Customer
desires to add a new Delivery Point or
interconnection point between the
Transmission Provider’s Transmission
System and a Network Load, the
Network Customer shall provide the
Transmission Provider with as much
advance notice as reasonably
practicable.
31.5 Changes in Service Requests
Under no circumstances shall the
Network Customer’s decision to cancel
or delay a requested change in Network
Integration Transmission Service (e.g.
the addition of a new Network Resource
or designation of a new Network Load)
in any way relieve the Network
Customer of its obligation to pay the
costs of transmission facilities
constructed by the Transmission
Provider and charged to the Network
Customer as reflected in the Service
Agreement. However, the Transmission
Provider must treat any requested
change in Network Integration
Transmission Service in a nondiscriminatory manner.
31.6 Annual Load and Resource
Information Updates
The Network Customer shall provide
the Transmission Provider with annual
updates of Network Load and Network
Resource forecasts consistent with those
included in its Application for Network
Integration Transmission Service under
Part III of the Tariff including, but not
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limited to, any information provided
under section 29.2(ix) pursuant to the
Transmission Provider’s planning
process in Attachment K. The Network
Customer also shall provide the
Transmission Provider with timely
written notice of material changes in
any other information provided in its
Application relating to the Network
Customer’s Network Load, Network
Resources, its transmission system or
other aspects of its facilities or
operations affecting the Transmission
Provider’s ability to provide reliable
service.
32 Additional Study Procedures for
Network Integration Transmission
Service Requests
32.1 Notice of Need for System Impact
Study
After receiving a request for service,
the Transmission Provider shall
determine on a non-discriminatory basis
whether a System Impact Study is
needed. A description of the
Transmission Provider’s methodology
for completing a System Impact Study is
provided in Attachment D. If the
Transmission Provider determines that a
System Impact Study is necessary to
accommodate the requested service, it
shall so inform the Eligible Customer, as
soon as practicable. In such cases, the
Transmission Provider shall within
thirty (30) days of receipt of a
Completed Application, tender a System
Impact Study Agreement pursuant to
which the Eligible Customer shall agree
to reimburse the Transmission Provider
for performing the required System
Impact Study. For a service request to
remain a Completed Application, the
Eligible Customer shall execute the
System Impact Study Agreement and
return it to the Transmission Provider
within fifteen (15) days. If the Eligible
Customer elects not to execute the
System Impact Study Agreement, its
Application shall be deemed withdrawn
and its deposit shall be returned with
interest.
32.2 System Impact Study Agreement
and Cost Reimbursement
(i) The System Impact Study
Agreement will clearly specify the
Transmission Provider’s estimate of the
actual cost, and time for completion of
the System Impact Study. The charge
shall not exceed the actual cost of the
study. In performing the System Impact
Study, the Transmission Provider shall
rely, to the extent reasonably
practicable, on existing transmission
planning studies. The Eligible Customer
will not be assessed a charge for such
existing studies; however, the Eligible
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Customer will be responsible for charges
associated with any modifications to
existing planning studies that are
reasonably necessary to evaluate the
impact of the Eligible Customer’s
request for service on the Transmission
System.
(ii) If in response to multiple Eligible
Customers requesting service in relation
to the same competitive solicitation, a
single System Impact Study is sufficient
for the Transmission Provider to
accommodate the service requests, the
costs of that study shall be pro-rated
among the Eligible Customers.
(iii) For System Impact Studies that
the Transmission Provider conducts on
its own behalf, the Transmission
Provider shall record the cost of the
System Impact Studies pursuant to
Section 8.
sroberts on PROD1PC70 with RULES
32.3
System Impact Study Procedures
Upon receipt of an executed System
Impact Study Agreement, the
Transmission Provider will use due
diligence to complete the required
System Impact Study within a sixty (60)
day period. The System Impact Study
shall identify any system constraints
and redispatch options, additional
Direct Assignment Facilities or Network
Upgrades required to provide the
requested service. In the event that the
Transmission Provider is unable to
complete the required System Impact
Study within such time period, it shall
so notify the Eligible Customer and
provide an estimated completion date
along with an explanation of the reasons
why additional time is required to
complete the required studies. A copy of
the completed System Impact Study and
related work papers shall be made
available to the Eligible Customer as
soon as the System Impact Study is
complete. The Transmission Provider
will use the same due diligence in
completing the System Impact Study for
an Eligible Customer as it uses when
completing studies for itself. The
Transmission Provider shall notify the
Eligible Customer immediately upon
completion of the System Impact Study
if the Transmission System will be
adequate to accommodate all or part of
a request for service or that no costs are
likely to be incurred for new
transmission facilities or upgrades. In
order for a request to remain a
Completed Application, within fifteen
(15) days of completion of the System
Impact Study the Eligible Customer
must execute a Service Agreement or
request the filing of an unexecuted
Service Agreement, or the Application
shall be deemed terminated and
withdrawn.
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32.4 Facilities Study Procedures
If a System Impact Study indicates
that additions or upgrades to the
Transmission System are needed to
supply the Eligible Customer’s service
request, the Transmission Provider,
within thirty (30) days of the
completion of the System Impact Study,
shall tender to the Eligible Customer a
Facilities Study Agreement pursuant to
which the Eligible Customer shall agree
to reimburse the Transmission Provider
for performing the required Facilities
Study. For a service request to remain
a Completed Application, the Eligible
Customer shall execute the Facilities
Study Agreement and return it to the
Transmission Provider within fifteen
(15) days. If the Eligible Customer elects
not to execute the Facilities Study
Agreement, its Application shall be
deemed withdrawn and its deposit shall
be returned with interest. Upon receipt
of an executed Facilities Study
Agreement, the Transmission Provider
will use due diligence to complete the
required Facilities Study within a sixty
(60) day period. If the Transmission
Provider is unable to complete the
Facilities Study in the allotted time
period, the Transmission Provider shall
notify the Eligible Customer and
provide an estimate of the time needed
to reach a final determination along
with an explanation of the reasons that
additional time is required to complete
the study. When completed, the
Facilities Study will include a good
faith estimate of (i) the cost of Direct
Assignment Facilities to be charged to
the Eligible Customer, (ii) the Eligible
Customer’s appropriate share of the cost
of any required Network Upgrades, and
(iii) the time required to complete such
construction and initiate the requested
service. The Eligible Customer shall
provide the Transmission Provider with
a letter of credit or other reasonable
form of security acceptable to the
Transmission Provider equivalent to the
costs of new facilities or upgrades
consistent with commercial practices as
established by the Uniform Commercial
Code. The Eligible Customer shall have
thirty (30) days to execute a Service
Agreement or request the filing of an
unexecuted Service Agreement and
provide the required letter of credit or
other form of security or the request no
longer will be a Completed Application
and shall be deemed terminated and
withdrawn.
32.5 Penalties for Failure To Meet
Study Deadlines
Section 19.9 defines penalties that
apply for failure to meet the 60-day
study completion due diligence
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12525
deadlines for System Impact Studies
and Facilities Studies under Part II of
the Tariff. These same requirements and
penalties apply to service under Part III
of the Tariff.
33
Load Shedding and Curtailments
33.1
Procedures
Prior to the Service Commencement
Date, the Transmission Provider and the
Network Customer shall establish Load
Shedding and Curtailment procedures
pursuant to the Network Operating
Agreement with the objective of
responding to contingencies on the
Transmission System and on systems
directly and indirectly interconnected
with Transmission Provider’s
Transmission System. The Parties will
implement such programs during any
period when the Transmission Provider
determines that a system contingency
exists and such procedures are
necessary to alleviate such contingency.
The Transmission Provider will notify
all affected Network Customers in a
timely manner of any scheduled
Curtailment.
33.2
Transmission Constraints
During any period when the
Transmission Provider determines that a
transmission constraint exists on the
Transmission System, and such
constraint may impair the reliability of
the Transmission Provider’s system, the
Transmission Provider will take
whatever actions, consistent with Good
Utility Practice, that are reasonably
necessary to maintain the reliability of
the Transmission Provider’s system. To
the extent the Transmission Provider
determines that the reliability of the
Transmission System can be maintained
by redispatching resources, the
Transmission Provider will initiate
procedures pursuant to the Network
Operating Agreement to redispatch all
Network Resources and the
Transmission Provider’s own resources
on a least-cost basis without regard to
the ownership of such resources. Any
redispatch under this section may not
unduly discriminate between the
Transmission Provider’s use of the
Transmission System on behalf of its
Native Load Customers and any
Network Customer’s use of the
Transmission System to serve its
designated Network Load.
33.3 Cost Responsibility for Relieving
Transmission Constraints
Whenever the Transmission Provider
implements least-cost redispatch
procedures in response to a
transmission constraint, the
Transmission Provider and Network
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Customers will each bear a
proportionate share of the total
redispatch cost based on their respective
Load Ratio Shares.
33.4 Curtailments of Scheduled
Deliveries
If a transmission constraint on the
Transmission Provider’s Transmission
System cannot be relieved through the
implementation of least-cost redispatch
procedures and the Transmission
Provider determines that it is necessary
to Curtail scheduled deliveries, the
Parties shall Curtail such schedules in
accordance with the Network Operating
Agreement or pursuant to the
Transmission Loading Relief procedures
specified in Attachment J.
33.5 Allocation of Curtailments
The Transmission Provider shall, on a
non-discriminatory basis, Curtail the
transaction(s) that effectively relieve the
constraint. However, to the extent
practicable and consistent with Good
Utility Practice, any Curtailment will be
shared by the Transmission Provider
and Network Customer in proportion to
their respective Load Ratio Shares. The
Transmission Provider shall not direct
the Network Customer to Curtail
schedules to an extent greater than the
Transmission Provider would Curtail
the Transmission Provider’s schedules
under similar circumstances.
sroberts on PROD1PC70 with RULES
33.6 Load Shedding
To the extent that a system
contingency exists on the Transmission
Provider’s Transmission System and the
Transmission Provider determines that
it is necessary for the Transmission
Provider and the Network Customer to
shed load, the Parties shall shed load in
accordance with previously established
procedures under the Network
Operating Agreement.
33.7 System Reliability
Notwithstanding any other provisions
of this Tariff, the Transmission Provider
reserves the right, consistent with Good
Utility Practice and on a not unduly
discriminatory basis, to Curtail Network
Integration Transmission Service
without liability on the Transmission
Provider’s part for the purpose of
making necessary adjustments to,
changes in, or repairs on its lines,
substations and facilities, and in cases
where the continuance of Network
Integration Transmission Service would
endanger persons or property. In the
event of any adverse condition(s) or
disturbance(s) on the Transmission
Provider’s Transmission System or on
any other system(s) directly or
indirectly interconnected with the
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Transmission Provider’s Transmission
System, the Transmission Provider,
consistent with Good Utility Practice,
also may Curtail Network Integration
Transmission Service in order to (i)
limit the extent or damage of the
adverse condition(s) or disturbance(s),
(ii) prevent damage to generating or
transmission facilities, or (iii) expedite
restoration of service. The Transmission
Provider will give the Network
Customer as much advance notice as is
practicable in the event of such
Curtailment. Any Curtailment of
Network Integration Transmission
Service will be not unduly
discriminatory relative to the
Transmission Provider’s use of the
Transmission System on behalf of its
Native Load Customers. The
Transmission Provider shall specify the
rate treatment and all related terms and
conditions applicable in the event that
the Network Customer fails to respond
to established Load Shedding and
Curtailment procedures.
34
Rates and Charges
The Network Customer shall pay the
Transmission Provider for any Direct
Assignment Facilities, Ancillary
Services, and applicable study costs,
consistent with Commission policy,
along with the following:
34.1
Monthly Demand Charge
The Network Customer shall pay a
monthly Demand Charge, which shall
be determined by multiplying its Load
Ratio Share times one twelfth (1⁄12) of
the Transmission Provider’s Annual
Transmission Revenue Requirement
specified in Schedule H.
34.2 Determination of Network
Customer’s Monthly Network Load
The Network Customer’s monthly
Network Load is its hourly load
(including its designated Network Load
not physically interconnected with the
Transmission Provider under Section
31.3) coincident with the Transmission
Provider’s Monthly Transmission
System Peak.
34.3 Determination of Transmission
Provider’s Monthly Transmission
System Load
The Transmission Provider’s monthly
Transmission System load is the
Transmission Provider’s Monthly
Transmission System Peak minus the
coincident peak usage of all Firm PointTo-Point Transmission Service
customers pursuant to Part II of this
Tariff plus the Reserved Capacity of all
Firm Point-To-Point Transmission
Service customers.
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34.4 Redispatch Charge
The Network Customer shall pay a
Load Ratio Share of any redispatch costs
allocated between the Network
Customer and the Transmission
Provider pursuant to Section 33. To the
extent that the Transmission Provider
incurs an obligation to the Network
Customer for redispatch costs in
accordance with Section 33, such
amounts shall be credited against the
Network Customer’s bill for the
applicable month.
34.5 Stranded Cost Recovery
The Transmission Provider may seek
to recover stranded costs from the
Network Customer pursuant to this
Tariff in accordance with the terms,
conditions and procedures set forth in
FERC Order No. 888. However, the
Transmission Provider must separately
file any proposal to recover stranded
costs under Section 205 of the Federal
Power Act.
35
Operating Arrangements
35.1 Operation Under the Network
Operating Agreement
The Network Customer shall plan,
construct, operate and maintain its
facilities in accordance with Good
Utility Practice and in conformance
with the Network Operating Agreement.
35.2 Network Operating Agreement
The terms and conditions under
which the Network Customer shall
operate its facilities and the technical
and operational matters associated with
the implementation of Part III of the
Tariff shall be specified in the Network
Operating Agreement. The Network
Operating Agreement shall provide for
the Parties to (i) operate and maintain
equipment necessary for integrating the
Network Customer within the
Transmission Provider’s Transmission
System (including, but not limited to,
remote terminal units, metering,
communications equipment and
relaying equipment), (ii) transfer data
between the Transmission Provider and
the Network Customer (including, but
not limited to, heat rates and
operational characteristics of Network
Resources, generation schedules for
units outside the Transmission
Provider’s Transmission System,
interchange schedules, unit outputs for
redispatch required under Section 33,
voltage schedules, loss factors and other
real time data), (iii) use software
programs required for data links and
constraint dispatching, (iv) exchange
data on forecasted loads and resources
necessary for long-term planning, and
(v) address any other technical and
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operational considerations required for
implementation of Part III of the Tariff,
including scheduling protocols. The
Network Operating Agreement will
recognize that the Network Customer
shall either (i) operate as a Control Area
under applicable guidelines of the
Electric Reliability Organization (ERO)
as defined in 18 CFR 39.1, (ii) satisfy its
Control Area requirements, including all
necessary Ancillary Services, by
contracting with the Transmission
Provider, or (iii) satisfy its Control Area
requirements, including all necessary
Ancillary Services, by contracting with
another entity, consistent with Good
Utility Practice, which satisfies the
applicable reliability guidelines of the
ERO. The Transmission Provider shall
not unreasonably refuse to accept
contractual arrangements with another
entity for Ancillary Services. The
Network Operating Agreement is
included in Attachment G.
35.3
Network Operating Committee
A Network Operating Committee
(Committee) shall be established to
coordinate operating criteria for the
Parties’ respective responsibilities under
the Network Operating Agreement. Each
Network Customer shall be entitled to
have at least one representative on the
Committee. The Committee shall meet
from time to time as need requires, but
no less than once each calendar year.
sroberts on PROD1PC70 with RULES
Schedule 1—Scheduling, System
Control and Dispatch Service
This service is required to schedule
the movement of power through, out of,
within, or into a Control Area. This
service can be provided only by the
operator of the Control Area in which
the transmission facilities used for
transmission service are located.
Scheduling, System Control and
Dispatch Service is to be provided
directly by the Transmission Provider (if
the Transmission Provider is the Control
Area operator) or indirectly by the
Transmission Provider making
arrangements with the Control Area
operator that performs this service for
the Transmission Provider’s
Transmission System. The Transmission
Customer must purchase this service
from the Transmission Provider or the
Control Area operator. The charges for
Scheduling, System Control and
Dispatch Service are to be based on the
rates set forth below. To the extent the
Control Area operator performs this
service for the Transmission Provider,
charges to the Transmission Customer
are to reflect only a pass-through of the
costs charged to the Transmission
Provider by that Control Area operator.
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Schedule 2—Reactive Supply and
Voltage Control From Generation or
Other Sources Service
In order to maintain transmission
voltages on the Transmission Provider’s
transmission facilities within acceptable
limits, generation facilities and nongeneration resources capable of
providing this service that are under the
control of the control area operator are
operated to produce (or absorb) reactive
power. Thus, Reactive Supply and
Voltage Control from Generation or
Other Sources Service must be provided
for each transaction on the
Transmission Provider’s transmission
facilities. The amount of Reactive
Supply and Voltage Control from
Generation or Other Sources Service
that must be supplied with respect to
the Transmission Customer’s
transaction will be determined based on
the reactive power support necessary to
maintain transmission voltages within
limits that are generally accepted in the
region and consistently adhered to by
the Transmission Provider.
Reactive Supply and Voltage Control
from Generation or Other Sources
Service is to be provided directly by the
Transmission Provider (if the
Transmission Provider is the Control
Area operator) or indirectly by the
Transmission Provider making
arrangements with the Control Area
operator that performs this service for
the Transmission Provider’s
Transmission System. The Transmission
Customer must purchase this service
from the Transmission Provider or the
Control Area operator. The charges for
such service will be based on the rates
set forth below. To the extent the
Control Area operator performs this
service for the Transmission Provider,
charges to the Transmission Customer
are to reflect only a pass-through of the
costs charged to the Transmission
Provider by the Control Area operator.
Schedule 3—Regulation and Frequency
Response Service
Regulation and Frequency Response
Service is necessary to provide for the
continuous balancing of resources
(generation and interchange) with load
and for maintaining scheduled
Interconnection frequency at sixty
cycles per second (60 Hz). Regulation
and Frequency Response Service is
accomplished by committing on-line
generation whose output is raised or
lowered (predominantly through the use
of automatic generating control
equipment) and by other non-generation
resources capable of providing this
service as necessary to follow the
moment-by-moment changes in load.
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The obligation to maintain this balance
between resources and load lies with
the Transmission Provider (or the
Control Area operator that performs this
function for the Transmission Provider).
The Transmission Provider must offer
this service when the transmission
service is used to serve load within its
Control Area. The Transmission
Customer must either purchase this
service from the Transmission Provider
or make alternative comparable
arrangements to satisfy its Regulation
and Frequency Response Service
obligation. The amount of and charges
for Regulation and Frequency Response
Service are set forth below. To the
extent the Control Area operator
performs this service for the
Transmission Provider, charges to the
Transmission Customer are to reflect
only a pass-through of the costs charged
to the Transmission Provider by that
Control Area operator.
Schedule 4—Energy Imbalance Service
Energy Imbalance Service is provided
when a difference occurs between the
scheduled and the actual delivery of
energy to a load located within a
Control Area over a single hour. The
Transmission Provider must offer this
service when the transmission service is
used to serve load within its Control
Area. The Transmission Customer must
either purchase this service from the
Transmission Provider or make
alternative comparable arrangements,
which may include use of nongeneration resources capable of
providing this service, to satisfy its
Energy Imbalance Service obligation. To
the extent the Control Area operator
performs this service for the
Transmission Provider, charges to the
Transmission Customer are to reflect
only a pass-through of the costs charged
to the Transmission Provider by that
Control Area operator. The
Transmission Provider may charge a
Transmission Customer a penalty for
either hourly generator imbalances
under Schedule 9 or hourly energy
imbalances under this Schedule for the
same imbalance, but not both.
The Transmission Provider shall
establish charges for energy imbalance
based on the deviation bands as follows:
(i) Deviations within +/¥1.5 percent
(with a minimum of 2 MW) of the
scheduled transaction to be applied
hourly to any energy imbalance that
occurs as a result of the Transmission
Customer’s scheduled transaction(s)
will be netted on a monthly basis and
settled financially, at the end of the
month, at 100 percent of incremental or
decremental cost; (ii) deviations greater
than +/¥1.5 percent up to 7.5 percent
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(or greater than 2 MW up to 10 MW) of
the scheduled transaction to be applied
hourly to any energy imbalance that
occurs as a result of the Transmission
Customer’s scheduled transaction(s)
will be settled financially, at the end of
each month, at 110 percent of
incremental cost or 90 percent of
decremental cost, and (iii) deviations
greater than +/¥7.5 percent (or 10 MW)
of the scheduled transaction to be
applied hourly to any energy imbalance
that occurs as a result of the
Transmission Customer’s scheduled
transaction(s) will be settled financially,
at the end of each month, at 125 percent
of incremental cost or 75 percent of
decremental cost.
For purposes of this Schedule, incremental
cost and decremental cost represent the
Transmission Provider’s actual average
hourly cost of the last 10 MW dispatched to
supply the Transmission Provider’s Native
Load Customers, based on the replacement
cost of fuel, unit heat rates, start-up costs
(including any commitment and redispatch
costs), incremental operation and
maintenance costs, and purchased and
interchange power costs and taxes, as
applicable.
sroberts on PROD1PC70 with RULES
Schedule 5—Operating Reserve—
Spinning Reserve Service
Spinning Reserve Service is needed to
serve load immediately in the event of
a system contingency. Spinning Reserve
Service may be provided by generating
units that are on-line and loaded at less
than maximum output and by nongeneration resources capable of
providing this service. The
Transmission Provider must offer this
service when the transmission service is
used to serve load within its Control
Area. The Transmission Customer must
either purchase this service from the
Transmission Provider or make
alternative comparable arrangements to
satisfy its Spinning Reserve Service
obligation. The amount of and charges
for Spinning Reserve Service are set
forth below. To the extent the Control
Area operator performs this service for
the Transmission Provider, charges to
the Transmission Customer are to reflect
only a pass-through of the costs charged
to the Transmission Provider by that
Control Area operator.
Schedule 6—Operating Reserve—
Supplemental Reserve Service
Supplemental Reserve Service is
needed to serve load in the event of a
system contingency; however, it is not
available immediately to serve load but
rather within a short period of time.
Supplemental Reserve Service may be
provided by generating units that are
on-line but unloaded, by quick-start
generation or by interruptible load or
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other non-generation resources capable
of providing this service. The
Transmission Provider must offer this
service when the transmission service is
used to serve load within its Control
Area. The Transmission Customer must
either purchase this service from the
Transmission Provider or make
alternative comparable arrangements to
satisfy its Supplemental Reserve Service
obligation. The amount of and charges
for Supplemental Reserve Service are
set forth below. To the extent the
Control Area operator performs this
service for the Transmission Provider,
charges to the Transmission Customer
are to reflect only a pass-through of the
costs charged to the Transmission
Provider by that Control Area operator.
Schedule 7—Long-Term Firm and
Short-Term Firm Point-To-Point
Transmission Service
The Transmission Customer shall
compensate the Transmission Provider
each month for Reserved Capacity at the
sum of the applicable charges set forth
below:
(1) Yearly delivery: one-twelfth of the
demand charge of $ll/KW of
Reserved Capacity per year.
(2) Monthly delivery: $ll/KW of
Reserved Capacity per month.
(3) Weekly delivery: $ll/KW of
Reserved Capacity per week.
(4) Daily delivery: $ll/KW of
Reserved Capacity per day.
The total demand charge in any week,
pursuant to a reservation for Daily
delivery, shall not exceed the rate
specified in section (3) above times the
highest amount in kilowatts of Reserved
Capacity in any day during such week.
(5) Discounts: Three principal
requirements apply to discounts for
transmission service as follows (1) any
offer of a discount made by the
Transmission Provider must be
announced to all Eligible Customers
solely by posting on the OASIS, (2) any
customer-initiated requests for
discounts (including requests for use by
one’s wholesale merchant or an
affiliate’s use) must occur solely by
posting on the OASIS, and (3) once a
discount is negotiated, details must be
immediately posted on the OASIS. For
any discount agreed upon for service on
a path, from point(s) of receipt to
point(s) of delivery, the Transmission
Provider must offer the same discounted
transmission service rate for the same
time period to all Eligible Customers on
all unconstrained transmission paths
that go to the same point(s) of delivery
on the Transmission System.
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Frm 00264
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Schedule 8—Non-Firm Point-To-Point
Transmission Service
The Transmission Customer shall
compensate the Transmission Provider
for Non-Firm Point-To-Point
Transmission Service up to the sum of
the applicable charges set forth below:
(1) Monthly delivery: $ll/KW of
Reserved Capacity per month.
(2) Weekly delivery: $ll/KW of
Reserved Capacity per week.
(3) Daily delivery: $ll/KW of
Reserved Capacity per day.
The total demand charge in any week,
pursuant to a reservation for Daily
delivery, shall not exceed the rate
specified in section (2) above times the
highest amount in kilowatts of Reserved
Capacity in any day during such week.
(4) Hourly delivery: The basic charge
shall be that agreed upon by the Parties
at the time this service is reserved and
in no event shall exceed $ll/MWH.
The total demand charge in any day,
pursuant to a reservation for Hourly
delivery, shall not exceed the rate
specified in section (3) above times the
highest amount in kilowatts of Reserved
Capacity in any hour during such day.
In addition, the total demand charge in
any week, pursuant to a reservation for
Hourly or Daily delivery, shall not
exceed the rate specified in section (2)
above times the highest amount in
kilowatts of Reserved Capacity in any
hour during such week.
(5) Discounts: Three principal
requirements apply to discounts for
transmission service as follows (1) any
offer of a discount made by the
Transmission Provider must be
announced to all Eligible Customers
solely by posting on the OASIS, (2) any
customer-initiated requests for
discounts (including requests for use by
one’s wholesale merchant or an
affiliate’s use) must occur solely by
posting on the OASIS, and (3) once a
discount is negotiated, details must be
immediately posted on the OASIS. For
any discount agreed upon for service on
a path, from point(s) of receipt to
point(s) of delivery, the Transmission
Provider must offer the same discounted
transmission service rate for the same
time period to all Eligible Customers on
all unconstrained transmission paths
that go to the same point(s) of delivery
on the Transmission System.
Schedule 9—Generator Imbalance
Service
Generator Imbalance Service is
provided when a difference occurs
between the output of a generator
located in the Transmission Provider’s
Control Area and a delivery schedule
from that generator to (1) another
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Control Area or (2) a load within the
Transmission Provider’s Control Area
over a single hour. The Transmission
Provider must offer this service when
Transmission Service is used to deliver
energy from a generator located within
its Control Area. The Transmission
Customer must either purchase this
service from the Transmission Provider
or make alternative comparable
arrangements, which may include use of
non-generation resources capable of
providing this service, to satisfy its
Generator Imbalance Service obligation.
To the extent the Control Area operator
performs this service for the
Transmission Provider, charges to the
Transmission Customer are to reflect
only a pass-through of the costs charged
to the Transmission Provider by that
Control Area Operator. The
Transmission Provider may charge a
Transmission Customer a penalty for
either hourly generator imbalances
under this Schedule or hourly energy
imbalances under Schedule 4 for the
same imbalance, but not both.
The Transmission Provider shall
establish charges for generator
imbalance based on the deviation bands
as follows: (i) Deviations within +/¥1.5
percent (with a minimum of 2 MW) of
the scheduled transaction to be applied
hourly to any generator imbalance that
occurs as a result of the Transmission
Customer’s scheduled transaction(s)
will be netted on a monthly basis and
settled financially, at the end of each
month, at 100 percent of incremental or
decremental cost, (ii) deviations greater
than +/¥1.5 percent up to 7.5 percent
(or greater than 2 MW up to 10 MW) of
the scheduled transaction to be applied
hourly to any generator imbalance that
occurs as a result of the Transmission
Customer’s scheduled transaction(s)
will be settled financially, at the end of
each month, at 110 percent of
incremental cost or 90 percent of
decremental cost, and (iii) deviations
greater than +/¥7.5 percent (or 10 MW)
of the scheduled transaction to be
applied hourly to any generator
imbalance that occurs as a result of the
Transmission Customer’s scheduled
transaction(s) will be settled at 125
percent of incremental cost or 75
percent of decremental cost, except that
an intermittent resource will be exempt
from this deviation band and will pay
the deviation band charges for all
deviations greater than the larger of 1.5
percent or 2 MW. An intermittent
resource, for the limited purpose of this
Schedule is an electric generator that is
not dispatchable and cannot store its
fuel source and therefore cannot
respond to changes in system demand
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18:17 Mar 14, 2007
Jkt 211001
or respond to transmission security
constraints.
For purposes of this Schedule,
incremental cost and decremental cost
represent the Transmission Provider’s
actual average hourly cost of the last 10
MW dispatched to supply the
Transmission Provider’s Native Load
Customers, based on the replacement
cost of fuel, unit heat rates, start-up
costs (including any commitment and
redispatch costs), incremental operation
and maintenance costs, and purchased
and interchange power costs and taxes,
as applicable.
Attachment A—Form Of Service Agreement
For Firm Point-To-Point Transmission
Service
1.0 This Service Agreement, dated as of
llll, is entered into, by and between
llll (the Transmission Provider), and
llll (‘‘Transmission Customer’’).
2.0 The Transmission Customer has been
determined by the Transmission Provider to
have a Completed Application for Firm
Point-To-Point Transmission Service under
the Tariff.
3.0 The Transmission Customer has
provided to the Transmission Provider an
Application deposit in accordance with the
provisions of Section 17.3 of the Tariff.
4.0 Service under this agreement shall
commence on the later of (l) the requested
service commencement date, or (2) the date
on which construction of any Direct
Assignment Facilities and/or Network
Upgrades are completed, or (3) such other
date as it is permitted to become effective by
the Commission. Service under this
agreement shall terminate on such date as
mutually agreed upon by the parties.
5.0 The Transmission Provider agrees to
provide and the Transmission Customer
agrees to take and pay for Firm Point-ToPoint Transmission Service in accordance
with the provisions of Part II of the Tariff and
this Service Agreement.
6.0 Any notice or request made to or by
either Party regarding this Service Agreement
shall be made to the representative of the
other Party as indicated below.
Transmission Provider:
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
Transmission Customer:
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
7.0 The Tariff is incorporated herein and
made a part hereof.
IN WITNESS WHEREOF, the Parties have
caused this Service Agreement to be executed
by their respective authorized officials.
Transmission Provider:
By:
lllllllllllllllllllll
Name
lllllllllllllllllllll
Title
lllllllllllllllllllll
PO 00000
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12529
Date
Transmission Customer:
By:
lllllllllllllllllllll
Name
lllllllllllllllllllll
Title
lllllllllllllllllllll
Date
Specifications for Long-Term Firm Point-toPoint Transmission Service
1.0 Term of Transaction: llllllll
Start Date:
lllllllllllllll
Termination Date: llllllllllll
2.0 Description of capacity and energy to be
transmitted by Transmission Provider
including the electric Control Area in which
the transaction originates.
lllllllllllllllllllll
3.0 Point(s) of Receipt: lllllllll
Delivering Party: lllllllllllll
4.0 Point(s) of Delivery: lllllllll
Receiving Party: lllllllllllll
5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): l
6.0 Designation of party(ies) subject to reciprocal service obligation: llllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
7.0 Name(s) of any Intervening Systems
providing transmission service: llllll
lllllllllllllllllllll
8.0 Service under this Agreement may be
subject to some combination of the charges
detailed below. (The appropriate charges for
individual transactions will be determined in
accordance with the terms and conditions of
the Tariff.)
8.1 Transmission Charge: llllllll
lllllllllllllllllllll
8.2 System Impact and/or Facilities Study
Charge(s):
lllllllllllllllllllll
lllllllllllllllllllll
8.3 Direct Assignment Facilities Charge: l
lllllllllllllllllllll
8.4 Ancillary Services Charges: lllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
Attachment A–1—Form of Service
Agreement for the Resale, Reassignment or
Transfer of Long-Term Firm Point-to-Point
Transmission Service
1.0 This Service Agreement, dated as of
llll, is entered into, by and between
llll (the Transmission Provider), and
llll (the Assignee).
2.0 The Assignee has been determined by
the Transmission Provider to be an Eligible
Customer under the Tariff pursuant to which
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sroberts on PROD1PC70 with RULES
the transmission service rights to be
transferred were originally obtained.
3.0 The terms and conditions for the
transaction entered into under this Service
Agreement shall be subject to the terms and
conditions of Part II of the Transmission
Provider’s Tariff, except for those terms and
conditions negotiated by the Reseller, as
identified below, of the reassigned
transmission capacity (pursuant to Section
23.1 of this Tariff) and the Assignee and
appropriately specified in this Service
Agreement. Such negotiated terms and
conditions include: contract effective and
termination dates, the amount of reassigned
capacity or energy, point(s) of receipt and
delivery. Changes by the Assignee to the
Reseller’s Points of Receipt and Points of
Delivery will be subject to the provisions of
Section 23.2 of this Tariff.
4.0 The Transmission Provider shall
credit or charge the Reseller, as appropriate,
for any difference between the price reflected
in the Assignee’s Service Agreement and the
Reseller’s Service Agreement with the
Transmission Provider.
5.0 Any notice or request made to or by
either Party regarding this Service Agreement
shall be made to the representative of the
other Party as indicated below.
Transmission Provider:
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
Assignee:
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
6.0 The Tariff is incorporated herein and
made a part hereof.
IN WITNESS WHEREOF, the Parties have
caused this Service Agreement to be executed
by their respective authorized officials.
Transmission Provider:
By:
lllllllllllllllllllll
Name
lllllllllllllllllllll
Title
lllllllllllllllllllll
Date
Assignee:
By:
lllllllllllllllllllll
Name
lllllllllllllllllllll
Title
lllllllllllllllllllll
Date
Specifications for the Resale, Reassignment
or Transfer of Long-Term Firm Point-to-Point
Transmission Service
1.0 Term of Transaction: llllllll
Start Date:
lllllllllllllll
Termination Date: llllllllllll
2.0 Description of capacity and energy to be
transmitted by Transmission Provider including the electric Control Area in which the
transaction originates. llllllllll
lllllllllllllllllllll
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Jkt 211001
3.0 Point(s) of Receipt: lllllllll
Delivering Party: lllllllllllll
4.0 Point(s) of Delivery: lllllllll
Receiving Party: lllllllllllll
5.0 Maximum amount of reassigned capacity: lllllllllllllllllll
6.0 Designation of party(ies) subject to reciprocal service obligation: llllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
7.0 Name(s) of any Intervening Systems
providing transmission service: llllll
lllllllllllllllllllll
8.0 Service under this Agreement may be
subject to some combination of the charges
detailed below. (The appropriate charges for
individual transactions will be determined in
accordance with the terms and conditions of
the Tariff.)
8.1 Transmission Charge: llllllll
lllllllllllllllllllll
8.2 System Impact and/or Facilities Study
Charge(s):
lllllllllllllllllllll
lllllllllllllllllllll
8.3 Direct Assignment Facilities Charge: l
lllllllllllllllllllll
8.4 Ancillary Services Charges: lllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
9.0 Name of Reseller of the reassigned
transmission capacity:
lllllllllllllllllllll
Attachment B—Form of Service Agreement
for Non-Firm Point-to-Point Transmission
Service
1.0 This Service Agreement, dated as of
llll, is entered into, by and between
llll (the Transmission Provider), and
llll (Transmission Customer).
2.0 The Transmission Customer has been
determined by the Transmission Provider to
be a Transmission Customer under Part II of
the Tariff and has filed a Completed
Application for Non-Firm Point-To-Point
Transmission Service in accordance with
Section 18.2 of the Tariff.
3.0 Service under this Agreement shall be
provided by the Transmission Provider upon
request by an authorized representative of the
Transmission Customer.
4.0 The Transmission Customer agrees to
supply information the Transmission
Provider deems reasonably necessary in
accordance with Good Utility Practice in
order for it to provide the requested service.
5.0 The Transmission Provider agrees to
provide and the Transmission Customer
agrees to take and pay for Non-Firm PointTo-Point Transmission Service in accordance
with the provisions of Part II of the Tariff and
this Service Agreement.
6.0 Any notice or request made to or by
either Party regarding this Service Agreement
PO 00000
Frm 00266
Fmt 4701
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shall be made to the representative of the
other Party as indicated below.
Transmission Provider:
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
Transmission Customer:
lllllllllllllllllllll
lllllllllllllllllllll
lllllllllllllllllllll
7.0 The Tariff is incorporated herein and
made a part hereof.
IN WITNESS WHEREOF, the Parties have
caused this Service Agreement to be executed
by their respective authorized officials.
Transmission Provider:
By:
lllllllllllllllllllll
Name
lllllllllllllllllllll
Title
lllllllllllllllllllll
Date
Transmission Customer:
By:
lllllllllllllllllllll
Name
lllllllllllllllllllll
Title
lllllllllllllllllllll
Date
Attachment C—Methodology To Assess
Available Transfer Capability
The Transmission Provider must include,
at a minimum, the following information
concerning its ATC calculation methodology:
(1) A detailed description of the specific
mathematical algorithm used to calculate
firm and non-firm ATC (and AFC, if
applicable) for its scheduling horizon (same
day and real-time), operating horizon (day
ahead and pre-schedule) and planning
horizon (beyond the operating horizon);
(2) A process flow diagram that illustrates
the various steps through which ATC/AFC is
calculated; and
(3) A detailed explanation of how each of
the ATC components is calculated for both
the operating and planning horizons.
(a) For TTC, a Transmission Provider shall:
(i) explain its definition of TTC; (ii) explain
its TTC calculation methodology; (iii) list the
databases used in its TTC assessments; and
(iv) explain the assumptions used in its TTC
assessments regarding load levels, generation
dispatch, and modeling of planned and
contingency outages.
(b) For ETC, a transmission provider shall
explain: (i) its definition of ETC; (ii) the
calculation methodology used to determine
the transmission capacity to be set aside for
native load (including network load), and
non-OATT customers (including, if
applicable, an explanation of assumptions on
the selection of generators that are modeled
in service); (iii) how point-to-point
transmission service requests are
incorporated; (iv) how rollover rights are
accounted for; and (v) its processes for
ensuring that non-firm capacity is released
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properly (e.g., when real time schedules
replace the associated transmission service
requests in its real-time calculations).
(c) If a Transmission Provider uses an AFC
methodology to calculate ATC, it shall:
(i) explain its definition of AFC; (ii)
explain its AFC calculation methodology;
(iii) explain its process for converting AFC
into ATC for OASIS posting; (iv) list the
databases used in its AFC assessments; and
(v) explain the assumptions used in its AFC
assessments regarding load levels, generation
dispatch, and modeling of planned and
contingency outages.
(d) For TRM, a Transmission Provider shall
explain: (i) its definition of TRM; (ii) its TRM
calculation methodology (e.g., its
assumptions on load forecast errors, forecast
errors in system topology or distribution
factors and loop flow sources); (iii) the
databases used in its TRM assessments; (iv)
the conditions under which the transmission
provider uses TRM. A Transmission Provider
that does not set aside transfer capability for
TRM must so state.
(e) For CBM, the Transmission Provider
shall state include a specific and selfcontained narrative explanation of its CBM
practice, including: (i) an identification of the
entity who performs the resource adequacy
analysis for CBM determination; (ii) the
methodology used to perform generation
reliability assessments (e.g., probabilistic or
deterministic); (iii) an explanation of whether
the assessment method reflects a specific
regional practice; (iv) the assumptions used
in this assessment; and (v) the basis for the
selection of paths on which CBM is set aside.
(f) In addition, for CBM, a Transmission
Provider shall: (i) explain its definition of
CBM; (ii) list the databases used in its CBM
calculations; and (iii) demonstrate that there
is no double-counting of contingency outages
when performing CBM, TTC, and TRM
calculations.
(g) The Transmission Provider shall
explain its procedures for allowing the use of
CBM during emergencies (with an
explanation of what constitutes an
emergency, the entities that are permitted to
use CBM during emergencies and the
procedures which must be followed by the
transmission providers’ merchant function
and other load-serving entities when they
need to access CBM). If the Transmission
Provider’s practice is not to set aside transfer
capability for CBM, it shall so state.
Attachment D—Methodology for Completing
a System Impact Study
To be filed by the Transmission Provider
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Attachment E—Index of Point-To-Point
Transmission Service Customers
Customer
Date of Service Agreement
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Jkt 211001
Attachment F—Service Agreement for
Network Integration Transmission Service
To be filed by the Transmission Provider
Attachment G—Network Operating
Agreement
To be filed by the Transmission Provider
Attachment H—Annual Transmission
Revenue Requirement for Network
Integration Transmission Service
1. The Annual Transmission Revenue
Requirement for purposes of the Network
Integration Transmission Service shall be
llll.
2. The amount in (1) shall be effective until
amended by the Transmission Provider or
modified by the Commission.
Attachment I—Index of Network Integration
Transmission Service Customers
Customer
Date of Service Agreement
Attachment J—Procedures for Addressing
Parallel Flows
To be filed by the Transmission Provider
Attachment K—Transmission Planning
Process
The Transmission Provider shall establish
a coordinated, open and transparent planning
process with its Network and Firm Point-toPoint Transmission Customers and other
interested parties, including the coordination
of such planning with interconnected
systems within its region, to ensure that the
Transmission System is planned to meet the
needs of both the Transmission Provider and
its Network and Firm Point-to-Point
Transmission Customers on a comparable
and nondiscriminatory basis. The
Transmission Provider’s coordinated, open
and transparent planning process shall be
provided as an attachment to the
Transmission Provider’s Tariff.
The Transmission Provider’s planning
process shall satisfy the following nine
principles, as defined in the Final Rule in
Docket No. RM05–25–000: coordination,
openness, transparency, information
exchange, comparability, dispute resolution,
regional participation, economic planning
studies, and cost allocation for new projects.
The planning process shall also provide a
mechanism for the recovery and allocation of
planning costs consistent with the Final Rule
in Docket No. RM05–25–000.
The Transmission Provider’s planning
process must include sufficient detail to
enable Transmission Customers to
understand:
(i) The process for consulting with
customers and neighboring transmission
providers;
(ii) The notice procedures and anticipated
frequency of meetings;
PO 00000
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12531
(iii) The methodology, criteria, and
processes used to develop transmission
plans;
(iv) The method of disclosure of criteria,
assumptions and data underlying
transmission system plans;
(v) The obligations of and methods for
customers to submit data to the transmission
provider;
(vi) The dispute resolution process;
(vii) The transmission provider’s study
procedures for economic upgrades to address
congestion or the integration of new
resources; and
(viii) The relevant cost allocation
procedures or principles.
Attachment L—Creditworthiness Procedures
For the purpose of determining the ability
of the Transmission Customer to meet its
obligations related to service hereunder, the
Transmission Provider may require
reasonable credit review procedures. This
review shall be made in accordance with
standard commercial practices and must
specify quantitative and qualitative criteria to
determine the level of secured and unsecured
credit.
The Transmission Provider may require the
Transmission Customer to provide and
maintain in effect during the term of the
Service Agreement, an unconditional and
irrevocable letter of credit as security to meet
its responsibilities and obligations under the
Tariff, or an alternative form of security
proposed by the Transmission Customer and
acceptable to the Transmission Provider and
consistent with commercial practices
established by the Uniform Commercial Code
that protects the Transmission Provider
against the risk of non-payment.
Additionally, the Transmission Provider
must include, at a minimum, the following
information concerning its creditworthiness
procedures:
(1) a summary of the procedure for
determining the level of secured and
unsecured credit;
(2) a list of the acceptable types of
collateral/security;
(3) a procedure for providing customers
with reasonable notice of changes in credit
levels and collateral requirements;
(4) a procedure for providing customers,
upon request, a written explanation for any
change in credit levels or collateral
requirements;
(5) a reasonable opportunity to contest
determinations of credit levels or collateral
requirements; and
(6) a reasonable opportunity to post
additional collateral, including curing any
non-creditworthy determination.
[FR Doc. E7–3636 Filed 3–14–07; 8:45 am]
BILLING CODE 6717–01–P
E:\FR\FM\15MRR2.SGM
15MRR2
Agencies
[Federal Register Volume 72, Number 50 (Thursday, March 15, 2007)]
[Rules and Regulations]
[Pages 12266-12531]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E7-3636]
[[Page 12265]]
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Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Parts 35 and 37
Preventing Undue Discrimination and Preference in Transmission Service;
Final Rule
Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules
and Regulations
[[Page 12266]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Parts 35 and 37
[Docket Nos. RM05-17-000 and RM05-25-000; Order No. 890]
Preventing Undue Discrimination and Preference in Transmission
Service
Issued February 16, 2007.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission is amending the
regulations and the pro forma open access transmission tariff adopted
in Order Nos. 888 and 889 to ensure that transmission services are
provided on a basis that is just, reasonable and not unduly
discriminatory or preferential. The final rule is designed to:
Strengthen the pro forma open-access transmission tariff, or OATT, to
ensure that it achieves its original purpose of remedying undue
discrimination; provide greater specificity to reduce opportunities for
undue discrimination and facilitate the Commission's enforcement; and
increase transparency in the rules applicable to planning and use of
the transmission system.
EFFECTIVE DATE: This rule will become effective May 14, 2007.
FOR FURTHER INFORMATION CONTACT: Daniel Hedberg (Technical
Information), Office of Energy Markets and Reliability, Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202) 502-6243.
W. Mason Emnett (Legal Information), Office of the General
Counsel--Energy Markets, Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426, (202) 502-6540.
Kathleen Barr[oacute]n (Legal Information), Office of the General
Counsel--Energy Markets, Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426, (202) 502-6461.
SUPPLEMENTARY INFORMATION:
Paragraph
Table of Contents Nos.
I. Introduction............................................. 1
II. Background.............................................. 9
A. Historical Antecedent................................ 9
B. Order No. 888 and Subsequent Reforms................. 14
C. EPAct 2005 and Recent Developments................... 22
III. Need for Reform of Order No. 888....................... 26
A. Opportunities for Undue Discrimination Continue to 26
Exist..................................................
B. Lack of Transparency Undermines Confidence in Open 44
Access and Impedes Enforcement of Open Access
Requirements...........................................
C. Congestion and Inadequate Infrastructure Development 52
Impede Customers' Use of the Grid......................
D. A Consistent Method of Measuring ATC Is Needed....... 62
E. Discriminatory Pricing of Imbalances................. 70
F. Redispatch/Conditional Firm.......................... 73
G. EPAct 2005 Emphasized Certain Policies and Priorities 79
for the Commission.....................................
IV. Summary, Scope and Applicability of the Final Rule...... 82
A. Summary of Reforms................................... 83
B. Core Elements of Order No. 888 That Are Retained..... 91
1. Federal/State Jurisdiction....................... 92
2. Native Load Protection........................... 95
3. The Types of Transmission Services Offered....... 110
4. Functional Unbundling............................ 117
C. Applicability of the Final Rule...................... 124
1. Non-ISO/RTO Public Utility Transmission Providers 124
2. ISO and RTO Public Utility Transmission Providers 143
and Transmission Owner Members of ISOs and RTOs....
3. Non-Public Utility Transmission Providers/ 162
Reciprocity........................................
V. Reforms of the OATT...................................... 193
A. Consistency and Transparency of ATC Calculations..... 193
B. Coordinated, Open and Transparent Planning........... 418
C. Transmission Pricing................................. 603
1. General.......................................... 603
2. Energy and Generation Imbalances................. 627
3. Credits for Network Customers.................... 729
4. Capacity Reassignment............................ 778
5. ``Operational'' Penalties........................ 826
a. Unreserved Use Penalties..................... 826
b. Distribution of Operational Penalties........ 850
c. Applicability of Operational Penalties 866
Proposal to RTOs and Other Independent or Non-
Profit Entities................................
6. ``Higher of'' Pricing Policy..................... 870
7. Other Ancillary Services......................... 886
D. Non-Rate Terms and Conditions........................ 901
1. Modifications to Long-Term Firm Point-to-Point 901
Service............................................
a. Planning Redispatch and Conditional Firm 901
Options........................................
b. Proposals for Transparent Redispatch......... 1095
c. Other Requested Service Modifications........ 1165
2. Hourly Firm Service.............................. 1177
3. Rollover Rights.................................. 1214
4. Modification of Receipt or Delivery Points....... 1268
5. Acquisition of Transmission Service.............. 1296
a. Processing of Service Requests............... 1296
b. Reservation Priority......................... 1394
6. Designation of Network Resources................. 1432
a. Qualification as a Network Resource.......... 1432
[[Page 12267]]
b. Documentation for Network Resources.......... 1507
c. Undesignation of Network Resources........... 1534
7. Clarifications Related to Network Service........ 1592
a. Secondary Network Service.................... 1592
b. Behind the Meter Generation.................. 1614
8. Transmission Curtailments........................ 1620
9. Standardization of Rules and Practices........... 1633
a. Business Practices........................... 1633
b. Liability and Indemnification................ 1662
10. OATT Definitions................................ 1678
E. Enforcement.......................................... 1714
1. General Policy................................... 1715
2. Civil Penalties.................................. 1724
VI. Information Collection Statement........................ 1752
VII. Environmental Analysis................................. 1758
VIII. Regulatory Flexibility Act Analysis................... 1759
IX. Document Availability................................... 1760
X. Effective Date and Congressional Notification............ 1763
Appendix A: Summary of Compliance Filing Requirements
Appendix B: Commenting Party Acronyms
Appendix C: Pro Forma Open Access Transmission Tariff
Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly,
Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.
I. Introduction
1. This Final Rule addresses and remedies opportunities for undue
discrimination under the pro forma Open Access Transmission Tariff
(OATT) adopted in 1996 by Order No. 888.\1\ This landmark rulemaking
fostered greater competition in wholesale power markets by reducing
barriers to entry in the provision of transmission service. In the ten
years since Order No. 888, however, the Commission has found that the
OATT contains flaws that undermine realizing its core objective of
remedying undue discrimination. In the Notice of Proposed Rulemaking
(NOPR) issued on May 19, 2006, the Commission proposed to remedy those
flaws.\2\ After receiving approximately 6,500 pages of comments from
close to 300 parties, we now take final action. We highlight below the
most critical reforms being adopted today.
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\1\ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. Sec.
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar.
14, 1997), FERC Stats. & Regs. Sec. 31,048 (1997), order on reh'g,
Order No. 888-B, 81 FERC Sec. 61,248 (1997), order on reh'g, Order
No. 888-C, 82 FERC Sec. 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000) (TAPS v. FERC), aff'd sub nom. New York v. FERC,
535 U.S. 1 (2002).
\2\ Preventing Undue Discrimination and Preference in
Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,636
(Jun. 6, 2006), FERC Stats. & Regs. Sec. 32,603 (2006).
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2. First, the Final Rule will increase nondiscriminatory access to
the grid by eliminating the wide discretion that transmission providers
currently have in calculating available transfer capability (ATC).\3\
The calculation of ATC is one of the most critical functions under the
OATT because it determines whether transmission customers can access
alternative power supplies. Despite this, the existing OATT does not
prescribe how ATC should be calculated because the Commission sought to
rely on voluntary efforts by the industry to develop consistent methods
of ATC calculation. This voluntary industry effort has not proven
successful. The Commission therefore acts today to require public
utilities, working through the North American Electric Reliability
Corporation (NERC), to develop consistent methodologies for ATC
calculation and to publish those methodologies to increase
transparency. This important reform will eliminate the wide discretion
that exists today in calculating ATC and ensure that customers are
treated fairly in seeking alternative power supplies.
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\3\ The Commission used the term ``Available Transmission
Capability'' in Order No. 888 to describe the amount of additional
capability available in the transmission network to accommodate
additional requests for transmission services. To be consistent with
the term generally accepted throughout the industry, the Commission
revises the pro forma OATT to adopt the term ``Available Transfer
Capability.''
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3. Second, the Final Rule will increase the ability of customers to
access new generating resources and promote efficient utilization of
transmission by requiring an open, transparent, and coordinated
transmission planning process. Transmission planning is a critical
function under the pro forma OATT because it is the means by which
customers consider and access new sources of energy and have an
opportunity to explore the feasibility of non-transmission
alternatives. Despite this, the existing pro forma OATT provides
limited guidance regarding how transmission customers are treated in
the planning process and provides them very little information on how
transmission plans are developed. These deficiencies are serious, given
the substantial need for new infrastructure in this Nation.\4\ We act
today to remedy these deficiencies by requiring transmission providers
to open their transmission planning process to customers, coordinate
with customers regarding future system plans, and share necessary
planning information with customers.
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\4\ Congress placed special emphasis on the development of
transmission infrastructure, including the consideration of advanced
transmission technologies, in the Energy Policy Act of 2005 (EPAct
2005). See Pub. L. 109-58, 119 Stat. 594 (to be codified in
scattered titles of the U.S.C.). The Commission has taken steps to
implement that goal in numerous contexts, including recent
rulemaking proceedings that address the promotion of transmission
investment through pricing reform and the siting of certain
transmission facilities. See Promoting Transmission Investment
through Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 31, 2006),
FERC Stats. & Regs. Sec. 31,222 (2006), order on reh'g, Order No.
679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. Sec. 31,236
(2007), reh'g pending; Regulations for Filing Applications for
Permits to Site Interstate Electric Transmission Facilities, Order
No. 689, 71 FR 69440 (Dec. 1, 2006), FERC Stats. & Regs. Sec.
31,234 (2006), reh'g pending. As discussed herein, several actions
taken in this Final Rule also relate to the need for investments in
transmission infrastructure and are consistent with the Commission's
responsibilities under EPAct 2005.
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4. Third, the Final Rule will also increase the efficient
utilization of
[[Page 12268]]
transmission by eliminating artificial barriers to use of the grid. The
existing pro forma OATT allows a transmission provider to deny a
request for long-term point-to-point service if the request cannot be
satisfied in only one hour of the requested term. This practice
discourages the efficient use of the existing grid and precludes access
to alternative power supplies. We reform this practice by requiring
that a conditional firm option be offered to customers seeking long-
term point-to-point service, i.e., conditional firm service. We also
modify the redispatch obligations of transmission providers to increase
the efficient utilization of the grid, while also ensuring that
reliability to native load customers is maintained.
5. Fourth, by adopting these and other reforms, the Final Rule
facilitates the use of clean energy resources such as wind power.
Conditional firm service is particularly important to wind resources
that can provide significant economic and environmental value even if
curtailed under limited circumstances. Open and coordinated
transmission planning will enhance the ability of customers to access
clean energy resources as part of their future resource portfolio. The
Final Rule also benefits clean energy resources by reforming energy and
generator imbalance charges. These reforms are particularly important
to intermittent resources such as wind power because these resources
have limited ability to control their output and, hence, must be
assured that imbalance charges are no more than required to provide
appropriate incentives for prudent behavior.
6. Fifth, the Final Rule will strengthen compliance and enforcement
efforts. We are increasing the transparency of pro forma OATT
administration, thereby increasing the ability of customers and our
Office of Enforcement to detect undue discrimination. We are adopting
operational penalties for clear violations of an OATT, thereby
enhancing compliance while also reducing the burdens on our Office of
Enforcement. We are also increasing the clarity of many other OATT
requirements, thereby facilitating compliance by transmission providers
with our regulations. This Final Rule thus reflects the close
integration of our Office of Enforcement into policy development at the
Commission. Several of the reforms we adopt today are informed by our
experience with OATT administration through oversight, audits, and
investigations performed by the Office of Enforcement.
7. Finally, we modify and improve several provisions of the pro
forma OATT using our experience over the past ten years and clarify
others that have proven ambiguous. For example, we reform our rollover
rights policy to ensure that the rights and obligations of rollover
customers are consistent with the resulting obligations of transmission
providers to plan and upgrade the system to accommodate rollovers. We
remove the price cap on reassigned capacity because it is not necessary
to remedy market power and doing so will otherwise increase the
efficient use of existing capacity. We increase the efficient use of
existing capacity by providing a priority to certain ``pre-confirmed''
requests for service. We increase certainty by providing greater
clarity regarding the wholesale contracts that qualify as network
resources. We also adopt numerous clarifications that should assist
transmission providers and customers in implementing and using the pro
forma OATT
8. Our actions in this proceeding have been informed to a great
extent by the comments received in response to our notices of inquiry
in the above-captioned dockets and the subsequent NOPR.\5\ We
appreciate the time and thoughtfulness of all sectors of the industry
in preparing comments. We have found them very informative and useful
in reaching our decisions in this Final Rule.
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\5\ Preventing Undue Discrimination and Preference in
Transmission Services, Notice of Inquiry, 112 FERC ] 61,299 (2005)
(NOI); Information Requirements for Available Transfer Capability,
Notice of Inquiry, 111 FERC ] 61,274 (2005) (ATC NOI).
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II. Background
A. Historical Antecedent
9. In the NOPR, the Commission explained the historical background
that led up to the issuance of Order No. 888, and the initiation of
this rulemaking proceeding. We repeat that history here to place in
context the actions we take today.
10. In the first few decades after enactment of the Federal Power
Act (FPA) in 1935, the industry was characterized mostly by self-
sufficient, vertically integrated electric utilities, in which
generation, transmission, and distribution facilities were owned by a
single entity and sold as part of a bundled service to wholesale and
retail customers. Most electric utilities built their own power plants
and transmission systems, entered into interconnection and coordination
arrangements with neighboring utilities, and entered into long-term
contracts to make wholesale requirements sales (bundled sales of
generation and transmission) to municipal, cooperative, and investor-
owned utilities connected to each utility's transmission system. Each
system covered a limited service area, which was defined by the retail
franchise decisions of State regulatory agencies. This structure of
separate systems arose naturally primarily due to cost and the
technological limitations on the distance over which electricity could
be transmitted.
11. A number of statutory, economic, and technological developments
in the 1970s led to an increase in coordinated operations and
competition. Among those was the passage of the Public Utility
Regulatory Policies Act of 1978 (PURPA),\6\ which was designed to
lessen dependence on foreign fossil fuels by encouraging the
development of alternative generation sources and imposing a mandatory
purchase obligation on utilities for generation from such sources.
PURPA also enabled the Commission to order wheeling of electricity
under limited circumstances.\7\ The rapid expansion and performance of
the independent power industry following the enactment of PURPA
demonstrated that traditional, vertically integrated public utilities
need not be the only sources of reliable power. During this period, the
profile of generation investment began to change, and a market for non-
traditional power supply beyond the purchases required by PURPA began
to emerge. The economic and technological changes in the transmission
and generation sectors helped encourage many new entrants in the
generating markets that could sell electric energy profitably with
smaller scale technology at a lower price than many utilities selling
from their existing generation facilities at rates reflecting cost.
However, it became increasingly clear that the potential consumer
benefits that could be derived from these technological advances could
be realized only if more efficient generating plants could obtain
access to the regional transmission grids. Because many traditional
vertically integrated utilities still did not provide open access to
third parties and favored their own generation if and when they
[[Page 12269]]
provided transmission access to third parties, access to cheaper, more
efficient generation sources remained limited.
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\6\ Pub. L. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C.
titles 15, 16, 26, 30, 42, and 43).
\7\ Section 211 of the FPA, 16 U.S.C. 824j. In earlier years, a
few customers were able to obtain access as a result of litigation,
beginning with the U.S. Supreme Court's decision in Otter Tail Power
Company v. United States, 410 U.S. 366 (1973). Additionally, some
customers gained access by virtue of Nuclear Regulatory Commission
license conditions and voluntary preference power transmission
arrangements associated with Federal power marketing agencies. See,
e.g., Consumers Power Co., 6 NRC 887, 1036-44 (1977); Toledo Edison
Co., 10 NRC 265, 327-34 (1979); Florida Municipal Power Agency v.
Florida Power and Light Co., 839 F. Supp. 1563 (M.D. Fla. 1993).
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12. The Commission encouraged the development of independent power
producers (IPPs), as well as emerging power marketers, by authorizing
market-based rates for their power sales on a case-by-case basis, and
by encouraging more widely available transmission access on a case-by-
case basis. Market-based rates helped to develop competitive bulk power
markets by allowing generating utilities to move more quickly and
flexibly to take advantage of short-term or even long-term market
opportunities than those utilities operating under traditional cost-of-
service tariffs. In approving these market-based rates, the Commission
required that the seller and its affiliates lack market power or
mitigate any market power that they may have had.\8\ The major concern
of the Commission was whether the seller or its affiliates could limit
competition and thereby drive up prices. A key inquiry became whether
the seller or its affiliates owned or controlled transmission
facilities in the relevant service area and therefore, by denying
access or imposing discriminatory terms or conditions on transmission
service, could foreclose other generators from competing. Beginning in
the late 1980s, in order to mitigate their market power to meet the
Commission's conditions, public utilities seeking Commission
authorization for blanket approval of market-based rates for generation
services under section 205 of the FPA filed ``open access''
transmission tariffs of general applicability.\9\ The Commission also
approved proposed mergers under section 203 of the FPA on the condition
that the merging companies remedy anticompetitive effects potentially
caused by the merger by filing ``open access'' tariffs. The early
tariffs submitted in market-based rate proceedings under section 205
and merger proceedings under section 203 did not, however, provide
access to the transmission system that was comparable to the service
the transmission providers used for their own purposes. Rather, they
typically made available only point-to-point transmission service,
i.e., service from a single point of receipt to a single point of
delivery. As these early tariffs were offered only by transmission
providers that volunteered to provide service to third parties, they
resulted in a patchwork of open access that was not sufficient to
facilitate wholesale generation markets.
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\8\ See, e.g., Dartmouth Power Associates Limited Partnership,
53 FERC ] 61,117 (1990); Commonwealth Atlantic Limited Partnership,
51 FERC ] 61,368 (1990); Doswell Limited Partnership, 50 FERC ]
61,251 (1990); Citizens Power & Light Co., 48 FERC ] 61,210 (1989);
Ocean State Power, 44 FERC ] 61,261 (1988); and Orange and Rockland
Utilities, Inc., 42 FERC ] 61,012 (1988).
\9\ See Order No. 888 at 31,644 n.52.
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13. In response to the competitive developments following PURPA,
and the fact that limited transmission access and significant
regulatory barriers continued to constrain the development of
generation by independent power producers, Congress enacted Title VII
of the Energy Policy Act of 1992 (EPAct 1992).\10\ EPAct 1992 reduced
regulatory barriers to entry by creating a class of ``Exempt Wholesale
Generators'' that were exempt from the requirements of the Public
Utility Holding Company Act of 1935.\11\ EPAct 1992 also expanded the
Commission's authority to approve applications for transmission
services under sections 211 and 212 of the FPA.\12\ Though the
Commission aggressively implemented expanded section 211, it ultimately
concluded that the procedural limitations in section 211 thwarted the
Commission's ability to effectively eliminate undue discrimination in
the provision of transmission service.
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\10\ Pub. L. 102-486, 106 Stat. 2776 (1992) (codified at, among
other places, 15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25), 824j-l).
\11\ 15 U.S.C. 79a, repealed by EPAct 2005 sec. 1263; see Repeal
of the Public Utility Holding Company Act of 1935 and Enactment of
the Public Utility Holding Company Act of 2005, Order No. 667, 70 FR
75592 (Dec. 20, 2005), FERC Stats. & Regs. ] 31,197 (2005), order on
reh'g, Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. &
Regs. ] 31,213 (2006), order on reh'g, Order No. 667-B, 71 FERC
42750 (Jul. 28, 2006), FERC Stats. & Regs. ] 31,224 (2006), reh'g
pending.
\12\ 16 U.S.C. 824j (authorizing the Commission to require
transmission utilities to provide service in certain circumstances);
16 U.S.C. 824k (establishing rates for service provided pursuant to
an order under section 211).
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B. Order No. 888 and Subsequent Reforms
14. In April 1996, as part of its statutory obligation under
sections 205 and 206 of the FPA to remedy undue discrimination, the
Commission adopted Order No. 888 prohibiting public utilities from
using their monopoly power over transmission to unduly discriminate
against others. In that order, the Commission required all public
utilities that own, control or operate facilities used for transmitting
electric energy in interstate commerce to file open access non-
discriminatory transmission tariffs that contained minimum terms and
conditions of non-discriminatory service. It also obligated such public
utilities to ``functionally unbundle'' their generation and
transmission services. This meant public utilities had to take
transmission service (including ancillary services) for their own new
wholesale sales and purchases of electric energy under the open access
tariffs, and to separately state their rates for wholesale generation,
transmission and ancillary services.\13\ Each public utility was
required to file the pro forma OATT included in Order No. 888 without
any deviation (except a limited number of terms and conditions that
reflect regional practices).\14\ After the effectiveness of their
OATTs, public utilities were allowed to file, pursuant to section 205
of the FPA, deviations that were consistent with or superior to the pro
forma OATT's terms and conditions. Because certain owners, controllers
or operators of interstate transmission facilities were not subject to
the Commission's jurisdiction under sections 205 and 206 and thus were
not subject to Order No. 888, the Commission adopted a reciprocity
provision in the pro forma OATT that conditions the use by a non-public
utility of a public utility's open access services on an agreement to
offer non-discriminatory transmission services in return.
---------------------------------------------------------------------------
\13\ This is known as ``functional unbundling'' because the
transmission element of a wholesale sale is separated or unbundled
from the generation element of that sale, although the public
utility may provide both functions. See infra section IV.B.4 of this
Final Rule.
\14\ See Order No. 888 at 31,769-70 (noting that the pro forma
OATT expressly identified certain non-rate terms and conditions,
such as the time deadlines for determining available transfer
capability in section 18.4 or scheduling changes in sections 13.8
and 14.6, that may be modified to account for regional practices if
such practices are reasonable, generally accepted in the region, and
consistently adhered to by the transmission provider).
---------------------------------------------------------------------------
15. In addition to imposing the functional unbundling requirement,
the Commission also encouraged broader reforms through the formation of
independent system operators (ISOs). The Commission stated that ISOs
can provide significant benefits such as enhancing regional
efficiencies and further remedying undue discrimination.\15\ While the
Commission declined to mandate ISOs, it set forth eleven principles for
assessing ISO proposals submitted to the Commission.\16\
---------------------------------------------------------------------------
\15\ Order No. 888 at 31,655.
\16\ Id. at 31,730-32.
---------------------------------------------------------------------------
16. Order No. 888 also clarified the Commission's interpretation of
the Federal and State jurisdictional boundaries over transmission and
local distribution. While Order No. 888 reaffirmed that the Commission
has exclusive jurisdiction over the rates,
[[Page 12270]]
terms, and conditions of unbundled retail transmission in interstate
commerce by public utilities, it nevertheless recognized the legitimate
concerns of State regulatory authorities regarding the transmission
component of bundled retail sales. The Commission therefore declined to
extend its unbundling requirement to the transmission component of
bundled retail sales. On appeal, the U.S. Supreme Court affirmed this
element of Order No. 888, finding that the Commission made a
statutorily permissible choice.\17\
---------------------------------------------------------------------------
\17\ New York v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------
17. The same day it issued Order No. 888, the Commission issued a
companion order, Order No. 889,\18\ addressing the separation of
vertically integrated utilities' transmission and merchant functions,
the information transmission providers were required to make public,
and the electronic means they were required to use to do so. Order No.
889 imposed Standards of Conduct governing the separation of, and
communications between, the utility's transmission and wholesale power
functions, to prevent the utility from giving its merchant arm
preferential access to transmission information. All public utilities
that owned, controlled or operated facilities used in the transmission
of electric energy in interstate commerce were required to create or
participate in an Open Access Same-Time Information System (OASIS) that
was to provide existing and potential transmission customers the same
access to transmission information.
---------------------------------------------------------------------------
\18\ Open Access Same-Time Information System (Formerly Real-
Time Information Networks) and Standards of Conduct, Order No. 889,
61 FR 21737 (May 10, 1996), FERC Stats. & Regs. ] 31,035 (1996),
order on reh'g, Order No. 889-A, FERC Stats. & Regs. ] 31,049
(1997), order on reh'g, Order No. 889-B, 81 FERC ] 61,253 (1997).
---------------------------------------------------------------------------
18. Among the information public utilities were required to post on
their OASIS was the transmission provider's calculation of ATC. Though
the Commission acknowledged that before-the-fact measurement of the
availability of transmission service is ``difficult,'' it concluded
that it was important to give potential transmission customers ``an
easy-to-understand indicator of service availability.'' \19\ Because
formal methods did not then exist to calculate ATC and total transfer
capability (TTC), the Commission encouraged industry efforts to develop
consistent methods for calculating ATC and TTC.\20\ Order No. 889
ultimately required transmission providers to base their calculations
on ``current industry practices, standards and criteria'' and to
describe their methodology in their tariffs.\21\ The Commission noted
that the requirement that transmission providers purchase only ATC that
is posted as available ``should create an adequate incentive for them
to calculate ATC and TTC as accurately and as uniformly as possible.''
\22\
---------------------------------------------------------------------------
\19\ Order No. 889 at 31,605.
\20\ Id. at 31,607.
\21\ Id.
\22\ Id.
---------------------------------------------------------------------------
19. The electric industry continued to undergo economic and
regulatory changes in the years following the issuance of Order No.
888. Retail access was adopted by approximately 25 states in the late
1990s.\23\ This State restructuring activity spurred significant
changes at the wholesale level as well by encouraging or requiring the
divestiture of generation plants by traditional electric utilities and
the development of ISOs that could manage short-term energy markets
necessary to support retail access. At the same time, there was a
significant increase in the number of mergers between traditional
electric utilities and between electric utilities and gas pipeline
companies, and large increases in the number of power marketers and
independent generation facility developers entering the marketplace.
Trade in bulk power markets increased significantly and the Nation's
transmission grid was used more heavily and in new ways as customers
took advantage of the pro forma OATT and purchased power from
competitive sellers.
---------------------------------------------------------------------------
\23\ See Energy Information Administration, Retail Unbundling--
U.S. Summary (2005), https://www.eia.doe.gov/oil_gas/natural_gas/
restructure/state/us.html.
---------------------------------------------------------------------------
20. In the wake of these changes, in December 1999, the Commission
adopted Order No. 2000.\24\ That rulemaking recognized that Order No.
888 set the foundation upon which competitive electric markets could
develop, but did not eliminate the potential to engage in undue
discrimination and preference in the provision of transmission
service.\25\ The rulemaking also recognized that Order No. 888 did not
address the regional nature of the grid, including the treatment of
parallel flows, pancaked rates, and congestion management. Thus, the
Commission encouraged the creation of RTOs to address important
operational and reliability issues and eliminate any residual
discrimination in transmission services that can occur when the
operation of the transmission system remains in the control of a
vertically integrated utility. The Commission found that RTOs would
increase the efficiency of wholesale markets by eliminating pancaked
rates, internalizing parallel flow, managing congestion efficiently,
and operating markets for energy, capacity and ancillary services. The
Commission established an open, collaborative process that relied on
voluntary regional participation to design RTOs tailored to the
specific needs of each region. The Commission noted, however, that
``[i]f the industry fails to form RTOs under this approach, the
Commission will reconsider what further regulatory steps are in the
public interest.''\26\
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\24\ Regional Transmission Organizations, Order No. 2000, 65 FR
809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 (1999), order on
reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. &
Regs. ] 31,092 (2000), aff'd sub nom. Public Utility District No. 1
of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir.
2001).
\25\ Order No. 2000 at 31,015.
\26\ Id. at 30,993.
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21. Following Order No. 2000, RTOs were approved in several regions
of the country including the Northeast (PJM; ISO New England),\27\ the
Midwest (MISO) and the South (SPP). In most cases, RTOs have assumed
responsibility for calculating ATC across the footprint of the RTO, as
well as the planning and expansion of the transmission grid, at least
for facilities necessary for maintaining system reliability. However,
large areas of the Nation have not developed RTOs using the voluntary
structure adopted by the Commission in Order No. 2000. Moreover,
transmission customers have complained that even in RTO markets there
are instances when comparable transmission service is not provided,
particularly in the area of transmission planning.
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\27\ A list of commenter acronyms can be found in Appendix B.
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C. EPAct 2005 and Recent Developments
22. Enacted on August 8, 2005, EPAct added a number of new
authorities and priorities for the Commission and emphasized certain of
its existing obligations. Among other things, EPAct 2005 recognized the
importance of adequate transmission infrastructure development and its
role in facilitating the development of competitive wholesale markets.
The Congressional directives in EPAct 2005 are intended to reverse the
decline in transmission infrastructure investment. For example,
Congress required the Commission to adopt a rule establishing incentive
ratemaking for transmission infrastructure to help promote reliability
and reduce congestion.\28\ Congress also
[[Page 12271]]
directed the Commission to encourage the deployment of advanced
technologies.\29\ Congress further directed the Commission to
``exercise its authority'' under EPAct 2005 ``in a manner that
facilitates the planning and expansion of transmission facilities to
meet the reasonable needs of load-serving entities.''\30\ Congress also
gave the Commission certain ``backstop'' transmission siting authority,
and authorized the creation of interstate compacts establishing
transmission siting agencies.\31\ EPAct 2005 also authorized the
Commission to require unregulated transmitting utilities (except for
certain small entities) to provide access to their transmission
facilities on a comparable basis.\32\ Congress further ordered the
Department of Energy (DOE) to study the benefits of economic dispatch
and required the Commission to convene regional joint boards to develop
a report to Congress containing recommendations for the use of security
constrained economic dispatch within each region.\33\ Congress also
directed the Commission to facilitate price transparency in markets for
the sale and transmission of electric energy in interstate commerce,
having due regard for the public interest, the integrity of those
markets, fair competition, and the protection of consumers, and it
authorized the Commission to prescribe rules to provide for the
dissemination of information about the availability and price of
wholesale electric energy and transmission service.\34\ Finally,
Congress emphasized compliance with the Commission's regulations,
adopting and increasing the civil and criminal penalties for violations
of Commission-administered statutes and regulations.\35\
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\28\ EPAct 2005 sec. 1241 (to be codified at section 219 of the
FPA, 16 U.S.C. 824s).
\29\ EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16422).
Indeed, Congress provided specific guidance as to the types of
advanced technologies that should be encouraged in infrastructure
improvements to include, among others, optimized transmission line
configurations (including multiple phased transmission lines),
controllable load, distributed generation (including PV, fuel cells,
and microturbines), and enhanced power device monitoring. Id.
\30\ EPAct 2005 sec. 1233(a) (to be codified at section
217(b)(4) of the FPA, 16 U.S.C. 824q).
\31\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of
the FPA, 16 U.S.C. 824p).
\32\ EPAct 2005 sec. 1231 (to be codified at section 211A of the
FPA, 16 U.S.C. 824j-1)
\33\ EPAct 2005 sec. 1234 (to be codified at 42 U.S.C. 16432);
EPAct 2005 sec. 1298 (to be codified at section 223 of the FPA, 16
U.S.C. 824w). EPAct 2005 sec. 1234(b) defined economic dispatch as
``the operation of generation facilities to produce energy at the
lowest cost to reliably serve consumers, recognizing any operational
limits of generation and transmission facilities.''
\34\ EPAct 2005 sec. 1281 (to be codified at section 220 of the
FPA, 16 U.S.C. 824t).
\35\ EPAct 2005 sec. 1284(d) (to be codified at section 316 of
the FPA, 16 U.S.C. 825o); EPAct 2005 sec. 1284(e) (to be codified at
section 316A of the FPA, 16 U.S.C. 825o-1).
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23. Recognizing the need for reform of Order No. 888 in light of
the Commission's continuing concern regarding whether the pro forma
OATT adequately remedies undue discrimination, the Commission issued an
NOI on September 16, 2005 \36\ seeking comments on appropriate reforms
of the Order No. 888 pro forma OATT. In the NOI, the Commission
expressed its preliminary view that reforms to the pro forma OATT and
public utilities' OATTs are necessary to avoid undue discrimination or
preference in the provision of transmission service. The NOI sought
comments on how best to accomplish the Commission's goals, specifically
with respect to enhancements that are needed to (1) Remedy any unduly
discriminatory or preferential application of the pro forma OATT or (2)
improve the clarity of the Order No. 888 pro forma OATT and the
individual public utility tariffs in order to more readily identify
violations and facilitate compliance.
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\36\ See supra note 5.
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24. The Commission received over 4,000 pages of initial and reply
comments on the NOI. Based on these comments, the comments submitted in
response to the ATC NOI,\37\ our experience in implementing Order No.
888, and the changes in the industry since we adopted it, the
Commission proposed to reform the pro forma OATT in a number of ways.
The Commission issued the NOPR on May 19, 2006 proposing a number of
reforms aimed at remedying undue discrimination in the provision of
open access transmission service and improving the clarity of the pro
forma OATT and the individual tariffs of transmission providers in
order to more readily identify violations and facilitate compliance.
The Commission received over 5,700 pages of initial and reply comments
in response. In response to comments on the particular issue of
redispatch and conditional firm service (discussed in more detail
below), the Commission issued a Notice of Request for Supplemental
Comments on November 15, 2006,\38\ that resulted in receipt of an
additional 750 pages of comments.
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\37\ Id.
\38\ Preventing Undue Discrimination and Preference in
Transmission Service, 117 FERC ] 61,185 (2006).
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25. Based on this voluminous record, the Commission concludes that
reform of the pro forma OATT and associated amendments to its
regulations are necessary to reduce the potential for undue
discrimination and provide clarity in the obligations of transmission
providers and customers alike. We turn next to a more complete
explanation of this need for reform.
III. Need for Reform of Order No. 888
A. Opportunities for Undue Discrimination Continue To Exist
26. Although Order No. 888 has been successful in many important
respects, the need for reform of the Order No. 888 pro forma OATT has
been apparent for some time. In 1999, the Commission held, in adopting
Order No. 2000, that the pro forma OATT could not fully remedy undue
discrimination because transmission providers retained both the
incentive and the ability to discriminate against third parties,
particularly in areas where the pro forma OATT left the transmission
provider with significant discretion.\39\ The Commission made a similar
finding in Order No. 2003,\40\ holding that opportunities for undue
discrimination continue to exist in areas where the pro forma OATT
leaves transmission providers with substantial discretion.\41\ The NOPR
reaffirmed these findings, preliminarily concluding that opportunities
for undue discrimination continue to exist in the provision of open
access transmission service. The Commission therefore proposed a number
of reforms to the pro forma OATT to address the opportunities and
incentives transmission providers have to unduly discriminate.
---------------------------------------------------------------------------
\39\ Order No. 2000 at 31,105.
\40\ See Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC
Stats. & Regs. ] 31,146 at P 11-12 (2003), order on reh'g, Order No.
2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160
(2004), order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005),
FERC Stats. & Regs. ] 31,171 (2004), order on reh'g, Order No. 2003-
C, 70 FR 37,661 (Jun. 30, 2005), FERC Stats. & Regs. ] 31,190
(2005), aff'd sub nom. National Association of Regulatory Utility
Commissioners v. FERC, No. 04-1148, 2007 U.S. App. LEXIS 626 (D.C.
Cir. Jan. 12, 2007).
\41\ Order No. 2003 at P 11-12.
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Comments
27. Many commenters agree with the Commission that reforms to the
pro forma OATT are needed because there continue to be both the
opportunity and incentive for transmission providers to engage in undue
discrimination.\42\
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\42\ E.g., APPA, EPSA, East Texas Cooperatives, Fayetteville,
NRG, Occidental, TAPS, TDU Systems, Williams, Entegra Reply, and
NRECA Reply.
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28. Several commenters offered examples of their experiences with
transmission providers, where they believe transmission providers have
acted in an unduly discriminatory
[[Page 12272]]
fashion.\43\ Constellation claims that on multiple occasions it has
been denied a transmission request when the transmission provider's
OASIS indicates that ATC is available, but Constellation had no
effective and timely way to challenge that determination because of the
ATC ``black box.'' Constellation states that given that its needs for
transmission service are often near-term or immediate--e.g., to
facilitate a load-serving obligation or wholesale transaction that must
be consummated quickly--seeking redress at the Commission for
improperly denied service generally is not time- or cost-effective.
Instead, Constellation asserts, it is often forced to accept the
determination of the transmission provider that ATC is not available
(even though its OASIS may indicate otherwise) and seek alternate
transmission paths and/or products to consummate its transaction.
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\43\ See, e.g., Dow, Fayetteville, Occidental, and Williams.
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29. Powerex also describes instances where a transmission provider
has granted short-term firm point-to-point transmission service
requests to transmission customers who have been allowed to remain in
the queue, even when zero ATC is posted, in the hopes that a
transmission provider's OASIS site wrongly indicates zero ATC or will
soon be updated. Powerex asserts that such practices clog the short-
term point-to-point transmission queue with multiple requests and
result in duplicative requests for service that reflect customers'
attempts to secure service, rather than the actual quantity of service
needed. Moreover, Powerex argues, transmission provider discretion in
this area and the lack of transparency raise customer concerns about
preferential treatment.
30. Occidental claims that it has first-hand experience with a
vertically integrated transmission provider that, despite having an
OATT, appears to have persistently used its transmission system to
preferentially benefit its merchant function. Similarly, Williams
alleges that its interests have been consistently and significantly
compromised by the discretion afforded transmission providers in the
interpretation of the OATT and the lack of transparency in requesting,
scheduling and interrupting of transmission service.
31. Other commenters, however, argue that the Commission's proposed
reforms are based on unsupported allegations of undue discrimination.
EEI maintains that any opportunities to engage in undue discrimination
have been largely mitigated by current regulatory policies and changes
in the industry. EEI explains that, unlike the situation that existed
when the Commission enacted Order No. 888, much of the country's
transmission facilities are now under the control of RTOs and ISOs. In
addition, EEI states, other transmission providers have transferred (or
are in the process of transferring) the administration of their OATTs
and OASIS functions to independent transmission service coordinators.
Even among the transmission providers who have taken neither of those
steps, EEI argues that the open access requirements of Order No. 888
and the Standards of Conduct of Order Nos. 889 and 2004 have largely
eliminated the ability of transmission providers to engage in undue
discrimination in the provision of transmission service.\44\ In
addition, EEI states, the Commission's expanded civil penalty authority
added to the FPA by EPAct 2005 gives the Commission a powerful tool
that will further eliminate any remaining incentive of transmission
providers to engage in undue discrimination in the provision of
transmission service. Therefore, EEI asserts, any modifications to the
OATT should be narrowly tailored to address the perceptions of residual
undue discrimination. To the extent that such perceptions exist,
however, Community Power Alliance states that, in the absence of
concrete record evidence, they are just that--perceptions.
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\44\ See also Southern Reply.
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32. Although Duke strongly supports, as a policy matter, OATT
reforms that will eliminate the perception that undue discrimination is
possible and/or likely, Duke argues that the FPA does not provide the
Commission the authority to remedy mere ``opportunities'' to
discriminate. Duke states that, in some cases, the Commission is
attempting to remedy an opportunity for undue discrimination that does
not exist or is proposing to impose a remedy that does not actually
remedy the perceived opportunity. Duke notes, however, that some OATT
terms and conditions are subject to multiple interpretations and argues
that the Commission can, and should, justify the OATT reforms proposed
in the NOPR as reforms needed to provide clarity to existing policies.
33. With regard to specific allegations made by commenters, several
transmission providers respond that the examples given by transmission
customers do not illustrate instances of undue discrimination. Rather,
they assert, these examples demonstrate the transmission customers'
lack of understanding of the OATT requirements, and the data available
on OASIS.\45\
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\45\ See, e.g., Entergy Reply, Progress Energy Reply, and
Southern Reply.
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34. New Mexico Attorney General argues that the traditional State-
regulated, vertically-integrated cost-of-service world is not in need
of reform. Contrary to the ``conspiracy theorists'' who argue that
utilities have an incentive to engage in undue discrimination and
preference in transmission services, New Mexico Attorney General
asserts that utilities have an incentive to maximize throughput and
revenue between State-level rate cases because incremental transmission
revenue is not deducted from the State-jurisdictional retail revenues
between rate cases. Similarly, Southern, in its reply comments, asserts
that broad claims of undue discrimination fail to take into
consideration that vertically-integrated utilities have more of an
incentive to act appropriately than do independent utilities because
the former have more to lose (e.g., loss of market-based rates, state
prudence reviews of costs, etc.) if they are found to have engaged in
wrong-doing. Southern states that any OATT revisions ultimately adopted
by the Commission must be reasonably tailored to address an identified
problem or to provide a specific improvement.
35. Other commenters argue that the Commission's focus should be on
transmission providers in non-organized markets, arguing that remaining
concerns about undue discrimination have already been addressed in the
world of ISOs and RTOs.\46\ According to ISO/RTO Council, this
proceeding provides an opportunity for the Commission to harmonize the
worlds of organized and non-organized markets in a manner that
encourages competition, promotes non-discriminatory access, and
maximizes the flow of electricity across various ISO/RTO and non-ISO/
RTO regions. ISO/RTO Council states that, in the existing regulatory
environment, a utility that is not a member of an ISO or RTO can sell
into, or purchase from, an ISO or RTO market even though the non-ISO/
RTO utility operates under tariff rules that are less open and
transparent, particularly in terms of access to generation resources
and pricing/system information, than their competitors that belong to
an ISO or RTO. Such asymmetry, ISO/RTO Council argues, operates as an
[[Page 12273]]
impediment to fair and non-discriminatory transmission access and
management of grid congestion.
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\46\ E.g., Indicated New York Transmission Owners, ISO/RTO
Council, and Northeast Utilities.
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36. ISO/RTO Council states that its members do not seek to impose
their market designs on the rest of the nation. At the same time, ISO/
RTO Council argues that meaningful reform should ensure a level of
transparency (of both price and the dispatch utilized by non-ISO/RTO
vertically-integrated entities) in regions without an ISO or RTO that
can assist the flow of electricity and enhance reliability and planning
in both ISO/RTO and non-ISO/RTO regions.
37. Exelon urges the Commission to hold the transmission providers
outside ISOs or RTOs to the same standard of non-discrimination that
exists within those organizations. Further, MISO/PJM States argue that
in order to achieve some level of independence in non-RTO regions, non-
independent transmission providers should be encouraged to turn over
operational control of their transmission systems to an independent
coordinator of transmission whose functions would include security
coordination, determination of ATC, granting of transmission service
and oversight for transmission planning.
38. Finally, EPSA suggests that the Commission establish a one-year
review period for the reformed pro forma OATT. EPSA urges the
Commission to revisit this Final Rule after one year of operation under
the reformed pro forma OATT to ensure that the revisions adopted here
do, in fact, protect against non-discriminatory or preferential
behavior by transmission providers. NRECA responds that, after this
comprehensive rulemaking process, there is simply no need for another
major look at the OATT in one year. Moreover, NRECA states, one year is
likely too short a period for the Commission and industry participants
to fully appreciate all of the consequences of those elements of OATT
reform resulting from this proceeding. At the same time, NRECA agrees
that the Commission should carefully monitor implementation of the
reformed OATT. This monitoring, NRECA states, must be an ongoing
process and cannot wait a year to begin.
Commission Determination
39. The Commission concludes that reforms are needed to address
deficiencies in the pro forma OATT that have become apparent since
1996, by limiting remaining opportunities for undue discrimination. As
the Commission found in Order No. 888, it is in the economic self-
interest of transmission monopolists, particularly those with high-cost
generation assets, to deny transmission or to offer transmission on a
basis that is inferior to that which they provide to themselves.\47\
Such an incentive can lead to unduly discriminatory behavior against
third parties, particularly if public utilities have unnecessarily
broad discretion in the application of their tariffs. This discretion
also can create problems for transmission providers seeking to comply
with our regulations in good faith because so many issues are left for
their interpretation, thereby increasing the possibility of disputes
with transmission customers and enforcement actions by the
Commission.\48\ Transmission customers also have found ways to use the
tariffs to their own advantage, particularly in the scheduling and
queuing processes.\49\
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\47\ Order No. 888 at 31,682.
\48\ See, e.g., Order No. 2003 at P 11-12.
\49\ See, e.g., Potomac Economics, Ltd., 2004 State of the
Market Report: Midwest ISO at 30-31, 34-35 (Jun. 2005), https://
www.midwestmarket.org/publish/Document/2b8a32_103ef711180_-
7bf20a48324a/2004%20MISO%20SOM%20Report.pdf?action=download&--
property=Attachment (explaining that the queuing process, by giving
customers the opportunity to submit multiple requests for service,
provides a low- or no-cost option that restricts other customers'
access to congested interfaces, and the scheduling process, by
allowing customers to leave transmission requests unconfirmed,
provides a free option that may invite hoarding or result in
underutilized capacity).
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40. As some commenters note, opportunities for undue discrimination
persist, particularly in areas where the pro forma OATT leaves the
transmission provider with substantial discretion. The Commission has a
responsibility under section 206 of the FPA to remedy undue
discrimination. Indeed, the court concluded in Associated Gas
Distributors v. FERC,\50\ that, like the Natural Gas Act,\51\ the FPA
``fairly bristles'' with concern over undue discrimination. Based on
AGD, the Commission determined in Order No. 888 that:
\50\ 824 F.2d 981 (D.C. Cir. 1987) (AGD).
\51\ 15 U.S.C. 717.
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The Commission has a mandate under sections 205 and 206 of the
FPA to ensure that, with respect to any transmission in interstate
commerce or any sale of electric energy for resale in interstate
commerce by a public utility, no person is subject to any undue
prejudice or disadvantage. We must determine whether any rule,
regulation, practice or contract affecting rates for such
transmission or sale for resale is unduly discriminatory or
preferential, and must prevent those contracts and practices that do
not meet this standard. * * * AGD demonstrates that our remedial
power is very broad and includes the ability to order industry-wide
non-discriminatory open access as a remedy for undue discrimination.
Order No. 888 at 31,669. Through this Final Rule, the Commission
exercises that remedial authority again to limit further opportunities
for undue discrimination, by minimizing areas of discretion, addressing
ambiguities and clarifying various aspects of the pro forma OATT.
41. We disagree with commenters who assert that the Commission is
relying on unsubstantiated allegations of discriminatory conduct to
justify OATT reform. The courts have made clear that the Commission
need not make specific factual findings of discrimination in order to
promulgate a generic rule to eliminate undue discrimination.\52\ In
AGD, the court explained that the promulgation of generic rate criteria
involves the determination of policy goals and the selection of the
means to achieve them and that courts do not insist on empirical data
for every proposition upon which the selection depends: ``[a]gencies do
not need to conduct experiments in order to rely on the prediction that
an unsupported stone will fall.'' \53\ During this multi-year
proceeding, the Commission has received many comments arguing that
commenters have either experienced or perceived that they have
experienced unduly discriminatory conduct by transmission providers.
Even transmission providers have acknowledged that there is a
continuing perception that there is the opportunity for them to unduly
discriminate against their competitors and, accordingly, they state
their support for our reform effort.\54\ Moreover, it is undisputed
that the existing pro forma OATT provides wide discretion in
implementing some of its basic requirements, such as the assessment of
whether sufficient ATC exists to grant third party access to the grid
and the manner in which new facilities are planned to satisfy third
party needs. This wide discretion, when coupled with a transmission
provider's incentive to discriminate, creates opportunities for
discrimination under the pro forma OATT. We have an obligation