Mandatory Reliability Standards for the Calculation of Available Transfer Capability, Capacity Benefit Margins, Transmission Reliability Margins, Total Transfer Capability, and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System, 64884-64927 [E9-28620]
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64884
Federal Register / Vol. 74, No. 234 / Tuesday, December 8, 2009 / Rules and Regulations
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM08–19–000, et al.; Order No.
729]
Mandatory Reliability Standards for the
Calculation of Available Transfer
Capability, Capacity Benefit Margins,
Transmission Reliability Margins, Total
Transfer Capability, and Existing
Transmission Commitments and
Mandatory Reliability Standards for the
Bulk-Power System
Issued November 24, 2009.
AGENCY: Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule.
SUMMARY: Pursuant to section 215 of the
Federal Power Act, the Commission
approves six Modeling, Data, and
Analysis Reliability Standards
submitted to the Commission for
approval by the North American Electric
Reliability Corporation, the Electric
Reliability Organization certified by the
Commission. The approved Reliability
Standards require certain users, owners,
and operators of the Bulk-Power System
to develop consistent methodologies for
the calculation of available transfer
capability or available flowgate
capability. Pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission also directs
the ERO to develop certain
modifications to the MOD Reliability
Standards. Finally, the Commission
directs NERC to retire the existing MOD
Reliability Standards replaced by the
versions approved here.
DATES: Effective Date: This rule will
become effective February 8, 2010.
FOR FURTHER INFORMATION CONTACT:
Jonathan First (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–8529.
Cory Lankford (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–6711.
Christopher Young (Technical
Information), Office of Electric
Reliability, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
6403.
SUPPLEMENTARY INFORMATION:
Table of Contents
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Paragraph
Numbers
I. Background ............................................................................................................................................................................................
A. Order Nos. 888 and 889 ...............................................................................................................................................................
B. Order Nos. 890 and 693 ...............................................................................................................................................................
II. MOD Reliability Standards ..................................................................................................................................................................
A. Coordination with Business Practice Standards ........................................................................................................................
B. Available Transmission System Capability, MOD–001–1 ..........................................................................................................
C. Capacity Benefit Margin Methodology, MOD–004–1 .................................................................................................................
D. Transmission Reliability Margin Methodology, MOD–008–1 ...................................................................................................
E. Three Methodologies for Calculating Available Transfer Capability ........................................................................................
1. Area Interchange Methodology, MOD–028–1 ......................................................................................................................
2. Rated System Path Methodology, MOD–029–1 ...................................................................................................................
3. Flowgate Methodology, MOD–030–2 ....................................................................................................................................
F. Implementation Plan ....................................................................................................................................................................
III. Discussion ...........................................................................................................................................................................................
A. Approval, Implementation and Audit of the MOD Reliability Standards ................................................................................
1. Approval of the MOD Reliability Standards ........................................................................................................................
2. Implementation Timeline ......................................................................................................................................................
3. Implementation Document Audits ........................................................................................................................................
a. Authority to Direct Audits .............................................................................................................................................
b. Performance of Audits ....................................................................................................................................................
c. Additional Requirements to Prevent Undue Discrimination .......................................................................................
B. Modification of the Reliability Standards ...................................................................................................................................
1. MOD–001–1 ............................................................................................................................................................................
a. Availability of the Implementation Documents ............................................................................................................
b. Dispatch Model Assumptions ........................................................................................................................................
c. Treatment of Network Resource Designations ..............................................................................................................
d. Updating Available Transfer Capability and Available Flowgate Capability Values ................................................
e. MOD–001–1, Consistent Treatment of Assumptions ....................................................................................................
f. MOD–001–1, Requirement R2 ........................................................................................................................................
g. MOD–001–1, Requirement R3 ........................................................................................................................................
h. MOD–001–1, Requirements R6 and R7 .........................................................................................................................
i. MOD–001–1, Requirement R9 ........................................................................................................................................
j. MOD–001–1, Counterflows .............................................................................................................................................
2. MOD–004–1, Capacity Benefit Margin .................................................................................................................................
3. MOD–008–1, Transfer Reliability Margin ............................................................................................................................
4. MOD–028–1, Area Interchange Methodology ......................................................................................................................
a. General .............................................................................................................................................................................
b. MOD–028–1, Requirement R2 ........................................................................................................................................
c. MOD–028–1, Requirement R5 ........................................................................................................................................
d. MOD–028–1, Requirement R6 .......................................................................................................................................
5. MOD–029–1, Rated System Path Methodology ...................................................................................................................
a. Sub-Requirement R2.7 ....................................................................................................................................................
b. Counterschedules ............................................................................................................................................................
6. MOD–030–2, Flowgate Methodology ....................................................................................................................................
a. MOD–030–2, Requirements R2.4 and R2.5 ...................................................................................................................
b. MOD–030–2, Requirements R3 and R10 .......................................................................................................................
c. MOD–030–2, Existing Transmission Commitments, Requirement R6 ........................................................................
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Federal Register / Vol. 74, No. 234 / Tuesday, December 8, 2009 / Rules and Regulations
64885
Paragraph
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d. MOD–030–2, Power Transfer and Outage Transfer Distribution Factors ...................................................................
e. MOD–030–2, Treatment of Adjacent Systems ..............................................................................................................
f. MOD–030–2, Effective Date ............................................................................................................................................
C. Violation Risk Factors and Violation Severity Levels ................................................................................................................
D. Disposition of Other Reliability Standards .................................................................................................................................
1. MOD–010–1 through MOD–025–1 ........................................................................................................................................
2. Reliability Standards to be Retired or Withdrawn ..............................................................................................................
E. Applicability .................................................................................................................................................................................
F. Definitions .....................................................................................................................................................................................
IV. Information Collection Statement ......................................................................................................................................................
V. Environmental Analysis ......................................................................................................................................................................
VI. Regulatory Flexibility Act ..................................................................................................................................................................
VII. Document Availability ......................................................................................................................................................................
VIII. Effective Date and Congressional Notification ...............................................................................................................................
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Before Commissioners: Jon Wellinghoff,
Chairman; Suedeen G. Kelly, Marc
Spitzer, and Philip D. Moeller.
1. Pursuant to section 215 of the
Federal Power Act (FPA),1 the Federal
Energy Regulatory Commission
(Commission) approves, and directs
modifications to, six Modeling, Data and
Analysis (MOD) Reliability Standards
submitted to the Commission by the
North American Electric Reliability
Corporation (NERC), the Commissioncertified Electric Reliability
Organization (ERO) for the United
States.2 The approved Reliability
Standards pertain to methodologies for
the consistent and transparent
calculation of available transfer
capability or available flowgate
capability. Pursuant to section 215(d)(5)
of the FPA and section 39.5(f) of our
regulations, the Commission directs the
ERO to develop certain modifications to
the MOD Reliability Standards.3 The
Commission also directs NERC to retire
the existing MOD Reliability Standards
replaced by the versions approved here.
The retirement of these Reliability
Standards will be effective upon the
effective date of the approved MOD
Reliability Standards.
2. In Order No. 890, the Commission
found that the lack of a consistent and
transparent methodology for calculating
available transfer capability is a
significant problem because the
calculation of available transfer
capability, which varies greatly
depending on the criteria and
assumptions used, may allow the
transmission service provider to
discriminate in subtle ways against its
1 16
U.S.C. 824o (2006).
American Electric Reliability Corp., 116
FERC ¶ 61,062 (ERO Certification Order), order on
reh’g & compliance, 117 FERC ¶ 61,126 (2006) (ERO
Rehearing Order), aff’d, Alcoa Inc. v. FERC, 564
F.3d 1342 (D.C. Cir. 2009).
3 16 U.S.C. 824o(d)(5).
2 North
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competitors.4 In Order No. 693, the
Commission reiterated its concerns
expressed in Order No. 890 and stated
that available transfer capability raises
both comparability and reliability
issues, and that it would be
irresponsible to require consistency in
the available transfer capability
calculation without considering the
reliability impact of those decisions.5
The calculation of available transfer
capability is one of the most critical
functions under the open access
transmission tariff (OATT) because it
determines whether transmission
customers can access alternative power
supplies. Improving transparency and
consistency of available transfer
capability calculation methodologies
will eliminate transmission service
providers’ wide discretion in calculating
available transfer capability and ensure
that customers are treated fairly in
seeking alternative power supplies. The
Commission believes that the Reliability
Standards approved here address the
potential for undue discrimination by
requiring industry-wide transparency
and increased consistency regarding all
components of the available transfer
capability calculation methodology and
certain definitions, data, and modeling
assumptions.
3. The Commission approves the
Reliability Standards filed by NERC in
this proceeding as just, reasonable, not
unduly discriminatory or preferential,
and in the public interest.6 These
Reliability Standards represent a step
4 Preventing
Undue Discrimination and
Preference in Transmission Service, Order No. 890,
72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs.
¶ 31,241 (2007), order on reh’g, Order No. 890–A,
73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs.
¶ 31,261 (2007), order on reh’g, Order No. 890–B,
123 FERC ¶ 61,299 (2008), order on reh’g, Order No.
890–C, 126 FERC ¶ 61,228 (2009).
5 Mandatory Reliability Standards for the BulkPower System, Order No. 693, 72 FR 16416 (Apr.
4, 2007), FERC Stats. & Regs. ¶ 31,242, at P 1022
(2007), order on reh’g, Order No. 693–A, 120 FERC
¶ 61,053 (2007).
6 16 U.S.C. 824o(d)(2).
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forward in eliminating the broad
discretion previously afforded
transmission service providers in the
calculation of available transfer
capability. The approved Reliability
Standards will enhance transparency in
the calculation of available transfer
capability, requiring transmission
operators and transmission service
providers to calculate available transfer
capability using a specific methodology
that is both explicitly documented and
available to reliability entities who
request it.7 The approved Reliability
Standards also require documentation of
the detailed representations of the
various components that comprise the
available transfer capability equation,
including the specification of modeling
and risk assumptions and the disclosure
of outage processing rules to other
reliability entities. These actions will
make the processes to calculate
available transfer capability and its
various components more transparent,
which in turn will allow the
Commission and others to ensure
consistency in their application. By
promoting consistency, standardization
and transparency, these Reliability
Standards enhance the reliability of the
Bulk-Power System.
4. On March 19, 2009, the
Commission issued its Notice of
Proposed Rulemaking (NOPR)
proposing to approve the six MOD
7 Reliability entities include: Transmission
service providers, planning coordinators, reliability
coordinators, and transmission operators as those
entities are defined in the NERC Glossary of Terms
Used in Reliability Standards (Glossary), (Effective
February 12, 2008), available at: https://
www.nerc.com/docs/standards/rs/
Glossary_12Feb08.pdf. Standards adopted by the
North American Energy Standards Board (NAESB)
govern disclosure of this information to other
entities. The Commission accepts the associated
NAESB business practices in a Final Rule issued
concurrently in Docket No. RM05–5–013. See
Standards for Business Practices and
Communication Protocols for Public Utilities, No.
676–E, 129 FERC ¶ 61,162 (2009).
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Federal Register / Vol. 74, No. 234 / Tuesday, December 8, 2009 / Rules and Regulations
Reliability Standards.8 The Commission
also proposed to direct NERC to retire
the currently effective MOD Reliability
Standards along with one FAC
Reliability Standard. The Commission
proposed that NERC retain another FAC
Reliability Standard, FAC–012–1, and
proposed that the ERO develop
modifications to conform with the MOD
Reliability Standards approved herein.
The Commission also proposed to direct
NERC to expand the disclosure
provisions and conduct audits of certain
implementation documents associated
with the Reliability Standards to be
approved herein. In response to the
NOPR, comments were filed by 37
interested parties. In the discussion
below, we address the issues raised by
these comments. Appendix A to this
Final Rule lists the entities that filed
comments on the NOPR.
I. Background
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A. Order Nos. 888 and 889
5. In April 1996, as part of its
statutory obligation under sections 205
and 206 of the FPA 9 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.10 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 that
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
8 Mandatory Reliability Standards for the
Calculation of Available Transfer Capability,
Capacity Benefit Margins, Transmission Reliability
Margins, Total Transfer Capability, and Existing
Transmission Commitments and Mandatory
Reliability Standards for the Bulk-Power System, 74
FR 12747 (March 25, 2009), FERC Stats. & Regs.
¶ 32,641 (2009) (‘‘NOPR’’).
9 16 U.S.C. 824d, 824e.
10 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), aff’d sub nom. New York v. FERC, 535 U.S.
1 (2002).
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state their rates for wholesale
generation, transmission and ancillary
services.11 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).12 After their OATTs
became effective, 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.
6. The same day it issued Order No.
888, the Commission issued a
companion order, Order No. 889,13
addressing the separation of vertically
integrated utilities’ transmission and
merchant functions, the information
transmission service 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.
7. Among the information public
utilities were required to post on their
OASIS was the transmission service
provider’s calculation of available
transfer capability. Though the
Commission acknowledged that beforethe-fact measurement of the availability
of transmission service is ‘‘difficult,’’
the Commission concluded that it was
important to give potential transmission
customers ‘‘an easy-to-understand
11 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.
12 See Order No. 888, FERC Stats. & Regs.
¶ 31,036 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 service provider).
13 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).
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indicator of service availability.’’ 14
Because formal methods did not then
exist to calculate available transfer
capability and total transfer capability,
the Commission encouraged industry
efforts to develop consistent methods
for calculating available transfer
capability and total transfer capability.15
Order No. 889 ultimately required
transmission service providers to base
their calculations on ‘‘current industry
practices, standards and criteria’’ and to
describe their methodology in an
Attachment C to their tariffs.16 The
Commission noted that the requirement
that transmission service providers
make available for purchase only
available transfer capability that is
posted as available ‘‘should create an
adequate incentive for them to calculate
available transfer capability and total
transfer capability as accurately and as
uniformly as possible.’’ 17
8. Although 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 did not standardize the
methodology for calculating available
transfer capability, nor did it impose
any specific requirements regarding the
disclosure of the methodologies used by
each transmission service provider.18 As
a result, a variety of methodologies to
calculate available transfer capability
have been used with very few clear
rules governing their use. Moreover,
there was often very little transparency
about the nature of these calculations,
given that many transmission service
providers historically filed only
summary explanations of their available
transfer capability methodologies in
Attachment C to their OATTs.
B. Order Nos. 890 and 693
9. Section 215 of the FPA requires a
Commission-certified ERO to develop
mandatory and enforceable Reliability
Standards that provide for the reliable
operation of the Bulk-Power System,
which are subject to Commission review
and approval. If approved, the
Reliability Standards are enforced by
the ERO subject to Commission
oversight, or by the Commission
independently. As the ERO, NERC
worked with industry to develop
Reliability Standards improving
consistency and transparency of
available transfer capability calculation
methodologies. On April 4, 2006, as
14 Order No. 889, FERC Stats. & Regs. ¶ 31,035 at
31,749.
15 Id. at 31,750.
16 Id.
17 Id.
18 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at
31,749 n.610.
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Federal Register / Vol. 74, No. 234 / Tuesday, December 8, 2009 / Rules and Regulations
modified on August 28, 2006, NERC
submitted to the Commission a petition
seeking approval of 107 proposed
Reliability Standards, including 23
Reliability Standards pertaining to
Modeling, Data and Analysis (MOD).
The MOD group of Reliability Standards
is intended to standardize
methodologies and system data needed
for traditional transmission system
operation and expansion planning,
reliability assessment and the
calculation of available transfer
capability in an open access
environment.
10. On February 16, 2007, the
Commission issued Order No. 890,
which addressed and remedied
opportunities for undue discrimination
under the pro forma OATT adopted in
Order No. 888. Among other things, the
Commission required industry-wide
consistency and transparency of all
components of available transfer
capability calculation and certain
definitions, data and modeling
assumptions. The Commission
concluded that the lack of industrywide criteria for the consistent
calculation of available transfer
capability poses a threat to the reliable
operation of the Bulk-Power System,
particularly with respect to the inability
of one transmission service provider to
know with certainty its neighbors’
system conditions affecting its own
available transfer capability values. As a
result of this reliability concern, the
Commission found that the proposed
available transfer capability reforms
were also supported by FPA section
215, through which the Commission has
the authority to direct the ERO to
submit a Reliability Standard that
addresses a specific matter.19 Thus, the
Commission in Order No. 890 directed
industry to develop Reliability
Standards, using the ERO’s Reliability
Standards development procedures, that
provide for consistency and
transparency in the methodologies used
by transmission owners to calculate
available transfer capability.
11. The Commission stated in Order
No. 890 that the available transfer
capability-related Reliability Standards
should, at a minimum, provide a
framework for available transfer
capability, total transfer capability and
existing transmission commitments
calculations. The Commission did not
require that there be just one
computational process for calculating
available transfer capability because,
among other things, it found that the
potential for discrimination and decline
in reliability level does not lie primarily
19 FPA
section 215(d)(5). 16 U.S.C. 824o(d)(5).
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in the choice of an available transfer
capability calculation methodology, but
rather in the consistent application of its
components, input and exchange data,
and modeling assumptions.20 The
Commission found that, if all of the
available transfer capability
components, certain data inputs and
certain assumptions are consistent, the
three available transfer capability
calculation methodologies would
produce predictable and sufficiently
accurate, consistent, equivalent and
replicable results.21
12. On March 16, 2007, the
Commission issued Order No. 693,
approving 83 of the 107 Reliability
Standards filed by NERC in April
2006.22 Of the 83 approved Reliability
Standards, the Commission approved
ten MOD Reliability Standards.23
However, the Commission directed
NERC to prospectively modify nine of
the ten approved MOD Reliability
Standards to be consistent with the
requirements of Order No. 890.24 The
Commission reiterated the requirement
from Order No. 890 that all available
transfer capability components (i.e.,
total transfer capability, existing
transmission commitments, capacity
benefit margin, and transmission
reliability margin) and certain data
input, data exchange, and assumptions
be consistent and that the number of
industry-wide available transfer
capability calculation formulas be few
in number, transparent and produce
equivalent results.25 The Commission
directed public utilities, working
through the NERC Reliability Standards
and North American Energy Standards
Board (NAESB) business practices
development processes, to produce
workable solutions to implement the
available transfer capability-related
reforms adopted by the Commission.
The Commission also deferred action on
24 proposed Reliability Standards,
which did not contain sufficient
information to enable the Commission
to propose a disposition.26
20 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 1029.
21 Id. P 1030.
22 Order No. 693, FERC Stats. & Regs. ¶ 31,242.
23 Id. P 1010.
24 Id.
25 Id. P 1029–30; see also Order No. 890, FERC
Stats. & Regs. ¶ 31,241 at P 207.
26 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 287–303. Some of these Reliability Standards
required the regional reliability organizations to
develop criteria for use by users, owners or
operators within each region. The Commission set
aside such Reliability Standards and directed NERC
to provide additional details prior to considering
them for approval. Id. P 287–303.
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64887
II. MOD Reliability Standards
13. In response to the requirements of
Order No. 890 and related directives of
Order No. 693,27 on August 29, 2008,
NERC submitted for Commission
approval five MOD Reliability
Standards: MOD–001–1—Available
Transmission System Capability, MOD–
008–1—TRM Calculation Methodology
(hereinafter Transmission Reliability
Margin Methodology), MOD–028–1—
Area Interchange Methodology, MOD–
029–1—Rated System Path
Methodology, and MOD–030–1—
Flowgate Methodology.28 On November
21, 2008, NERC submitted for
Commission approval a sixth MOD
Reliability Standard: MOD–004–1—
Capacity Benefit Margin (hereinafter
Capacity Benefit Margin Methodology).
On March 6, 2009, NERC submitted for
Commission approval: MOD–030–2—a
revised Flowgate Methodology
Reliability Standard and withdrew its
request for approval of MOD–030–1.29
14. The Available Transmission
System Capability Reliability Standard
(MOD–001–1) serves as an ‘‘umbrella’’
Reliability Standard that requires each
applicable entity to select and
implement one or more of the three
available transfer capability
methodologies found in MOD–028–1,
MOD–029–1, or MOD–030–2. MOD–
004–1 and MOD–008–1 provide for the
calculation of capacity benefit margin
and transmission reliability margin,
which are inputs into the available
transfer capability calculation. NERC
states that its filing wholly addresses
eight of the 24 Reliability Standards that
the Commission did not approve in
Order No. 693 because further
information was needed.
15. NERC contends that the Reliability
Standards will have no undue negative
effect on competition, nor will they
unreasonably restrict available transfer
capability on the Bulk-Power System
27 The Reliability Standards were originally due
on December 10, 2007. See Order No. 890, FERC
Stats. & Regs. ¶ 31,241 at P 223. NERC requested
additional time to develop the Reliability Standards
in order to address concerns raised in its
stakeholder process. See NERC November 21, 2007
Request for Extension of Time, Docket No. RM05–
17–000, et al., at 7. The Commission ultimately
granted three requests for extension of time,
extending NERC’s deadline by over seven months,
so that NERC could develop the Reliability
Standards proposed here.
28 NERC designates the version number of a
Reliability Standard as the last digit of the
Reliability Standard number. Therefore, version
zero Reliability Standards end with ‘‘–0’’ and
version one Reliability Standards end with ‘‘–1.’’
29 The MOD Reliability Standards are not codified
in the CFR and are not attached to the Final Rule.
They are, however, available on the Commission’s
eLibrary document retrieval system and on the
ERO’s Web site, https://www.nerc.com.
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beyond any restriction necessary for
reliability and do not limit use of the
Bulk-Power System in an unduly
preferential manner. NERC contends
that the increased rigor and
transparency introduced in the
development of available transfer
capability and available flowgate
capability calculations serve to mitigate
the potential for undue advantages of
one competitor over another. Under the
Reliability Standards, applicable entities
are prohibited from making
transmission capability available on a
more conservative basis for commercial
purposes than for either planning for
native load or use in actual operations,
thereby mitigating the potential for
differing treatment of native load
customers and transmission service
customers. NERC states that data
exchange, which has been heretofore
voluntary, is now mandatory and it is
required that the data be used in the
available transfer capability/available
flowgate capability calculations. None
of these requirements exist in the
current available transfer capabilityrelated Reliability Standards. NERC
contends that these improvements help
the Commission achieve many of the
primary objectives of Order No. 890
regarding transparency, standardization
and consistency in available transfer
capability calculations.
16. NERC states that all three
methodology Reliability Standards
(MOD–028–1, MOD–029–1, and MOD–
030–2) share fundamental equations
that, while mathematically equivalent,
are written in slightly different forms.
As a result, the manner of determining
the components varies between
methodologies. The employment of any
two methodologies, given the same
inputs, may produce similar, but not
identical, results. As noted by NERC
there are fundamental differences in the
proposed methodologies that can keep
them from producing identical results.
For example, the rated system path
methodology does not use the same
frequent simulations of power flow used
by the other two methodologies. NERC
states that the rated system path
methodology therefore will rarely
generate numbers that identically match
those determined by an entity using the
other two methodologies.
A. Coordination With Business Practice
Standards
17. NERC states that it has worked
closely and collaboratively with
NAESB, conducting numerous joint
meetings and conference calls, to
develop the MOD Reliability Standards
and related NAESB business-practice
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standards.30 NERC states that the focus
of the MOD Reliability Standards is to
address only the reliability aspects of
available transfer capability and
available flowgate capability, not
commercial aspects, except to the extent
that commercial system availability
closely matches actual remaining
system capability. The associated
NAESB business practice standards are
intended to focus on the competitive
aspects of these processes. Through
implementation of these Reliability
Standards, access to the grid may
indirectly be restricted, but NERC states
that NAESB business practices and
Commission orders related to these
Reliability Standards ensure that any
limitation will be applied in a manner
that ensures open access and promotes
competition.
18. According to NERC, it and NAESB
have coordinated the development of
these business practices and the
Reliability Standards to ensure that
there are no duplications or double
counting between the business practice
standards and the Reliability Standards.
They intend to continue to coordinate as
necessary so that the available transfer
capability-related Reliability Standards
are compatible and consistent.
B. Available Transmission System
Capability, MOD–001–1
19. NERC proposes the Available
Transmission System Capability
Reliability Standard (MOD–001–1) as
part of a set of Reliability Standards
which are designed to work together to
support a common reliability goal: To
ensure that transmission service
providers maintain awareness of
available system capability and future
flows on their own systems as well as
those of their neighbors. NERC states
that, historically, differences in
implementation of available transfer
capability methodologies and a lack of
coordination between transmission
service providers have resulted in cases
where available transfer capability has
been overestimated. As a result, systems
have been oversold, resulting in
potential or actual violations of system
operating limits and interconnection
reliability operating limits. NERC states
that MOD–001–1 is the foundational
Reliability Standard that obliges entities
to select a methodology and then
calculate available transfer capability or
available flowgate capability using that
methodology. NERC contends that such
30 As noted above, the Commission addresses the
NAESB business practices in a Final Rule issued
concurrently in Docket No. RM05–5–013. See
Standards for Business Practices and
Communication Protocols for Public Utilities, Order
No. 676–E, 129 FERC ¶ 61,162 (2009).
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selection ensures that the determination
of available transfer capability is
accurate and consistent across North
America and that the transmission
system is neither oversubscribed nor
underutilized.
20. NERC states that, unlike the
current set of voluntary available
transfer capability standards, MOD–
001–1 requires adherence to a specific
documented and transparent
methodology. NERC states that it
requires applicable entities to calculate
available transfer capability on a
consistent schedule and for specific
timeframes. According to NERC, MOD–
001–1 requires users, owners and
operators to disclose counterflow
assumptions and outage processing
rules to other reliability entities. NERC
states that this Reliability Standard
prohibits applicable entities from
making transmission capability
available on a more conservative basis
for commercial purposes for either
planning for native load or use in actual
operations. NERC’s MOD–001–1 also
requires entities, for the first time, to
exchange and use available transfer
capability data. NERC states that the
Reliability Standard reflects industry’s
consensus best practices for determining
available transfer capability.
21. MOD–001–1 includes nine
requirements, which apply to all
transmission service providers and
transmission operators. To ensure
consistency of enforcement, NERC states
that each requirement is supported by a
measure that identifies what is required
and how the requirement will be
enforced.
22. Under Requirement R1, a
transmission operator must select one of
three methodologies for calculating
available transfer capability or available
flowgate capability for each available
transfer capability path for each time
frame (hourly, daily or monthly) for the
facilities in its area. As stated above, the
three methodologies are: The area
interchange methodology, the rated
system path methodology, and the
flowgate methodology.
23. Several requirements within this
MOD–001–1 address the calculation of
available transfer capability or available
flowgate capability. Requirement R2
requires each transmission service
provider to calculate available transfer
capability or available flowgate
capability values hourly for the next 48
hours, daily for the next 31 calendar
days and monthly for the next 12
months. Requirement R6 requires each
transmission operator in its calculation
of total transfer capability or total
flowgate capability to use assumptions
no more limiting than those used in its
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planning of operations. NERC contends
that, consistent with the requirements of
Order No. 890 and related directives of
Order No. 693, Requirement R6 will
minimize the differences between total
transfer capability and total flowgate
capability for transmission and transfer
capability used in native load and
reliability assessment studies.31
Similarly, Requirement R7 requires each
transmission service provider, in its
calculation of available transfer
capability or available flowgate
capability, to use assumptions no more
limiting than those used in its planning
of operations. NERC contends that this
requirement addresses the
Commission’s directive in Order No.
693 for the ERO to modify the available
transfer capability Reliability Standards
to include a requirement that the
assumptions used in available transfer
capability and available flowgate
capability calculations be consistent
with those used for planning the
expansion or operation of the BulkPower System to the maximum extent
possible.32 Requirement R8 requires
each transmission service provider to
recalculate available transfer capability
at a certain specified interval (hourly,
daily, monthly) unless the input values
specified in the available transfer
capability calculation have not changed.
NERC contends that Requirement R8
satisfies the Commission’s directive to
calculate available transfer capability on
a consistent time interval.33
24. MOD–001–1 also includes several
record keeping and information sharing
requirements for transmission service
providers. Requirement R3 requires
each transmission service provider to
keep an available transfer capability
implementation document that explains
the implementation of its chosen
methodology(ies), its use of
counterflows, the identities of entities
with which it exchanges information for
coordination purposes, any capacity
allocation processes, and the manner in
which it considers outages. Requirement
R4 requires transmission service
providers to keep specific reliability
entities advised regarding changes to the
available transfer capability
implementation document.34
31 See Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 237; Order No. 693, FERC Stats. &
Regs. ¶ 31,242 at P 1051.
32 Order No. 693, FERC Stats. & Regs. ¶ 1,242 at
P 1057; see also Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 292.
33 See Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 301; Order No. 693, FERC Stats. &
Regs. ¶ 31,242 at P 1057.
34 These include: each planning coordinator,
reliability coordinator, and transmission operator
associated with the transmission service provider’s
area; and each planning coordinator, reliability
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Requirement R5 requires the
transmission service provider to make
the available transfer capability
implementation document available to
those same reliability entities.35 Finally,
Requirement R9 allows a transmission
service provider thirty calendar days to
begin to respond to a request from any
other transmission service provider,
planning coordinator, reliability
coordinator or transmission operator for
certain data to be used in the requestor’s
available transfer capability or available
flowgate capability calculations.
25. In Order No. 693, the Commission
directed the ERO to develop
modifications to the available transfer
capability Reliability Standards to
include a requirement that applicable
entities make available assumptions and
contingencies underlying available
transfer capability and total transfer
capability calculations. NERC contends
that this Reliability Standard addresses
this issue by requiring disclosure in the
available transfer capability
implementation document under
Requirement R3.1 and part of the data
exchange required by Requirement R9.
NERC states that it has agreed with
NAESB that requirements for posting
information are more appropriately
addressed through the NAESB process.
Accordingly, NERC states that NAESB
will be addressing the requirements
associated with posting this
information, instead of NERC.
C. Capacity Benefit Margin
Methodology, MOD–004–1
26. The Capacity Benefit Margin
Methodology Reliability Standard
(MOD–004–1) provides for the
calculation of capacity benefit margin.
NERC defines capacity benefit margin as
the amount of firm transmission
capability set aside by the transmission
service provider for load-serving
entities, whose loads are located on that
transmission service provider’s system,
to enable access by the load-serving
entities to generation from
interconnected systems to meet
generation reliability requirements.36
The purpose of this Reliability Standard
is to promote the consistent and reliable
calculation, verification, setting aside,
and use of capacity benefit margin to
support analysis and system operations.
coordinator, and transmission service provider
adjacent to the transmission service provider’s area.
35 Although the Reliability Standards only require
the transmission service provider to make the
available transfer capability implementation
document available to certain reliability entities,
the NAESB standard on OASIS posting
requirements (Standard 001–13.1.5) requires
transmission service providers to provide a link to
the document on OASIS.
36 See NERC Glossary.
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NERC states that setting aside of
capacity benefit margin for a loadserving entity allows that entity to
reduce its installed generating capacity
below that which may otherwise have
been necessary without
interconnections to meet its generation
reliability requirements. NERC states
that the transmission transfer capability
preserved as capacity benefit margin is
intended to be used by the load-serving
entities only in times of emergency
generation deficiencies.
27. Reliability Standard MOD–004–1
applies to transmission service
providers, transmission planners, loadserving entities, resource planners and
balancing authorities. As discussed
more fully below, NERC states that it
does not specify a particular
methodology for calculating capacity
benefit margin, but rather improves
transparency by requiring adherence to
specific documented and transparent
methodology to ensure consistent and
reliable calculation, verification,
preservation and use of capacity benefit
margin.
28. To improve consistency and
transparency in the calculation of
capacity benefit margin, the Reliability
Standard imposes twelve requirements
on entities electing to use a capacity
benefit margin. Requirement R1 requires
the transmission service provider that
maintains capacity benefit margin to
prepare and keep current a capacity
benefit margin implementation
document that includes at a minimum:
(1) The process through which a loadserving entity within a balancing
authority associated with the
transmission service provider, or the
resource planner associated with that
balancing authority area, may ensure
that its need for transmission capacity to
be set aside as capacity benefit margin
will be reviewed and accommodated by
the transmission service provider to the
extent transmission capacity is
available; (2) the procedure and
assumptions for establishing capacity
benefit margin for each available
transfer capability path or flowgate; and
(3) the procedure for a load-serving
entity or balancing authority to use
transmission capacity set aside as
capacity benefit margin, including the
manner in which the transmission
service provider will manage situations
where the requested use of capacity
benefit margin exceeds the amount of
capacity benefit margin available.
29. Requirement R2 requires the
transmission service provider to make
its current capacity benefit margin
implementation document available to
the transmission operators, transmission
service providers, reliability
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coordinators, transmission planners,
resource planners, and planning
coordinators that are within or adjacent
to the transmission service provider’s
area, and to the load-serving entities and
balancing authorities within the
transmission service providers area, and
notify those entities of any changes to
the capacity benefit margin
implementation document prior to the
effective date of the change.
30. Requirements R3 and R4 require
each load-serving entity and resource
planner to determine the need for
transmission capacity to be set aside as
capacity benefit margin for imports into
a balancing authority by using one or
more of the following to determine the
generation capability import
requirement: 37 loss of load expectation
studies, loss of load probability studies,
deterministic risk-analysis studies, and
reserve margin or resource adequacy
requirements established by other
entities, such as municipalities, state
commissions, regional transmission
organizations, independent system
operators, regional reliability
organizations, or regional entities.
31. Requirement R5 requires the
transmission service provider to
establish at least every 13 months a
capacity benefit margin value for each
available transfer capability path or
flowgate to be used for available transfer
capability or available flowgate
capability during the 13 full calendar
months (months 2–14) following the
current month (the month in which the
transmission service provider is
establishing the capacity benefit margin
values). Similarly, Requirement R6
requires the transmission planner to
establish a capacity benefit margin value
for each available transfer capability
path or flowgate to be used in planning
during each of the full calendar years
two through ten following the current
year (the year in which the transmission
planner is establishing the capacity
benefit margin values). All values must
reflect consideration of each of the
following, if available: (1) Any studies
performed by load-serving entities or
resource planners pursuant to
Requirement R3 for loads within the
transmission service provider’s area; or
(2) any reserve margin or resource
adequacy requirements for loads within
the transmission service provider’s area
established by other entities, such as
municipalities, state commissions,
regional transmission organizations,
37 NERC defines the generation capability import
requirement as the amount of generation capability
from external sources identified by a load-serving
entity or resource planner to meet its generation
reliability or resource adequacy requirement as an
alternative to internal resources.
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independent system operators, regional
reliability organizations, or regional
entities. Once determined, the capacity
benefit margin values will be allocated
along available transfer capability paths
based on the expected import paths or
source regions provided by load-serving
entities or resource planners. Capacity
benefit margin values for flowgates will
be allocated based on the expected
import paths or source regions provided
by load-serving entities or resource
planners and the distribution factors
associated with those paths or regions,
as determined by the transmission
service provider.
32. Requirements R7 and R8 require
the transmission service provider and
the transmission planner to notify all
load-serving entities and resource
planners that determined they had a
need for capacity benefit margin of the
amount, or the amount planned, of
capacity benefit margin set aside, within
31 calendar days after the establishment
of capacity benefit margin.
33. Requirement R9 requires the
transmission service provider that
maintains capacity benefit margin and
the transmission planner to provide,
subject to confidentiality and security
requirements, copies of the applicable
supporting data, including any models,
used for determining capacity benefit
margin or allocating capacity benefit
margin over each available transfer
capability path or flowgate to each of
the associated transmission operators
and to any transmission service
provider, reliability coordinator,
transmission planner, resource planner,
or planning coordinator within 30
calendar days of their making a request
for the data.
34. Requirement R10 requires the
load-serving entity or balancing
authority to request to import energy
over firm transfer capability set aside as
capacity benefit margin only when
experiencing a declared level 2 or
higher NERC energy emergency alert.38
35. When reviewing an arranged
interchange service request using
capacity benefit margin, Requirement
R11 requires all balancing authorities
and transmission service providers to
waive, within the bounds of reliable
operation, any real-time timing and
ramping requirements.
36. Requirement R12 requires all
transmission service providers
38 Under
Reliability Standard EOP–002–2
Reliability Coordinators initiate an energy
emergency alert when a balancing authority within
its control area experiences a potential or actual
energy emergency. NERC has established three
levels of energy emergency alerts (one through
three) to clarify the severity of the potential or
actual energy emergency.
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maintaining capacity benefit margin to
approve, within the bounds of reliable
operation, any arranged interchange
using capacity benefit margin that is
submitted by an ‘‘energy deficient
entity’’ 39 under an energy emergency
alert level 2 if the capacity benefit
margin is available, the emergency is
declared within the balancing authority
area of the energy deficient entity, and
the load of the energy deficient entity is
located within the transmission service
provider’s area.
37. NERC states that MOD–004–1
complies with the requirements of
Order No. 890 and related directives of
Order No. 693 because it sets criteria
that allow load-serving entities to
request transfer capability to be set aside
in the form of capacity benefit margin in
a consistent and transparent manner.
Consistent with the Commission’s
direction, the Reliability Standard
provides an approach for determining
capacity benefit margin that is flexible
and does not mandate a particular
methodology.40 NERC supports this
approach because various parts of the
country have already developed robust
methodologies for determining capacity
benefit margin. NERC states that
Requirements R3 and R4 allow loadserving entities and resource planners to
perform specific studies to determine
their need for capacity benefit margin.
By specifying the types of studies loadserving entities or resource planners
must perform, NERC contends that
MOD–004–1 ensures that capacity
benefit margin and transmission
reliability margin are not used for the
same purpose.41 In response to the
Commission’s transparency
requirement,42 NERC states that
Requirement R9 ensures that capacity
benefit margin studies are made
available to the appropriate reliability
entities for their review and analysis.
With regard to public disclosure, NERC
states that it has agreed with NAESB
that requirements for posting
information are more appropriately
addressed through the NAESB process.
38. Requirements R5 and R6 require
that the transmission service provider
and transmission planner utilize the
information contained in the studies if
it has been provided to them when
establishing capacity benefit margin
values and mandate the re-evaluation of
39 Energy deficient entities are defined by NERC
in the Capacity and Energy Emergencies Reliability
Standard. See EOP–002–2, Attachment 1.
40 Citing Order No. 693, FERC Stats. & Regs.
¶ 31,242 at P 1078; see also Order No. 890, FERC
Stats. & Regs. ¶ 31,241 at P 257.
41 Citing Order No. 693, FERC Stats. & Regs.
¶ 31,242 at P 1105.
42 Citing id. P 1077.
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capacity benefit margin at least once
every thirteen months.43 NERC states
that, consistent with Order Nos. 890 and
693, Requirements R5 and R6 also
require allocation of capacity benefit
margin based on the available transfer
methodology chosen under MOD–001–
1.44 NERC states that Requirements R10,
R11 and R12 specify the manner in
which capacity benefit margin is to be
used.45 NERC states that any additional
requirements specified by the
transmission service provider must be
identified in the capacity benefit margin
implementation document, as mandated
in Requirement R1.3.
39. In response to the requirement
that capacity benefit margins values be
verifiable,46 NERC states that
Requirements R5, R6 and R9 ensure that
the studies used to establish a need for
capacity benefit margin are made
available to any of the reliability entities
specified in Requirement R9 that
request them. NERC explains that the
Reliability Standard does not mandate
the verification of amounts of capacity
benefit margin requested by the
transmission service provider because it
would place a functional entity (either
the transmission service provider or
transmission planner) in the position of
having to judge the quality of each
request, which could create conflicts of
interest or potentially result in liability
for that entity. Rather than mandate any
particular approach for validation,
NERC states that Requirements R3 and
R4 mandate the specific kinds of studies
to be performed and supporting
information that is to be maintained
when determining the underlying need
for capacity benefit margin. To the
extent that entities do not use these
methods or maintain this supporting
information, NERC states that they will
be in violation of the Reliability
Standard.
40. In response to the Commission’s
call for clarity in the process for
requesting capacity benefit margin,47
NERC states that Requirement R1.1
requires the transmission service
provider to explain the process by
which load-serving entities and resource
planners may ensure that their need for
transmission capacity to be set aside as
capacity benefit margin is reviewed and
43 Citing Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 358. NERC states that it chose thirteen
months to ensure enough flexibility for a yearly
update without being so prescriptive as to require
it on a specific day.
44 Citing id. P 257; Order No. 693, FERC Stats. &
Regs. ¶ 31,242 at P 1082.
45 Citing Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 256–7.
46 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 1077.
47 Id. P 1081.
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accommodated by the transmission
service provider to the extent
transmission capacity is available.
Requirement R1.3 requires the
transmission service provider to
describe the procedure for load-serving
entities and resource planners to use
transmission capacity that has been set
aside as capacity benefit margin. If the
requested use of capacity benefit margin
exceeds the amount of capacity benefit
margin available, Requirement R1.3 also
requires a description of how the
transmission service provider will
manage such situations. In addition,
NERC states that Requirements R7 and
R8 mandate that the transmission
service provider notify load-serving
entities and resource planners that
determined they had a need for capacity
benefit margin of the amount of capacity
benefit margin set aside, so that they
may make informed decisions about
how to proceed if their full request for
capacity benefit margin could not be
accommodated.
D. Transmission Reliability Margin
Methodology, MOD–008–1
41. The Transmission Reliability
Margin Methodology Reliability
Standard (MOD–008–1) provides for the
calculation of transmission reliability
margin. Transmission reliability margin
is transmission transfer capability set
aside to mitigate risks to operations,
such as deviations in dispatch, load
forecast, outages, and similar such
conditions.48 It is distinctly different
from capacity benefit margin, which is
transmission transfer capability set
aside to allow for the import of
generation upon the occurrence of a
generation capacity deficiency. MOD–
008–1 describes the reliability aspects of
determining and maintaining a
transmission reliability margin and the
components of uncertainty that may be
considered when making that
calculation. The purpose of this
Reliability Standard is to promote the
consistent and reliable calculation,
verification, preservation, and use of
transmission reliability margin to
support analysis and system operations.
42. Reliability Standard MOD–008–1
applies only to transmission operators
that have elected to keep a transmission
reliability margin. As discussed more
fully in the discussion section below,
NERC states that the Reliability
Standard does not specify one approach
for calculating transmission reliability
margin, but rather improves
transparency by providing the key
48 See NERC Glossary, available at: https://
www.nerc.com/docs/standards/rs/
Glossary_2009April20.pdf.
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64891
requirements and items that must be
contained in any transmission reliability
margin methodology.
43. To improve the transparency of
transmission reliability margin
calculations, the Reliability Standard
imposes five requirements on
transmission service providers electing
to keep a transmission reliability
margin. Requirement R1 provides that a
transmission operator must keep a
transmission reliability margin
implementation document that explains
how specific risks such as aggregate
load forecast uncertainty, load
distribution uncertainty, and forecast
uncertainty in transmission system
topology 49 are accounted for in the
transmission reliability margin, how
transmission reliability margin is
allocated, and how transmission
reliability margin is determined for
various time frames.
44. Requirement R2 allows a
transmission operator to account only
for the risks identified in Requirement
R1 in transmission reliability margin,
and prohibits the transmission operator
from incorporating risks that are
addressed in capacity benefit margin. It
allows reserve sharing to be included in
transmission reliability margin.
45. Requirement R3 requires each
applicable entity to make the
transmission reliability margin
implementation document and
associated information available to the
following reliability entities if
requested: Transmission service
provider, reliability coordinator,
planning coordinator, transmission
planner, and transmission operator.
46. Requirement R4 provides that
each applicable transmission operator
must determine the transmission
reliability margin value per the methods
described in the transmission reliability
margin implementation document at
least once every thirteen months.
Finally, Requirement R5 states that each
applicable transmission operator must
provide that transmission reliability
margin value to its transmission service
providers and transmission planners no
more than seven days after it has been
determined.
47. NERC states that MOD–008–1
complies with Order No. 890 by
specifying the critical areas of analysis
49 This includes, but is not limited to: Forced or
unplanned outages and maintenance outages;
allowances for parallel path (loop flow) impacts;
allowances for simultaneous path interactions;
variations in generation dispatch (including, but not
limited to, forced or unplanned outages,
maintenance outages and location of future
generation); short-term system operator response
(operating reserve actions); reserve sharing
requirements; and inertial response and frequency
bias.
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required for transmission reliability
margin.50 Further, it states that it has
specified the appropriate uses of
transmission reliability margin in
Requirement R1 and prohibited the use
of other values and double counting in
Requirement R1. In addition, it
maintains that MOD–008–1 complies
with Order No. 693 by imposing clear
requirements for making available
documents supporting the transmission
reliability margin determination through
Requirements R1 and R3.
48. In response to the requirement to
expand the applicability of the
transmission reliability margin
Reliability Standard to planning
authorities and reliability
coordinators,51 NERC states that the
drafting team was not able to identify
any requirements for these entities,
based on the current drafting of the
Reliability Standard. Therefore, these
entities are not included in the
proposed Reliability Standard. NERC
states that, until such time as the
transmission reliability margin
methodology becomes more detailed,
there does not seem to be any
measurable action that can be imposed
on the planning coordinator or
reliability coordinator.
49. In response to the Commission’s
statement that it would not require
transfer capability that is set aside as
transmission reliability margin to be
sold on a non-firm basis,52 NERC states
that it has included this requirement in
each of the three methodologies as a
part of firm and non-firm equations.
NERC states that, because some of the
uncertainties included in the
transmission reliability margin may be
reduced or eliminated as one
approaches real time, the non-firm
equations allow for the partial release of
transmission reliability margin.
50. NERC contends that choosing a
‘‘best’’ approach to transmission
reliability margin calculation would
require a much more thorough technical
effort. NERC therefore requests that the
Commission provide additional
guidance on this topic regarding its
priority and a determination whether or
not such an effort should be included in
NERC’s annual planning process.
E. Three Methodologies for Calculating
Available Transfer Capability
51. In Order No. 890, the Commission
did not require a uniform methodology
for calculating available transfer
50 NERC Filing at 32 (citing Order No. 890, FERC
Stats. & Regs. ¶ 31,241 at P 273).
51 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 1126.
52 See Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 273.
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capability. The Commission noted that
NERC was developing Reliability
Standards for three available transfer
capability calculation methodologies
and concluded that, if all of the
available transfer capability components
and certain data inputs and assumptions
are consistent, the three available
transfer capability calculation
methodologies being developed by
NERC will produce predictable and
sufficiently accurate, consistent,
equivalent and replicable results.53
Consistent with Order No. 890, NERC
developed three methodologies for
calculating available transfer capability
as detailed in the following Reliability
Standards: MOD–028–1, MOD–029–1
and MOD–030–2. NERC contends that
these three methodologies meet the
requirements established by the
Commission in Order No. 890, as well
as those established in Order No. 693.
52. NERC asserts that the three
methodologies are a significant
improvement over the existing available
transfer capability related requirements.
While current MOD–001–0 is essentially
a ‘‘fill-in-the-blank’’ Reliability
Standard,54 the methodologies replace
the original fill-in-the blank standard by
specifying in detail how total transfer
capability is to be determined—from
modeling requirements, to the
simulation of dispatch to determine
native load impacts, to the treatment of
reservations and to the incorporation of
neighboring data. According to NERC,
MOD–001–1 specifies how existing
transmission commitments and
available transfer capability are to be
determined in detail and clearly
describes the treatment of capacity
benefit margin and transmission
reliability margin in the available
transfer capability equations. Thus,
NERC contends, these Reliability
Standards reduce the potential for
seams discrepancies and improve the
wide-area understanding of the BulkPower System on a forward-looking
basis. NERC states that, by promoting
consistency, standardization and
transparency, they directly support and
improve the reliability of the BulkPower System and help achieve the
Commission’s objectives stated in Order
No. 890.
53 Id.
P 210.
fill-in-the-blank Reliability Standard requires
the regional entities to develop criteria for use by
users, owners or operators within each region. In
Order No. 693, the Commission held 24 Reliability
Standards (mainly fill-in-the-blank standards) as
pending until further information was provided on
each standard and requires users, owners and
operators to follow these pending standards as
‘‘good utility practice’’ pending their approval by
the Commission.
54 A
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1. Area Interchange Methodology,
MOD–028–1
53. NERC states that the area
interchange methodology is
characterized by determination of
incremental transfer capability via
simulation, from which total transfer
capability can be mathematically
derived. Capacity benefit margin,
transmission reliability margin, and
existing transmission commitments are
subtracted from the total transfer
capability, and postbacks and
counterflows are added, to derive
available transfer capability. NERC also
states that, under the area interchange
methodology, total transfer capability
results are generally reported on an area
to area basis.
54. MOD–028–1 describes the area
interchange methodology (previously
referred to as the network response
available transfer capability
methodology) for determining available
transfer capability. NERC intends to use
the Area Interchange Methodology
Reliability Standard to increase
consistency and reliability in the
development and documentation of
transfer capability calculation for shortterm use performed by entities using the
area interchange methodology to
support analysis and system operations.
55. This Reliability Standard applies
only to transmission operators and
transmission service providers that elect
to implement this particular
methodology as part of their compliance
with MOD–001–1, Requirement R1. The
proposed Reliability Standard consists
of eleven requirements. Requirement R1
provides the additional information that
a transmission service provider using
the area interchange methodology must
include in its available transfer
capability implementation document.
The document must include
information describing how the selected
methodology has been implemented, in
such detail that, given the same
information used by the transmission
operator, the results of the total transfer
capability calculations can be validated.
The document must also include a
description of the manner in which the
transmission operator will account for
interchange schedules in the calculation
of total transfer capability; any
contractual obligations for allocation of
total transfer capability; a description of
the manner in which contingencies are
identified for use in the total transfer
capability process; and information on
how sources and sinks for transmission
service are accounted for in available
transfer capability calculations.
56. Pursuant to Requirement R2, each
transmission operator must calculate
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total transfer capability using a model
that meets the scope specified in the
requirement and includes rating
information specified by generator
owners and transmission owners whose
equipment is represented in the model.
57. Requirement R3 details the
information the transmission operator
must include in its determination of
total transfer capability for the on-peak
and off-peak intra-day and next day
time periods, as well as days two
through 31 and for months two through
13.55 Requirement R4 requires each
transmission operator to determine total
transfer capability while modeling
contingencies and reservations
consistently, and respect any
contractual allocations of total transfer
capability.
58. Requirement R5 provides that
each transmission operator must
determine total transfer capability on a
periodic basis (as specified in the
requirement) or upon certain operating
conditions significantly affecting bulk
electric system topology.
59. Requirement R6 provides the
detailed process by which each
transmission operator must establish
total transfer capability, which it must
communicate to the transmission
service provider within the time frames
specified in Requirement R7.
60. Requirements R8 through R11
specify the formulas and provide
descriptions of the variables to be used
to calculate firm and non-firm existing
transmission commitments and firm and
non-firm available transfer capability.
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2. Rated System Path Methodology,
MOD–029–1
61. NERC states that the rated system
path methodology is characterized by an
initial total transfer capability,
determined via simulation. As with the
area interchange methodology, capacity
benefit margin, transmission reliability
margin, and existing transmission
commitments are subtracted from the
total transfer capability, and postbacks
and counterflows are added, to derive
available transfer capability. NERC also
states that, under the rated system path
methodology, total transfer capability
results are generally reported as specific
transmission path capabilities.
62. MOD–029–1 describes the rated
system path methodology for
determining available transfer
capability. NERC intends to use this
Reliability Standard to increase
consistency and reliability in the
55 This information includes: expected generation
and transmission outages, additions, and
retirements; load forecasts; and unit commitment
and dispatch order.
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development and documentation of
transfer capability calculations for shortterm use performed by entities using the
rated system path methodology to
support analysis and system operations.
63. This Reliability Standard applies
only to transmission operators and
transmission service providers that have
elected to implement rated system path
methodology as part of their compliance
with MOD–001–1, Requirement R1. To
implement this calculation, this
Reliability Standard consists of eight
requirements. Under Requirement R1, a
transmission operator must calculate
total transfer capability using a model
that meets the scope and criteria
specified in the requirement.
Requirement R2 lists a detailed process
by which the transmission operator
must establish total transfer capability.
Pursuant to Requirement R3, the
transmission operator must establish
total transfer capability as the lesser of
the system operating limit 56 or the
value determined in Requirement R2.
The transmission operator must then
provide a transmission service provider
with the appropriate total transfer
capability values and study report
within seven days of finalization of the
study report to be prepared under in
Requirement R4.
64. Requirements R5 through R8
provide that each applicable
transmission service provider must
calculate firm and non-firm existing
transmission commitments and firm and
non-firm available transfer capability
using a specified formula and also
provides detailed descriptions of the
variables to be used.
3. Flowgate Methodology, MOD–030–2
65. NERC states that the flowgate
methodology is characterized by
identification of key facilities as
flowgates. Total flowgate capabilities are
determined based on facility ratings and
voltage and stability limits. The impacts
of existing transmission commitments
are determined by simulation. To
determine the available flowgate
commitments, the transmission service
provider or operator must subtract the
impacts of existing transmission
commitments, capacity benefit margin,
and transmission reliability margin, and
add the impacts of postbacks and
counterflows. Available flowgate
capability can be used to determine
available transfer capability.
56 The NERC Glossary defines a system operating
limit as the value (such as MW, MVar, Amperes,
Frequency or Volts) that satisfies the most limiting
of the prescribed operating criteria for a specified
system configuration to ensure operation within
acceptable reliability criteria.
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64893
66. MOD–030–2 describes the
flowgate methodology for determining
available transfer capability. NERC
states that the purpose of the Flowgate
Methodology Reliability Standard is to
increase consistency and reliability in
the development and documentation of
transfer capability calculations for shortterm use performed by entities using the
flowgate methodology to support
analysis and system operations.
67. This Reliability Standard applies
only to transmission operators and
transmission service providers that have
elected to implement this particular
methodology as part of their compliance
with MOD–001–2. As proposed, the
Flowgate Methodology consists of
eleven requirements. Requirement R1
states that a transmission service
provider implementing this
methodology must include the
following information in its available
transfer capability implementation
document in addition to that already
required in the Available Transmission
System Capability Reliability Standard
(MOD–001–1): The criteria used by the
transmission operator to identify sets of
transmission facilities as flowgates that
are to be considered in available
flowgate capability calculations, and
information on how sources and sinks
for transmission service are accounted
for in available flowgate capability
calculations.
68. Under Requirement R2, each
applicable transmission operator must
determine and manage the flowgates
used in the methodology based on the
criteria listed in the requirement,
establish its total flowgate capability
based on the criteria listed in the
requirement, and provide total flowgate
capability to the transmission service
provider within seven days of their
determination. To achieve consistency
in each component of the available
transfer capability calculation, the
Commission, in Order No. 890, directed
public utilities, working through NERC,
to develop an available flowgate
capability definition and requirements
used to identify a particular set of
transmission facilities in a flowgate.57
As part of the development of the
Flowgate Methodology, NERC states that
the Reliability Standard drafting team
developed a definition of available
flowgate capability. In addition, NERC
states that Requirement R2 of this
Reliability Standard contains a list of
minimum characteristics that are to be
used to identify a particular set of
transmission facilities as a flowgate.
57 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 313.
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69. Requirement R3 requires the
transmission operator to provide the
transmission service provider with a
transmission model that meets a
specified criteria and Requirement R4
provides that the transmission service
provider must evaluate reservations
consistently when determining available
flowgate capability. When determining
available flowgate capability,
Requirement R5 provides that each
transmission service provider must use
the models given to it as described in
Requirement R3, include appropriate
outages, and use the available flowgate
capability on external flowgates as
provided by the transmission service
provider calculating available flowgate
capability for those flowgates.
70. Requirements R6 and R7 require
each transmission service provider to
calculate the impact of firm and nonfirm existing transmission commitments
using a specified process. The
transmission service provider must
calculate firm and non-firm available
flowgate capability using the formula
and detailed specification of the
variables found in Requirements R8 and
R9.
71. Under Requirement R10, each
transmission service provider shall
recalculate available flowgate capability
at a certain specified interval (hourly
once per hour, daily once per day,
monthly once per week) unless the
input values specified in the available
flowgate capability calculation have not
changed. NERC contends that this
requirement satisfies the requirement in
Order No. 890 and Order No. 693 that
transmission service providers
recalculate available transfer capability
on a consistent time interval. Finally,
Requirement R11 provides the formula
and variables that a transmission service
provider must use if it desires to convert
available flowgate capability to available
transfer capability.
F. Implementation Plan
72. NERC requests that the Available
Transmission System Capability
Reliability Standard and the three
methodology Reliability Standards
become effective the first day of the first
quarter no sooner than one calendar
year after approval of all of these four
Reliability Standards by all appropriate
regulatory authorities where approval is
required or is otherwise effective in
those jurisdictions where approval is
not explicitly required. NERC notes that
Requirement R9 of the Available
Transmission System Capability
Reliability Standard (MOD–001–1)
establishes the requirement for entities
to develop certain information and the
three methodology Reliability Standards
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rely on this information from
neighboring reliability entities for use in
the development of its available transfer
capability and available flowgate
capability values. Due to this reliance
on the MOD–001–1 information, NERC
concludes that none of the methodology
Reliability Standards can be effectively
implemented unless and until MOD–
001–1 has been implemented by all
entities in all jurisdictions.
73. NERC states that, although some
entities may already be implementing
the requirements in the Reliability
Standards, many others are not,
especially with regard to the data
exchange requirements listed in
Requirement R9 of MOD–001–1.
Accordingly, software changes,
associated testing, and possible tariff
filings will be required to comply with
the proposed Reliability Standards.
Therefore, NERC maintains that a
minimum of one year from regulatory
approval should be allowed for entities
to comply.
74. NERC requests that each of the
Capacity Benefit Margin (MOD–004–1)
and Transmission Reliability Margin
(MOD–008–1) Reliability Standards
require compliance on the first day of
the first quarter no sooner than one
calendar year after approval of the
Reliability Standard by appropriate
regulatory authorities where approval is
required or, where approval is not
explicitly required, when the Reliability
Standard is otherwise effective.58
According to NERC, unlike the other
four proposed Reliability Standards
included in this filing, the Transmission
Reliability Margin Reliability Standard
replaces the existing Reliability
Standard MOD–008–0 and the Capacity
Benefit Margin Reliability Standard
replaces MOD–004–0. As such, they do
not require coordinated
implementation, as entities may rely on
the previous version of the Reliability
Standards if any delay in implementing
the Reliability Standards occurs. NERC
states that, although many entities
already use transmission reliability
margin and capacity benefit margin,
compliance with these Reliability
Standards may require software
changes, software regression testing, and
possible tariff changes. To accommodate
these needs, NERC believes a one-year
implementation period is appropriate.
58 In jurisdictions where regulatory approval is
not required, the MOD–004–1 and MOD–008–1 will
become effective on the first day of the first
calendar quarter that is twelve months after the date
of approval by the NERC Board of Trustees.
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III. Discussion
A. Approval, Implementation and Audit
of the MOD Reliability Standards
NOPR Proposal
75. In the NOPR, the Commission
proposed to approve the Reliability
Standards filed by NERC in this
proceeding as just, reasonable, not
unduly discriminatory or preferential,
and in the public interest.59 The
Commission stated that these Reliability
Standards represent a step forward in
eliminating the broad discretion
previously afforded transmission service
providers in the calculation of available
transfer capability.
76. The Available Transmission
System Capability Reliability Standard
(MOD–001–1) serves as an ‘‘umbrella’’
Reliability Standard that requires each
applicable entity to select and
implement one or more of the three
available transfer capability
methodologies found in MOD–028–1,
MOD–029–1, or MOD–030–2. Reliability
Standards MOD–004–1 and
MOD–008–1 provide for the calculation
of capacity benefit margin and
transmission reliability margin, which
are inputs into the available transfer
capability calculation. Together, these
Reliability Standards require
transmission service providers and
transmission operators to prepare and
keep current implementation
documents that contain certain
information specified in the Reliability
Standards. The available transfer
capability implementation documents
must describe the available transfer
capability methodology in such detail
that the results of their calculations can
be validated when given the same
information used by the transmission
service provider or transmission
operator.60
77. The Commission expressed
concern in the NOPR that the proposed
Reliability Standards could be
implemented by a particular
transmission service provider or
transmission operator in a way that
enables them to unduly discriminate in
the provision of open access
transmission service. The Commission
observed that, although the Reliability
Standards require transmission service
providers to include certain minimum
information in each of the
implementation documents,
transmission service providers are also
permitted to include additional,
undefined parameters and assumptions
in those documents.61 The Commission
59 NOPR,
FERC Stats. & Regs. ¶ 32,641 at P 75.
Requirement R3.
61 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 81.
60 MOD–001–1,
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explained that these documents could
include criteria that are themselves not
sufficiently transparent to allow the
Commission and others to determine
whether they have been consistently
applied by the transmission service
provider in particular circumstances. As
noted by the Commission, this
discretion appears in the three available
transfer capability methodologies
(MOD–028–1, MOD–029–1, an MOD–
030–2), as well as the Reliability
Standards governing the calculation of
capacity benefit margin (MOD–004–1)
and transmission reliability margin
(MOD–008–1).
78. The Commission clarified in the
NOPR that it is appropriate for
transmission service providers to retain
some level of discretion in the
calculation of available transfer
capability. Requiring absolute
uniformity in criteria and assumptions
across all transmission service providers
would preclude transmission service
providers from calculating available
transfer capability in a way that
accommodates the operation of their
particular systems. The Commission
explained that the Reliability Standards
need not be so specific that they address
every unique system difference or
differences in risk assumptions when
modeling expected flows. Instead, each
transmission service provider should
retain some discretion to reflect unique
system conditions or modeling
assumptions in its available
transmission capability methodology.62
The Commission stated that any such
system conditions or modeling
assumptions, however, must be made
sufficiently transparent and be
implemented consistently for all
transmission customers.
79. In order to ensure adequate
transparency, the Commission proposed
to direct the ERO to conduct a review
of the additional parameters and
assumptions included by each
transmission service provider in its
available transfer capability, capacity
benefit margin, and transmission
reliability margin implementation
documents. In its audit, NERC would
identify any parameters and
assumptions that are not sufficiently
specific or transparent to allow the
Commission and others to replicate and
verify the results of the transmission
service provider’s calculation of
available transfer capability or available
flowgate capability, capacity benefit
margin, and transmission reliability
margin. Upon review of NERC’s
analysis, the Commission indicated that
62 Order
No. 890–A, FERC Stats. & Regs. ¶ 31,261
at P 51.
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it may direct the ERO to develop a
modification to MOD–001–1, MOD–
004–1, and MOD–008–1 to address any
lack of transparency. The Commission
proposed to direct the ERO to complete
this audit no later than 180 days after
the effective date of the Reliability
Standards.
80. The Commission emphasized that
it did not intend to require the
development of a single, uniform
methodology for calculating available
transfer capability or its components. In
Order No. 890, the Commission found
that the potential for discrimination
does not lie primarily in the choice of
an available transfer capability
methodology, but rather in the
consistent application of its
components.63 The Commission stated
that it acknowledged in Order No. 890
that NERC was developing standards for
three available transfer capability
calculation methodologies. The
Commission concluded that, if all of the
available transfer capability components
and certain data inputs and assumptions
are consistent, the three available
transfer capability calculation
methodologies being developed by
NERC would produce predictable and
sufficiently accurate, consistent,
equivalent and replicable results.64
81. The Commission clarified in the
NOPR that this does not mean that the
results of available transfer capability
calculations on either side of an
interface must be identical in every
instance. The Commission stated that
there are fundamental differences in the
three available transfer capability
methodologies set forth in the proposed
Reliability Standards that may keep
them from producing identical results.
Even where the same methodology is
used by transmission service providers
on either side of an interface, the
Commission stated that unique system
differences or differences in risk
assumptions can lead to variations in
available transfer capability values.
82. The Commission also reiterated
that available transfer capability reforms
approved herein address interests
related to the Commission’s open access
goals and the reliable operation of the
Bulk-Power System.
1. Approval of the MOD Reliability
Standards
Comments
83. Many commenters support the
Commission’s proposed approval of the
63 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 208.
64 Id. P 210.
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64895
proposed MOD Reliability Standards.65
For example, FirstEnergy contends that
the MOD Reliability Standards, as
proposed, completely address the
calculation of ATC and its
corresponding TTC values. Others agree
that the Reliability Standards represent
a step forward in eliminating the broad
discretion previously afforded
transmission service providers in the
calculation of available transfer
capability.66 In addition, several
commenters state that the proposed
MOD Reliability Standards will provide
greater transparency and consistency in
the calculation of available transfer
capability, available flowgate capability,
capacity benefit margins and
transmission reliability margins within
the transmission service industry.67
84. NRU, Pacific Northwest, the
Public Power Council and Snohomish
agree with the Commission that the use
of the proposed Reliability Standards,
indeed the use of any one standard, may
not produce identical results when
applied to a different transmission
system. They also agree that, even when
the same methodology is used by
transmission service providers on either
side of an interface, unique system
differences or differences in risk
assumptions can lead to variations in
available transmission capability values.
They state that they agree with the
Commission that this will occur and is
an acceptable result. They contend that
each transmission provider must retain
sufficient discretion to make
assumptions and represent its system in
the calculation such that its system
reliability is assured.
85. To the extent that there are any
outstanding issues not addressed in
NERC’s filing, APPA, the Georgia
Companies and the Joint Municipals
contend that the Commission should
allow industry to address such issues
through the NERC Reliability Standards
development process. The Joint
Municipals state that, imperfect though
it is, the Reliability Standards
development process is unequalled in
its ability to secure industry input,
cooperation and often consensus in the
development of industry-wide
protocols.
86. Midwest ISO states that it concurs
that multiple available transfer
capability methodologies should be
permitted but disagrees that a different
Reliability Standard should be
developed for each methodology.
65 APPA, Bonneville, Duke, EEI, EPSA, Entegra,
FirstEnergy, Georgia, ISO/RTO Council, SMUD and
NERC.
66 APPA, Bonneville, and ISO/RTO Council.
67 Bonneville, ISO/RTO Council, Joint
Municipals, and SMUD.
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Midwest ISO contends that
notwithstanding the use of an umbrella
Reliability Standards, imposing a
separate standard for each methodology,
and corresponding risks of noncompliance therewith, could create a
deterrent to using the methodology that
provides the greatest benefits to
reliability, where that methodology has
higher compliance risks.
Commission Determination
87. The Commission adopts the NOPR
proposal and approves the MOD
Reliability Standards and related
additions to the NERC Glossary, to be
effective as proposed by NERC, as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest. By promoting consistency,
standardization and transparency, these
Reliability Standards enhance the
reliability of the Bulk-Power System.
88. The MOD Reliability Standards
also represent a step forward in
eliminating the broad discretion
previously afforded transmission service
providers in the calculation of available
transfer capability. As the Commission
explained in Order No. 890, excessive
discretion in the calculation of available
transfer capability gives transmission
service providers the opportunity to
discriminate in subtle ways in the
provision of open access transmission
service.68 On systems where
transmission capacity is constrained, a
lack of transparency and consistency in
the calculation of available transfer
capability has led to recurring disputes
over whether transmission service
providers have performed those
calculations in a way that discriminates
against competitors.
89. The Commission acted in Order
No. 890 to limit this remaining
opportunity for discrimination by
directing public utilities, working
through NERC, to develop Reliability
Standards to govern the consistent and
transparent calculation of available
transfer capability by transmission
service providers. In Order No. 693, the
Commission implemented that directive
by requiring NERC to prospectively
modify the MOD Reliability Standards it
filed in April 2006 to address the
requirements of Order No. 890. The
proposed Reliability Standards satisfy
the Commission’s requirements by
enhancing transparency and consistency
in the calculation of available transfer
capability, mandating that transmission
service providers and transmission
operators perform their calculations in
accordance with methodologies that are
68 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 68.
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both explicitly documented and
available to reliability entities who
request them. The proposed Reliability
Standards also require documentation of
the detailed representations of the
various components that comprise the
available transfer capability equation,
and require transmission service
providers and transmission operators to
specify modeling and risk assumptions
and disclosure of outage processing
rules to other reliability entities. These
actions will make the processes to
calculate available transfer capability
and its various components more
transparent which, in turn, will allow
the Commission and others to ensure
that those calculations are performed
consistently.
90. The Commission finds that
Midwest ISO’s concerns regarding the
structure of the Reliability Standards to
be misplaced. NERC, working through
its Reliability Standards development
process, developed the six Reliability
Standards approved herein. The
Commission believes that each
Reliability Standard adequately ensures
the reliable operation of the Bulk-Power
System and, thus, sees no basis for
limiting which methodology is chosen
to calculate available transfer or
flowgate capability. We believe that
Midwest ISO’s remaining concerns,
including variation in relative
compliance burdens or risks among the
three methodologies, are best
considered through NERC’s enforcement
and compliance program.
91. As discussed in greater detail later
in the Final Rule, the Commission has
concern regarding several of the
substantive requirements of the
proposed Reliability Standards. To
address these concerns, pursuant to
section 215(d)(5) of the FPA and section
39.5(f) of our regulations, the
Commission directs the ERO to develop
modifications to the Reliability
Standards to address discrete issues
involving: The availability of each
transmission service provider’s
implementation documents; the
consistent treatment of assumptions in
the calculation of available transfer
capability; the calculation, allocation,
and use of capacity benefit margin; the
calculation of total transfer capability
under the Rated System Path
Methodology; the treatment of network
resource designations in the calculation
of available transfer capability; and
several other issues raised by
commenters.
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2. Implementation Timeline
Comments
92. EEI contends that the
implementation date is ambiguous. EEI
states that the implementation timeline
could be understood to mean that the
effective date of the Reliability
Standards is either on the first day of
the first quarter occurring 365 days after
approval of these Reliability Standards
or on January 1 of the year following a
full calendar year after approval.
Accordingly, EEI asks the Commission
to clarify the intended implementation
timeline.
93. Bonneville contends that a oneyear implementation timeframe is
unrealistic for certain portions of the
proposed MOD Reliability Standards.
Bonneville states that it has been
preparing to comply with the flowgate
methodology approach set forth in
MOD–030–2. Bonneville states that, to
date, it has identified twelve adjacent
transmission service providers from
which it will likely need to request data
to determine the impacts on
Bonneville’s network flow based system
of the existing network integration
transmission service, point-to-point
transmission service, and grandfathered
commitments reserved on those
providers’ systems as required by
Requirements R6 and R7 of MOD–030–
2. Although Bonneville can request its
adjacent transmission service providers
to provide that data in aggregate form
pursuant to Requirement R9 of MOD–
001–1, Bonneville contends that, to
obtain sufficiently detailed data, it will
have to coordinate separate data
exchange arrangements with each
adjacent transmission service provider.
Bonneville states that it is unlikely that
it will be able to accomplish this, along
with the necessary software changes,
associated testing, and possible tariff
filings that would be required to comply
with the proposed Reliability Standard,
within one year. Accordingly,
Bonneville asks that the Commission
establish a two-year implementation
compliance timeframe or, in the
alternative, allow entities to request
extensions on a case-by-case basis.
94. In contrast, EPSA contends that
the Commission should advance the
implementation schedule. EPSA states
that NERC provided no support for why
it will take a full year from Commission
approval to implement MOD–001–1.
EPSA contends that transmission
service providers have long known that
Order No. 890’s available transfer
capability reform was coming. EPSA
further contends that much of what is
proposed in the MOD NOPR could be
accomplished during the MOD NOPR’s
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development, if not before. EPSA
questions whether the documentation
process and accompanying software
changes will require a full year. Absent
compelling reasons, EPSA argues that
the Commission should reject the
proposed implementation timeline and
set a new timeline that accommodates
actual implementation issues so as not
to defer any longer the benefits of Order
No. 890.
Commission Determination
95. As approved, the Reliability
Standards shall become effective on the
first day of the first calendar quarter that
is twelve months beyond the date that
the Reliability Standards are approved
by all applicable regulatory authorities.
The Commission finds that the
approved implementation schedule
strikes a reasonable balance between the
need for timely reform and the needs of
transmission service providers and
transmission operators to make
adjustments to their calculations of
available transfer capability, capacity
benefit margin and transfer reliability
margin. To the extent necessary, we
clarify that, under this plan, the
Reliability Standards shall become
effective on the first day of the first
quarter occurring 365 days after
approval by all applicable regulatory
authorities. Approval by the
Commission will be effective 60 days
after the date of publication of this Final
Rule in the Federal Register. If a
transmission service provider or
transmission operator is unable to
implement these Reliability Standards
within the time allowed, requests for
extension should be considered through
NERC’s enforcement and compliance
program.
3. Implementation Document Audits
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a. Authority To Direct Audits
Comments
96. Many commenters expressed
concern that the Commission’s proposal
to direct NERC to conduct audits of the
available transfer capability, capacity
benefit margin and transfer reliability
margin implementation documents
would be an inappropriate use of the
Commission’s authority under section
215 of the FPA.69 They contend that the
proposed audits would engage NERC in
the Commission’s market oversight
functions, and expand the scope of the
ERO’s delegated responsibilities beyond
its statutory duty to develop and enforce
69 E.g., NERC, Duke, EEI, EPSA, EEI, Entegra, the
Georgia Companies, ISO/RTO Council, NRU,
NYISO, Pacific Northwest, Public Power Council,
Snohomish, Puget Sound, SMUD, Joint Municipals,
and TANC.
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Reliability Standards to ensure the
reliability of the Bulk-Power System.
97. NERC states that section 215
recognizes the distinction between
reliability matters (where the
Commission is to give ‘‘due weight to
the technical expertise of the ERO’’),
and matters affecting competition
(where the Commission is to give no
such deference). NERC states that, while
it understands that consistent treatment
of transmission customers in functions
related to competitions and markets is
an important part of the Commission’s
open access policies, this is not within
NERC’s mandate to address as the ERO.
NERC contends that the Commission’s
proposed directive blurs the line
between commercial interests and
reliability interests and is not based on
an objective evaluation of the impact to
the reliability of the Bulk-Power System.
98. NERC contends, and others agree,
that the Commission should address its
goals through business practice
standards developed by NAESB and
through specific Commission
rulemakings that direct entities to which
the Commission’s market-based
jurisdiction applies to take action
consistent with the Commission’s open
access goals. TANC states that NERC’s
filing letter was clear that NERC and
NAESB have agreed that any item that
is directly related to the Open Access
Same Time Information System or other
commercial interactions between
customers and transmission providers
are within the scope of NAESB
activities. TANC points out that NERC’s
filing letter states repeatedly that the
focus of the proposed Reliability
Standards is to address only the
reliability, not commercial, aspects of
available transmission.
99. Similarly, ISO/RTO Council
agrees that the Commission should
pursue such commercial concerns
through another forum such as the
NAESB standards. ISO/RTO Council
expresses concern that the
Commission’s proposed directive could
undermine the coordination efforts
between NERC and NAESB on these
issues. In addition, ISO/RTO Council
contends that the NOPR overstates
reliability concerns associated with the
standards and that the Commission
lacks justification for additional
directives. ISO/RTO Council states that
overestimation and hence overselling of
ATC can result in potential or actual
violations of system operating limits
and interconnection reliability operating
limits but claims there has not been a
single incident in which a system
operating limit and interconnection
reliability operating limit has been
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64897
violated due to the overselling of
available transfer capability.
100. ISO/RTO Council states that the
subject of the proposed audits is not
related to compliance with NERC
Reliability Standards or reliability in
any way. ISO/RTO Council argues that
such audits are not in themselves
Reliability Standards compliance audits
which are appropriately conducted by
the ERO and its Reliability Entities
through a set schedule. Rather, ISO/RTO
Council argues, the proposed audits are
designed to allow the Commission and
others to replicate and verify
calculations to satisfy a competitionrelated concern.
101. EEI contends that a Reliability
Standard must address a reliability
concern that falls within the statutory
framework of section 215. EEI further
contends that the purpose of a
Reliability Standard may not extend
beyond the reliable operation of the
Bulk-Power System. EEI states that it is
appropriate for the Commission to
determine if a Reliability Standard is
unduly discriminatory.70 But, EEI
contends, there is a difference between
a Reliability Standard that is not unduly
discriminatory and a standard that
furthers open access goals that are not
a part of the reliable operation of the
Bulk-Power System. EEI states that the
potential discrimination described in
the NOPR is related to the provision of
transmission service under an OATT
and, to the extent the Commission or
others believe such discrimination
exists, the Commission has the authority
and jurisdiction to address such
discrimination under sections 205 and
206 of the FPA. According to EEI, it is
imperative that the ERO maintain focus
on its reliability duties rather than
taking on additional duties to police
implementation of tariffs and
comparability issues.71
102. EEI and Entegra separately ask
the Commission to clarify that, under
Order No. 890, transmission service
providers are required to adhere to the
Commission’s policies regarding nondiscriminatory open access transmission
service in their exercise of discretion
under the standards. They also ask the
Commission to clarify that it will retain
jurisdiction under Order No. 890 after
approval of the MOD Reliability
Standards to remedy any undue
70 Citing Rules Concerning Certification of the
Electric Reliability Organization; 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 332 (2006); order on reh’g, Order No. 672–A,
71 FR 19814 (Apr. 18, 2006), FERC Stats. & Regs.
¶ 31,212 (2006).
71 See also Duke, NYISO and TANC comments.
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discrimination that may result from the
implementation of these standards by
individual transmission operators or
transmission service providers. Entegra
separately argues that while it may be
necessary and appropriate for the
Commission to rely on the NERC
process to develop requirements that are
solely related to reliability, the
Commission cannot and should not
abdicate its statutory authority to
prevent undue discrimination by
delegating to NERC its responsibility to
enforce its open access requirements.
103. Although commenters such as
NRU, Pacific Northwest, Public Power
Council, Snohomish and SMUD agree
that undue discrimination in
transmission service must be addressed,
they also contend that such a goal is not
a statutory purpose that Reliability
Standards are intended to address.
Puget Sound agrees, stating that
available transfer capability calculations
have little impact on reliability. SMUD
states that it is troubled by language in
the NOPR that suggests that commercial
concepts be addressed by the Reliability
Standards, even where no clear nexus to
reliability exists. NRU, Pacific
Northwest, Public Power Council, and
Snohomish state that the Commission
has provided no reliability-based
justification for the proposed audit
directive and that the proposal cannot
be supported on the basis of reliability.
104. The Joint Municipals agree that
the Commission has not articulated a
sufficient statutory basis for the
proposed audits. The Joint Municipals
state that the courts have been clear that
the Commission must be rigorous in
identifying the statutory authority under
which it proceeds. The Joint Municipals
comment that the Commission is
charged with the responsibility to
ensure non-discrimination in the
provision of transmission service under
sections 205, 206 and 211A of the FPA;
whereas section 215 clearly identifies
reliability as the only purpose of the
ERO regime. Accordingly, the Joint
Municipals ask the Commission to make
clear that in the exercise of its
prosecutorial discretion, it will ensure
that the Commission and NERC
enforcement processes will be focused
on violations of the proposed Reliability
Standards that threaten system
reliability. The Joint Municipals argue,
however, that a review of Order Nos.
890, 693 and the NOPR make clear that
the impetus for developing a consistent,
transparent approach to available
transfer capability lies in the
Commission’s concern over
discrimination in the provision of
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transmission service, rather than system
reliability.72
105. By contrast, EPSA states that it
supports and applauds the
Commission’s efforts to meld the
reliability goals of Order No. 693 and
the non-discriminatory goals of Order
No. 890. EPSA contends that the
contributions that market mechanisms
make to system reliability, and the need
to preserve the positive link between
reliability and markets, is a significant
dimension of the new Reliability
Standards development process. EPSA
commends the Commission for
recognizing the connection between the
MOD Reliability Standards and the
initiative to reform Order No. 890 to
address existing opportunities for to
discriminate against competitive power
suppliers. EPSA states that Order Nos.
890 and 693 articulated serious
concerns regarding the lack of clarity,
transparency and uniformity in the
critical calculations pertaining to one of
the most fundamental aspects of the
wholesale Bulk-Power System from both
a reliability and commercial
perspective.
Commission Determination
106. The Commission hereby adopts
the NOPR proposal to direct the ERO to
conduct an audit of the various
implementation documents developed
by transmission service providers to
confirm that the complete available
transfer capability methodologies
reflected therein are sufficiently
transparent to allow the Commission
and others to replicate and verify those
calculations. The Commission clarifies
that these audits are not intended to
address the competitive effects of these
MOD Reliability Standards.73 Instead,
the audit should review each
component of available transfer or
flowgate capability, including the
transmission service provider’s
calculation of capacity benefit margin
and transmission reliability margin, for
transparency and verifiability to ensure
compliance with the MOD Reliability
Standards. In the course of its audit,
NERC is directed to identify any
parameters and assumptions that are not
72 Citing Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 83 (stating that the ‘‘purpose of
increasing consistency and transparency of
[available transfer capability] calculations is to
reduce the potential for undue discrimination in the
provision of transmission service.’’) See also NOPR,
FERC Stats. & Regs. ¶ 32,641 at P 2 (stating that the
proposed Reliability Standards ‘‘address the
potential for undue discrimination by requiring
industry-wide transparency and increased
consistency regarding all components of the
[available transfer capability] methodology and
certain definitions, data, and modeling.’’
73 See infra section III.3.b.ii.
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sufficiently specific or transparent to
allow the Commission and others to
replicate and verify the results.
107. The Commission disagrees with
commenters asserting that the scope of
this audit is irrelevant to the Reliability
Standards or the reliability of the BulkPower System. Requirement R3.1 of
MOD–001–1 requires transmission
service providers to include in their
available transfer capability
implementation documents information
describing how the selected
methodology (or methodologies) has
been implemented. Transmission
service providers are to provide enough
detail for the Commission and others to
validate the results of the calculation
given the same information used by the
transmission service provider. Thus,
Requirement R3.1 of MOD–001–1
requires transmission service providers
to include enough information in their
available transfer capability or available
flowage capability implementation
documents to confirm that the
respective methodologies reflected
therein are sufficiently transparent to
allow the Commission and others to
replicate and verify those calculations.
Consequently, the audit is directly
relevant to compliance with the
Reliability Standards as proposed by the
ERO and approved by the Commission
in this Final Rule.
108. As described above, the
Reliability Standards approved herein
are the result of a long process before
the Commission. In Order No. 890, the
Commission, among other things,
expressed concern that a lack of
consistent, industry-wide available
transfer capability calculation standards
poses a threat to the reliable operation
of the Bulk-Power System.74 In light of
these concerns, the Commission
directed public utilities, working
through the NERC Reliability Standards
development process, to develop
Reliability Standards for the consistent
and transparent calculation of available
transfer capability.75 One month later,
the Commission issued Order No. 693,
which directed the ERO to modify nine
out of ten approved MOD Reliability
Standards to be consistent with the
requirements in Order No. 890. Thus,
the MOD Reliability Standards
approved here today are the result of
efforts by the Commission, the ERO and
industry to address concerns related to
the reliable operation of the Bulk-Power
System.
109. The Commission clarifies that it
is not directing the ERO to perform a
74 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 195.
75 Id. P 196.
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market-based analysis of the
competitive effects of the Reliability
Standards approved herein. Although
the ERO should attempt to develop
Reliability Standards that have no
undue negative effects on
competition,76 the ERO’s statutory
functions are properly focused on the
reliability of the Bulk-Power System and
the Commission does not intend to
broaden that focus here. The
Commission reiterates that a proposed
Reliability Standard should not
unreasonably restrict available
transmission capability on the BulkPower System beyond any restriction
necessary for reliability and should not
limit use of the Bulk-Power System in
an unduly preferential manner. The
Reliability Standard should not create
an undue advantage for one competitor
over another.77 Nonetheless, pursuant to
sections 205 and 206 of the FPA, the
Commission shall remain the final
arbiter of undue discrimination. The
MOD Reliability Standards approved in
this Final Rule require transmission
service providers to document their
methodologies for calculating available
transfer capability or available flowgate
capability in a transparent and
consistent manner. Compliance with
these requirements is essential to
reducing the threat posed to the reliable
operation of the Bulk-Power System,
particularly with respect to the inability
of one transmission provider to know
with certainty its neighbors’ system
conditions affecting its own available
transfer capability values.78
110. Specifically, each of the
methodologies for calculating available
transfer capability or available flowgate
capability provides an algorithm for
calculating the respective values. Each
of these algorithms requires values for
capacity benefit margin and transfer
reliability margin. For example,
Requirement R10 of MOD–028–1 states:
[available transfer capability] = [total
transfer capability]¥[existing
transmission
commitments]¥[capacity benefit
margin]¥[transfer reliability
margins] + postbacks +
counterflows.
Thus, in order to validate the results of
the available transfer capability or
available flowgate capability
calculations, the Commission and others
must be able to validate the calculations
for capacity benefit margin and transfer
reliability margin. Accordingly, the
76 Order No. 672, FERC Stats. & Regs. ¶ 31,204 at
P 332.
77 Id.
78 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 195.
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Commission directs the ERO to audit
the capacity benefit margin and transfer
reliability margin implementation
documents, created pursuant to MOD–
004–1 and MOD–008–1 respectively, to
ensure that these documents include
information, in such detail that, given
the same information, the results of the
capacity benefit margin or transfer
reliability margin calculation can be
validated.
111. Although the Commission directs
the ERO to conduct audits to ensure
compliance with the requirements of the
MOD Reliability Standards, the
Commission will remain vigilant in its
efforts to reduce the potential for undue
discrimination in the provision of
transmission service pursuant to its
authority under sections 205 and 206 of
the FPA. Accordingly, transmission
customers and neighboring transmission
providers will have the opportunity to
submit complaints pursuant to section
206 of the FPA, if they believe that a
transmission provider is using
assumptions or parameters in available
transfer capability calculations in an
unduly discriminatory or preferential
manner.79
b. Performance of Audits
Comments
112. Many commenters, including
NERC, indicate that NERC lacks the
expertise to conduct the proposed
audits. These commenters suggest that
Commission staff is more suited to
perform the audits that pertain to
market issues. Others, such as EPSA,
support the proposed audits but
recognize that NERC staff may not have
sufficient knowledge and skill for the
task. Other commenters ask for
clarification regarding the scope and
details of such audits. NERC and others
contend that the proposed 180-day
deadline for NERC to complete the
audits is overly-burdensome and
unrealistic, while Entegra supports the
NOPR proposal to complete the audits
within 180-days of the effective date of
the Reliability Standards.
79 The ERO is to conduct audits to ensure
compliance with the MOD standards to assure the
reliable operation of the grid. Further, the
Commission is not directing that the scope of the
audit include an active search or review of
anomalous events or unduly discriminatory
behavior. If, however, in the course of an audit the
ERO happens to identify any assumptions or
parameters that appear anomalous, that may appear
to cause available transfer capability calculation
results to be skewed toward a particular result even
if the implementation documents can be validated
according to Requirement R3 of MOD–001–1, or
that appear to violate NERC’s market-reliability
interface principles that the Commission
acknowledged in Order No. 672, the ERO is free to
notify the Commission’s Office of Enforcement of
such anomalies.
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i. NERC Expertise
113. NERC indicates that obtaining
personnel with the technical expertise
needed to evaluate the implementation
of these audits will result in staffing
challenges that could be more complex
than the Commission foresees. NERC
expresses concern that, if the
Commission expands the role of the
ERO to begin enforcement of open
access service, it would not be able to
perform the audits with its current staff
and would therefore need to hire new
employees or consultants. Moreover,
NERC contends that it may prove
extremely difficult to locate and acquire
new employees or consultants with the
appropriate qualifications to not only
review an implementation document for
its engineering merits but also for its
commercial implications.
114. Several commenters agree that
NERC and the Regional Entities lack the
ability, experience, authority or staff
determine whether the Commission or
transmission customers have sufficient
and accurate information for
commercial and economic purposes or
to ensure compliance with the
competition goals of Order No. 890.80
The Georgia Companies point out that
the Reliability Standards were
developed by NERC using industry
experts on reliability, not necessarily
experts on the commercial or regulatory
implications of undue discrimination in
the provision of transmission service.
Similarly, TAPS and TANC contend
that the Commission should not require
NERC to divert its limited resources to
cover market oversight and competition
issues. EPSA argues that if both the
reliability goals of Order No. 693 and
the non-discriminatory access goals of
Order No. 890 become the responsibility
of NERC and the regional reliability
entities, the achievement of each will be
diffused. EPSA further contends that a
reliability audit cannot be a substitute
for an audit of transmission access
practices and measures.
115. Some commenters recommend
that, if the Commission is interested in
auditing the implementation documents
to address commercial concerns, the
Commission itself should perform the
audits.81 For example, APPA states that
the role of detecting and remedying
undue discrimination properly falls
upon the Commission, acting in an
audit and compliance role or acting
upon customer complaints that
transmission service providers or
80 E.g., APPA, Cottonwood, EEI, EPSA, NRU,
Pacific Northwest, Public Power Council, Puget
Sound, Joint Municipals and Snohomish.
81 E.g., Cottonwood, EEI, EPSA, Puget Sound,
TAPS and TANC.
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transmission operators have failed to
fully comply with transparency
obligations. Puget Sound states that the
Commission has an established method
to conduct such audits—the OATT
process. If the Commission chooses to
direct NERC to conduct these audits,
Entegra argues that NERC staff should
be required to conduct the audit under
the guidance of Commission staff.
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ii. Audit Scope
116. Several parties also question the
intended scope of the proposed audits.82
For example, Entegra contends that the
Commission should specify in greater
detail the contents of the audit with
Commission staff acting as subject
matter experts with respect to the
Commission’s policies for nondiscriminatory open access transmission
service. To the extent an audit team
identifies an item in an implementation
document as unduly discriminatory or
preferential, or otherwise does not
comply with the requirements of Order
Nos. 890 and 693, Entegra recommends
that the Commission should require the
transmission service provider to modify
the item during the audit process as
appropriate. Entegra states that the audit
report should identify and document all
areas where the implementation
document did not comply with Order
Nos. 890 and 693 and explain how the
non-compliance was corrected. Further,
Entegra suggests that the Commission
should specify that the audit findings
are preliminary and that it will establish
notice and comment procedures for the
initial audit report. Finally, Entegra
recommends that the Commission
should commit to reopen the audit and/
or direct any necessary modifications to
the implementation documents if the
comments of interested parties indicate
that any items in the implementation
documents are unduly discriminatory or
preferential or otherwise do not comply
with the Commission’s open access
requirements in Order Nos. 890 and
693.
117. The Georgia Companies
recommend that the Commission
describe how it proposes the
Commission and others should be able
to replicate and verify results and allow
proper time for NERC and the industry
to determine a plan that meets the
Commission’s proposals as well as state
and regional requirements. The Georgia
Companies also ask that the
Commission limit its review of capacity
benefit margin and transmission reserve
margin implementation documents to
82 E.g., Entegra, EPSA, the Georgia Companies,
ITC Companies, NYISO, and Puget Sound.
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their effect on reliability, not undue
discrimination.
118. EPSA recommends the
Commission convene a technical
conference to clarify the audit scope,
responsibilities and jurisdictional
questions. In addition, EPSA contends
that the Commission needs to have a
process to handle complaints as they
arise.
119. Puget Sound states that the
Commission needs to rationalize the
OATT enforcement regime, which its
staff oversees, and the NERC reliability
rule enforcement regime, as they will
both apply to the same total transfer
capability/available transfer capability
concepts. Puget Sound states that the
Commission must be absolutely clear
that the regimes, as they both address
available transfer capability
calculations, are completely consistent
and that there is no interpretation gap
between enforcement personnel and
auditors from the two separate entities.
Puget Sound contends that this is
necessary because there is a significant
risk of conflicting or at least
inconsistent interpretations and
questions the appropriateness of having
two enforcement regimes cover the same
issue.
120. NYISO expresses concern that
the proposed audits might be
interpreted to require NYISO to publicly
disclose confidential market and
transmission information in its
implementation document. NYISO
argues that requiring independent
system operators (ISOs) and regional
transmission organizations (RTOs) to
reveal information, such as transmission
flow utilization variables, would place
them in a position of choosing to
comply with the NERC available
transfer capability replication
requirement or internal codes of
conduct that forbid ISOs and RTOs from
revealing such information. NYISO
contends that it is not necessary for
confidential information to be revealed
in order to allow market participants to
replicate available transfer capability
calculations. Accordingly, NYISO asks
the Commission to clarify that its audit
requirement is not meant to require
ISOs and RTOs to make confidential
information publicly available, and that
other methods can be used to allow
market participants to replicate
available transfer capability calculations
without such disclosure.
121. The ITC Companies contend that
the audit process should be
strengthened to effectively detect
evidence of oversubscription or
underutilization of the transmission
system and ensure that the commercial
aspect of the available transfer
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capability closely matches the system
available transfer capability
calculations. The ITC Companies
suggest, as an example, an audit of
adjacent transmission service providers
where they both calculate the available
transfer capability or available flowgate
capability for the same flowgates or
paths. The ITC Companies state that,
usually, the two calculations should
have similar results and that any major
difference would be the result of
differences in assumptions or study
parameters. In addition, the ITC
Companies comment that the
Commission should open up the results
of the NERC audit for further comments
prior to directing NERC to modify the
Reliability Standards to address any
lack of transparency in the calculation
of ATC and each of its components.
iii. Audit Timeline
122. NERC, and other commenters,
oppose the 180-day deadline for NERC
to complete the audits.83 NERC
contends that the imposition of a 180day deadline to complete these audits
places a higher priority on these issues
than is warranted. NERC states that
consistency in available transfer
capability practices (or the lack thereof)
in the treatment of transmission has a
relatively low reliability impact on the
Bulk-Power System compared to
numerous other core areas under which
NERC has responsibilities. NERC states
that under its Commission-approved
rules, NERC must conduct an audit of
users, owners and operators of the BulkPower System every three years. NERC
contends that the NOPR provides no
explanation of the reliability benefits
that would necessitate an audit cycle
accelerated beyond this three year
schedule. In addition, NERC contends
that if the Commission insists on
broadening NERC’s responsibilities,
NERC will need more than 30 days to
develop and submit a timeline for the
completion of these audits. NERC asks
that the Commission allow the ERO
sufficient time to appropriate consider
the best ways to restructure its resources
in light of its new responsibilities.
123. APPA agrees with NERC stating
that the Commission’s proposed
timeline is potentially very burdensome.
APPA, TANC and TAPS state that the
proposed timeline will likely divert
scarce NERC and registered entity staff
resources from other tasks that are more
central to NERC’s responsibilities as the
ERO. They recommend that such audits
take place on the normal three-year or
five-year audit cycles applicable to these
83 E.g., APPA, Bonneville, ColumbiaGrid, Georgia
Companies, TANC and TAPS.
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reliability functions. The Georgia
Companies state that full audits with
on-site visits of each transmission
owner and transmission service
provider likely cannot be completed
within 180 days. ColumbiaGrid suggests
that NERC should be permitted to audit
a representative sample of entities rather
than every single one and then assess
whether a broader audit is necessary.
124. By contrast, Entegra suggests that
the Commission should require NERC to
complete the proposed audit within 180
days of the publication of this Final
Rule. Entegra points out that, as
proposed, the proposed audit will not
be due until 18 to 21 months from the
approval date. Entegra contends that
NERC has not explained why drafting
the implementation documents and
making the corresponding changes to
software and operating procedures will
require 12 to 15 months after approval.
Accordingly, Entegra suggests that the
Commission should require all
transmission service providers to
finalize their implementation
documents and submit to NERC within
90 days of the approval date and require
NERC to complete the audit within 90
days after receipt of these
implementation documents. Entegra
states that transmission providers will
have to complete their implementation
documents well in advance of the actual
implementation. Entegra argues that
requiring the audit before the effective
date would allow NERC and the
Commission opportunity to identify and
remedy—at the front end—any
individual or systematic problems that
NERC of the Commission find in the
transmission service provider
implementation documents.
Commission Determination
125. While we adopt the NOPR
proposal to direct NERC to conduct an
audit, we are persuaded by the
comments of the ERO and others to
modify the NOPR proposal regarding
certain details on implementation of the
required audits. First, as already
discussed above, the Commission will
not require the ERO to perform an audit
that requires the ERO to assess whether
a transmission operators’ or
transmission service providers’
available transfer capability
methodology provides opportunities for
undue discrimination or preference.
Rather, the ERO audits must focus on
compliance with the provisions of the
MOD Reliability Standards. In accord
with the position of numerous
commenters, Commission staff is in a
more appropriate position to analyze
market-related issues. Thus, the ERO
must retain information and material
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gathered during the course of its audit
and make it available to Commission
staff upon request, so as to allow
Commission staff to inquire into
possible anti-competition concerns.
126. Moreover, the Commission is
persuaded that the ERO should conduct
the audits in the due course of its
periodic, three-year audit cycle, i.e.,
these Reliability Standards should be
added to the ERO’s list of actively
monitored Reliability Standards. The
Commission believes that these
modifications to the NOPR proposal
address the concerns of the ERO and
others regarding the expertise of the
ERO to conduct the audits and the
availability of ERO resources to conduct
the audits in a more limited period of
time.
127. The audits directed herein
should not displace any of NERC’s
existing scheduled audits or priorities. If
NERC is unable to perform the audits
with current staff without sacrificing
other audit priorities, it can seek
additional resources to perform the
audits. Since the MOD Reliability
Standards will not become effective
until more than one year from
Commission approval, NERC can
request any additional funding
necessary to undertake the audits in its
2011 business plan and budget
proposal. Thus, NERC will have
sufficient opportunity to perform the
audits without any undue burden.
128. We decline to direct how the
ERO should conduct the MOD
Reliability Standards audit, as requested
by some commenters. We believe that
our action to focus the ERO audit on
compliance with the requirements of the
Reliability Standards, matches the scope
of the audits to the ERO’s expertise. The
ERO should be fully capable of
developing an audit to measure
compliance with the requirements of its
Reliability Standards. In directing this
audit, the Commission does not expect
NERC’s staff to have expert knowledge
of the competition requirements of
Order No. 890.
129. If the Commission determines
upon its own review of the data, or
upon review of a complaint, that it
should investigate the implementation
of the available transfer capability
methodologies, the Commission will
need access to historical data.
Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, the Commission
directs the ERO to modify the Reliability
Standards so as to increase the
document retention requirements to a
term of five years, in order to be
consistent with the enforcement
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provisions established in Order No.
670.84
130. With regard to concerns raised by
commenters regarding the nondisclosure of confidential information,
we expect the ERO to conduct the MOD
Reliability Standards audits consistent
with section 1500 of NERC’s Rules of
Procedure, which provides detailed
rules for the protection of confidential
information. Section 1505 of NERC’s
Rules specifically addresses the ERO’s
provision of confidential information to
the Commission or another
governmental agency in response to a
request for information by that agency.
Likewise, the implementation
documents will be made publicly
available through the corresponding
NAESB business standards, approved
concurrently with this Final Rule,
which incorporate appropriate
confidentiality protections.85
131. As indicated above, we are
persuaded by the commenters that the
proposed 180-day time frame for
conducting the MOD Reliability
Standards audits is not practical, and
likely not feasible. Upon further
consideration, the Commission hereby
directs the ERO to conduct these audits
in the course of its periodic, three-year
audits of users, owners and operators of
the Bulk-Power System. The ERO shall
begin this audit process 60 days after
the implementation of these Reliability
Standards. On an annual basis, to
commence on 180 days after the
implementation of the Reliability
Standards approved herein, the ERO
shall file the audit reports (or the results
of its audit in any other format) with the
Commission.86
c. Additional Requirements To Prevent
Undue Discrimination
NOPR Proposal
132. In the NOPR, the Commission
sought comment whether additional
requirements should be directed in this
proceeding to ensure that the discretion
provided under the available transfer
capability implementation documents
cannot be used to unduly discriminate
in the provision of transmission service.
Comments
133. ISO/RTO Council contends that
the proposed MOD Reliability Standards
84 Prohibition of Energy Market Manipulation,
Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC
Stats. & Regs. ¶ 31,202, at P 63 (2006) (citing 28
U.S.C. § 2462 (2000)).
85 See Standards for Business Practices and
Communication Protocols for Public Utilities, Order
No. 676–E, 129 FERC ¶ 61,162 (2009).
86 The Commission does not anticipate allowing
an opportunity for public comment on the filed
audit reports.
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offer the appropriate level of discretion
in the calculation of the various
parameters including the ATC, and that
the discretion afforded cannot be used
to unduly discriminate the provisions of
the transmission service. Accordingly,
ISO/RTO Council believes that no
additional requirements should be
directed in this proceeding. It is not
possible to identify and state all
assumptions in the requirements for the
given set of Reliability Standards.
134. SMUD and Salt River contend
that the Reliability Standards may not
lawfully be expanded to include matters
that do not impact the reliability of the
Bulk-Power System, such as the NAESB
business practices. They contend that
incorporating NAESB business practices
and open access concepts in the
Reliability Standards creates confusion
about how the Reliability Standards will
be applied. SMUD states, as an example,
that it is not subject to the NAESB
business practices and has not been
involved in their development. SMUD
also points out that the NAESB
standards are subject to change by
Commission order. Similarly, SMUD
contends that the Reliability Standards
should not be melded with the
Commission’s open access policies
because such policies do not apply to
SMUD. Salt River also argues that
allowing the Reliability Standards to be
subject to change by the Commission,
NAESB or any other third party could
create situations where third-party
revisions of such regulations or business
practices could be construed as
effectively modifying the Commissionapproved Reliability Standards.
Accordingly, SMUD and Salt River
argue that compliance with these
Reliability Standards must be governed
by the four corners of the standard and
not incorporate by reference or
otherwise NAESB business practices or
the Commission’s open access policies.
Commission Determination
135. As the Commission stated in the
NOPR, it is appropriate for transmission
service providers to retain some level of
discretion in the calculation of available
transfer capability. Requiring absolute
uniformity in criteria and assumptions
across all transmission service providers
would preclude transmission service
providers from calculating available
transfer capability in a way that
accommodates the operation of their
particular systems. The Commission
disagrees with ISO/RTO Council’s
argument that the discretion afforded in
these Reliability Standards cannot be
used to unduly discriminate the
provisions of the transmission service. It
is possible, for example, for a
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transmission service provider to use
parameters and assumptions that skew
its available transfer capability values
toward a particular result in a way that
discriminates against certain types of
customers. As discussed above, the
Commission accepts these risks and
expects that they will be mitigated
through complaints as well as the
Commission’s own market oversight
authority.
136. In response to SMUD and Salt
River, the Commission notes that the
MOD Reliability Standards do not
incorporate the NAESB standards.
NERC and NAESB worked together to
create two, distinct sets of standards
with overlapping interests. The NAESB
standards impose certain posting
requirements of the available transfer
capability information generated by
these MOD Reliability Standards but
compliance with the MOD Reliability
Standards does not depend upon
compliance with the NAESB standards.
B. Modification of the Reliability
Standards
1. MOD–001–1
a. Availability of the Implementation
Documents
NOPR Proposal
137. In the NOPR, the Commission
expressed concern that the Reliability
Standards potentially restrict the
disclosure of the available transfer
capability, capacity benefit margin, and
transmission reliability margin
implementation documents.
Requirements R4 and R5 of MOD–001–
1 requires transmission service
providers to provide a current available
transfer or flowgate capability
implementation document to the
following entities and to notify the same
entities before implementing a new or
revised implementation document: Each
planning coordinator, reliability
coordinator, and transmission operator
associated with the transmission service
provider’s area; each planning
coordinator and reliability coordinator
adjacent to the transmission service
provider’s area; and, each transmission
service provider whose area is adjacent
to the transmission service provider’s
area. Similarly, Requirement R2 of
MOD–004–1, requires transmission
service providers maintaining to
capacity benefit margin to make
available its current capacity benefit
margin implementation document to the
following entities: Transmission
operators, transmission service
providers, reliability coordinators,
transmission planners, resource
planners, and planning coordinators
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that are within or adjacent to the
transmission service provider’s area,
and to the load serving entities and
balancing authorities within the
transmission service provider’s area,
and notify those entities of any changes
to the implementation document prior
to the effective date of the change.
Finally, Requirement R3 of MOD–008–
1, requires transmission operators using
transfer reliability margin to make
available its transfer reliability margin
implementation document, and if
requested, underlying documentation,
to any of the following who make a
written request no more than 30
calendar days after receiving the
request: Transmission service providers,
reliability coordinators, planning
coordinators, transmission planners,
and transmission operators.
138. The Commission pointed out that
NERC did not explain in its filings why
only certain entities would have access
to these materials nor why the specified
list of recipients varies for each
documents. Although the proposed
NAESB standards accompanying the
Reliability Standards would require
transmission service providers to post a
link to the implementation documents
on their OASIS, which would result in
disclosure beyond the specified entities
listed in the Reliability Standards, the
Commission stated that it is important
for reliability purposes to require
disclosure of the implementation
documents to a broader audience than
provided in the Reliability Standards.87
The Commission explained that its
jurisdiction under section 215 of the
FPA is broader than its jurisdiction to
require compliance with the NAESB
standards under sections 205 and 206 of
the FPA. The Commission stated that
these documents will describe how the
transmission provider implements the
Reliability Standards and, therefore,
should be disclosed by all transmission
service providers, not only those who
are also public utilities.
139. Therefore, to ensure sufficient
transparency, the Commission proposed
to direct the ERO, pursuant to section
215(d)(5) of the FPA and section 35.19(f)
of our regulations to modify the
proposed Reliability Standards to make
the available transfer capability,
capacity benefit margin, and
transmission reliability margin
implementation documents available to
all customers eligible for transmission
service in a manner that is consistent
with relevant NAESB standards.88 The
Commission also sought comment on
any improvements that may be
87 NOPR,
88 Id.
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necessary to improve access by
transmission customers to the
implementation documents.
Comments
140. NERC objects to the
Commission’s proposal to expand the
availability of the implementation
documents. NERC states that the
Commission’s proposal crosses the line
between reliability matters and
commercial and open access matters.
NERC contends that the Commission
provides no explanation of how
reliability could be compromised by not
making these implementation
documents available to all eligible
transmission customers. Although
NERC agrees that it is critical that
reliability entities have access to the
necessary information regarding BulkPower System reliability, NERC
contends that transparency related to
ensuring open access and consistent
treatment for all transmission customers
is not critical to reliability or within
NERC’s area of responsibility.
141. NERC states that the Commission
has other tools and authorities to police
its open access policies. NERC states
that its mandate is to ensure the
reliability of the Bulk-Power System. It
also states that it has coordinated
procedures with NAESB to address the
appropriate assignment of tasks that
could have a reliability or a commercial
impact, and the actions proposed by the
Commission could undermine that
coordination. Accordingly, NERC asks
the Commission to address its desired
goals through the business practice
standards developed by NAESB and
through specific Commission
rulemakings that direct entities to which
the Commission’s market-based
jurisdiction applies to take action
consistent with the Commission’s open
access goals.
142. Many commenters agree that the
availability of the implementation
documents should be limited to those
entities with a reliability need for such
information.89 These parties argue that
expanding the availability of the
implementation documents to entities
without a reliability need for such
information is beyond the ERO’s
statutory authority, which is limited to
ensuring the reliable operation of the
Bulk-Power System. Several entities
agree that any information provided as
part of any Reliability Standard should
be restricted to that which is needed to
ensure reliability.90 ISO/RTO Council
89 E.g., APPA, Bonneville, Duke, EEI, the Georgia
Companies, ISO/RTO Council, Pacific Northwest,
SMUD, Snohomish, TANC.
90 E.g., Bonneville, EEI, SMUD, Snohomish, Salt
River.
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further argues that achieving
transparency by making these
documents available to the public is not
related to reliability. Similarly, the
Georgia Companies contend that it is
beyond the scope of NERC’s authority to
make these documents available to
unregistered entities that do not have to
comply with the Reliability Standards.
143. Many commenters also argue that
the availability of the implementation
documents is a business practice issue
that should be dealt with in NAESB
standards.91 Although parties such as
EEI contend that the NAESB standards
do not provide sufficient confidentiality
protections for competitively sensitive
information, others, such as APPA
contend that NAESB is a more
appropriate standards development
forum with which to craft and maintain
these business practices and associated
confidentiality agreements. APPA also
suggests that disputes concerning access
to such information fall squarely within
the Commission’s jurisdiction and
expertise under sections 205 and 206 of
the FPA and not within NERC’s
responsibilities under section 215 of the
FPA.
144. By contrast, Entegra argues that
the Commission should direct the ERO
to modify MOD–001–1 to require each
transmission service provider to make
available, upon request, all relevant
documentation, input data, models,
assumptions and other materials
necessary to replicate the transmission
service provider’s available transfer
capability calculations and results and
to verify that the transmission service
provider has applied its methodology
and models in a consistent, nondiscriminatory manner. If a data item
used in a calculation is confidential,
Entegra suggests it should be so
identified in the implementation
document, and made available subject
to a confidentiality or non-disclosure
agreement. Entegra also suggests that,
because NERC proposes to leave to the
NAESB process any posting
requirements, the NERC Reliability
Standard should require transmission
service providers to provide a complete,
regularly updated (i.e., at least once per
day) list of all of the above materials
that are not posted, but are to be made
available upon request.
145. Puget Sound also supports the
Commission proposal to make the
implementation documents more
broadly available and to impose
comparable disclosure requirements on
non-jurisdictional entities. However, to
91 E.g., APPA, Bonneville, ColumbiaGrid, ISO/
RTO Council, Pacific Northwest, SMUD,
Snohomish, Salt River.
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64903
the extent that the proposed MOD
Reliability Standards continue to
require available transfer capability
algorithm documentation, in addition to
Appendix C to the OATT, the available
transfer capability implementation
document, the capacity benefit margin
implementation document, and the
transfer reliability margin
implementation document, Puget Sound
contends that such documentation
obligations are duplicative and overly
burdensome. Accordingly, Puget Sound
recommends the development of a
single documentation process for these
related obligations. Puget Sound
contends that it would be confusing to
customers and counterproductive if the
OATT Attachment C documentation is
not consistent with the NERC required
documentation.
146. TAPS supports the Commission’s
proposal to make the implementation
documents available to all customers
eligible for transmission service in a
manner that is consistent with relevant
NAESB standards. TAPS contends that
it is essential from a competitive
perspective for customers to have timely
access to this data. TAPS also contends
that the proposed expanded disclosure
requirements are consistent with the
Commission’s obligation to review de
novo the competitive impact of the
proposed standards under section
215(d)(2) of the FPA. TAPS contends
that, unless entities who purchase
transmission service have timely access
to the transmission available
implementation documents, they will
not be able to verify the amount of
transmission that appears to be
available, undermining the
Commission’s effort to enhance
reliability and competition through
more accurate and transparent
calculation of available transfer
capability.
Commission Determination
147. As noted in several comments,
expanding the availability of the
implementation documents to entities
beyond the registered entities listed in
the Reliability Standards may stretch
the role of the ERO beyond ensuring
reliability of the Bulk-Power System and
could be duplicative of the associated
NAESB standard requirements.
Therefore, upon further consideration,
the Commission declines to adopt the
NOPR proposal to direct the ERO to
modify MOD–001–1 to expand the
availability of the implementation
documents beyond those entities with a
demonstrated reliability need to access
such information. Instead, the
Commission approves the availability
provisions of the Reliability Standards
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as written. NERC has provided
sufficient justification for limiting
disclosure of the implementation
documents to a discrete set of registered
entities that have been identified as
having a reliability need for such
information.
148. In response to Puget Sound, the
Commission finds that the disclosure
requirements imposed here are not
overly burdensome or duplicative of a
transmission service provider’s
obligation to include these available
transfer capability algorithms in
Appendix C to the OATT. The
implementation documents developed
under the MOD Reliability Standards
ensure transparency for the sake of the
reliable operation of the Bulk-Power
System whereas the reporting
requirements in Attachment C of the
OATT are designed to reduce
opportunities for undue discrimination.
Although the algorithms may be
repeated in both documents, the
supporting information and the purpose
for providing that information differ
greatly. Moreover, the disclosure
requirements of these MOD Reliability
Standards are binding on all
transmission providers, not just those
within the Commission’s jurisdiction
under sections 205 and 206 of the FPA.
149. As written, the Reliability
Standard requires all transmission
service providers to make the
implementation documents available to
designated reliability entities. With the
modification directed above, the
Commission is confident that disclosure
will be broad enough to ensure the
reliable operation of the Bulk-Power
System. The Commission’s concerns for
broad availability of the implementation
documents are sufficiently mitigated by
the disclosure requirements of the
related NAESB standards.92
Specifically, NAESB has developed
Standard 001–13.1.5, which requires
transmission service providers to
include an available transfer capability
information link on OASIS. This
standard requires that transmission
providers post several links on the
available transfer capability information
link, including links to their available
transfer capability, capacity benefit
margin and transfer reliability margin
implementation documents.
150. Relying on the NAESB standards
to require appropriate disclosure of the
implementation documents should also
resolve concerns for appropriate
confidentiality protections. Standard
92 The NAESB standards are approved
concurrently with this Final Rule. See Standards
for Business Practices and Communication
Protocols for Public Utilities, Order No. 676–E, 129
FERC ¶ 61,162 (2009).
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17:05 Dec 07, 2009
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001–13.1.5 provides that the posting of
information on the available transfer
capability link would be ‘‘subject to the
Transmission Provider’s ability to redact
certain provisions due to market,
security or reliability sensitivity
concerns.’’ In Order No. 890, the
Commission acknowledged that a
transmission provider may require
someone seeking access to CEII material
or proprietary customer information to
sign a confidentiality agreement. The
Commission expects that the provision
in the NAESB standard for a
transmission provider to redact
sensitive information from postings to
be implemented by a transmission
provider subject to their OATT in a
manner consistent with its obligation to
make that information available to those
with a legitimate need to access the
information, subject to appropriate
confidentiality restrictions.
Nevertheless, any concerns about the
NAESB business practices should be
raised with NAESB itself.
151. Nevertheless, the Commission
believes that the lists of required
recipients of the implementation
documents may be overly prescriptive
and could exclude some registered
entities with a reliability need to review
such information. Accordingly,
pursuant to section 215(d)(5) of the FPA
and section 39.5(f) of our regulations,
the Commission directs the ERO to
develop a modification to the Reliability
Standards pursuant to the ERO’s
Reliability Standards development
process to require disclosure of the
various implementation documents to
any registered entity who demonstrates
to the ERO a reliability need for such
information.
b. Dispatch Model Assumptions
NOPR Proposal
152. In the NOPR, the Commission
stated its belief that, subject to
confirmation by NERC through its audit,
the Reliability Standards will provide
the necessary level of transparency and,
therefore, the results of the available
transfer capability calculations will be
sufficiently accurate, consistent,
equivalent and replicable. Aspects of
the dispatch model to be used by
transmission service providers using
available transfer capability or available
flowgate capability are addressed
throughout the Reliability Standards.
For example, Requirement R3.6 of
MOD–001–1 requires transmission
service providers to include in their
implementation documents a
description of how generation and
transmission outages are to be
considered in transfer of flowgate
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calculations. Requirement R9 of MOD–
001–1 requires transmission service
providers to provide, upon request,
information related to unit
commitments and order of dispatch, to
include all designated network
resources and other resources that are
committed or have the legal obligation
to run, as they are expected to run.
Similarly, Requirement R6.1.2 of MOD–
030–2 requires transmission service
providers to consider unit commitment
and dispatch order in the calculation of
existing transmission capability.
Comments
153. Cottonwood and Entegra state
that the Reliability Standards provide
little detail and practically no
guidelines on the dispatch model to be
used in the available transfer capability
or available flowgate capability
calculations. Cottonwood contends that
despite the lack of clear and measurable
requirements, the dispatch model is the
most significant factor in the calculation
of available transfer capability and
available flowgate capability values.
Cottonwood further contends that
additional detail will reduce the
potential for manipulation of flowgate
capabilities through the use of dispatch
models that are not realistic and that,
therefore, could lead to undue
discrimination in access to the
transmission system. To reduce the
potential for undue discrimination and
to improve the accuracy of the available
transfer capability and available
flowgate capability calculations,
Cottonwood and Entegra ask the
Commission to direct the ERO to
develop detailed requirements for the
dispatch model used in these
calculations and establish
measurements to evaluate compliance
with the requirements.
154. Entegra contends that the
Reliability Standards fail to comply
with the requirement in Order No. 890
that reservations from a generator in
excess of the generator’s nameplate
should not be simultaneously included
in the calculation of existing
transmission commitments.93 Entegra
argues that this may cause available
transfer capability or available flowgate
capability calculations to indicate
unrealistic utilization of transmission
capacity associated with overgeneration. Entegra requests that the
Commission require NERC to continue
to work on a methodology for the
appropriate treatment of overgeneration. By contrast, ISO/RTO
Council argues that the Commission
93 Citing Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 254.
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should not direct the ERO to modify the
Reliability Standard to restrict
reservations coming out of a generation
source to the generation nameplate
capacity of that facility. ISO/RTO
Council contends that there is no
reliability impact of generating above
nameplate capacity because the
generator cannot generate above its
capacity. ISO/RTO Council contends
that NAESB would be the appropriate
organization to address the maximum
reservation level and that the
Commission should not interfere with
the coordination efforts between NERC
and NAESB.
155. Entegra contends that MOD–001–
1 does not adequately address the
modeling of transmission and
generation outages in the models used
for monthly available transfer capability
calculations. Accordingly, Entegra asks
the Commission to direct the ERO to
modify MOD–001–1, Requirements R3.6
and R8, to provide clear guidelines on
the duration and type of outages to be
included in the calculation of monthly
available transfer capability or available
flowgate capability values to ensure that
this process is transparent and
consistent across the various regions.
Entegra also contends that transmission
service providers should be required to
update models and available transfer
capability or available flowgate
capability values as soon as practicable
after an event such as a generation or
transmission outage or the discovery of
an error in the calculations, rather than
waiting for the next scheduled update.
156. Entegra contends that the
Commission should direct the ERO to
modify MOD–001–1 to require
transmission operators or transmission
service providers to periodically review,
update, and benchmark their models to
actual events used for available transfer
capability or available flowgate
capability calculations. Entegra points
out that NERC, in its filing, argued that
benchmarking is outside the scope of
the ATC-related Reliability Standards.
Entegra states that the updating and
benchmarking of models to actual
events are essential elements of the
Commission’s ATC reforms because
they ensure that the available transfer
capability or available flowgate
capability values will be modeled as
accurately as possible. Entegra contends
that the Commission should require
transmission operators and transmission
service providers to examine in their
benchmarking analyses whether their
models result in unduly preferential or
discriminatory treatment of any class of
transmission customers or transmission
service. Entegra also contends that the
Commission should require
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transmission operators and transmission
service providers to use the results of
the benchmarking studies to make any
necessary or appropriate adjustments to
their models.
157. Entegra suggests that the
benchmarking and updating
requirements in the revised standard
should ensure that transmission
providers’ available transfer capability
and available flowgate capability
models and methodologies comply with
the accuracy expectations set forth in
Order Nos. 693 and 890. Entegra also
urges the Commission should direct the
ERO to revise the Reliability Standards
to specify the frequency with which
transmission operators and transmission
service providers must periodically
review and update their models.
Finally, Entegra asks the Commission to
direct the ERO to develop a
modification to the Reliability Standard
that would allow stakeholders to
comment on the results of such studies
and participate in the review and
updating of the available transfer and
flowgate capability methodologies.
158. Cottonwood agrees that the MOD
Reliability Standards should include a
benchmarking process for available
transfer capability models and results.
Cottonwood contends that while an
audit of the transmission service
providers’ implementation documents
would help reduce the risk of undue
discrimination, only an ongoing
monitoring and benchmarking process
that includes Commission and
stakeholder input will protect against
actual misstatements of available
transfer capability values. Cottonwood
states that it raised this issue during the
stakeholder process but was informed
that benchmarking will be addressed
with future standards development
efforts.
Commission Determination
159. With respect to the treatment of
dispatch modeling assumptions, the
Commission finds that the proposed
requirements adequately address these
issues by maintaining transmission
service providers’ discretion to model
their systems effectively. As the
Commission stated in the NOPR,
requiring absolute uniformity in criteria
and assumptions across all transmission
service providers would preclude
transmission service providers from
calculating available transfer capability
in a way that accommodates the
operation of their particular systems.
The Commission maintains that these
Reliability Standards need not be so
specific that they address every unique
system difference or differences in risk
assumptions when modeling expected
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64905
flows. Each transmission service
provider should retain some discretion
to reflect unique system conditions or
modeling assumptions in its available
transmission capability methodology.94
Any such system conditions or
modeling assumptions, however, must
be made sufficiently transparent and be
implemented consistently for all
transmission customers.
160. In Order No. 890, the
Commission also expressed concern
regarding the treatment of reservations
with the same point of receipt
(generator), but multiple points of
delivery (load), in setting aside existing
transmission capacity.95 The
Commission found that such
reservations should not be modeled in
the existing transmission commitments
calculation simultaneously if their
combined reserved transmission
capacity exceeds the generator’s
nameplate capacity at the point of
receipt. The Commission required the
development of Reliability Standards
that lay out clear instructions on how
these reservations should be accounted
for by the transmission service provider.
The proposed Reliability Standards
achieve this by requiring transmission
service providers to identify in their
implementation documents how they
have implemented MOD–028–1, MOD–
029–1, or MOD–030–2, including the
calculation of existing transmission
commitments.96 Thus we will not direct
the ERO to develop a modification to
address over-generation, as suggested by
Entegra. Nonetheless, in developing the
modifications to the MOD Reliability
Standards directed in this Final Rule,
the ERO should consider generator
nameplate ratings and transmission line
ratings including the comments raised
by Entegra and ISO/RTO Council.
161. Nevertheless, the Commission
believes that these Reliability Standards
94 Order No. 890–A, FERC Stats. & Regs. ¶ 31,261
at P 51.
95 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 245; Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 1033.
96 MOD–001–1, Requirement R3.1. In its filing,
NERC discusses several options should the
Commission desire to impose a uniform approach
regarding the treatment of reservations with the
same point of receipt, but multiple points of
delivery. See NERC August 29, 2008 Filing, Docket
No. RM08–19–000, at 90–92. Neither Order No. 890
nor Order No. 693 directed that a single approach
be adopted to account for such reservations and,
instead, required only that instructions on how
these reservations are accounted for by the
transmission service provider be clearly laid out.
See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 245; Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 1033. The obligation of each transmission
service provider to identify in its implementation
document how they have implemented MOD–028–
1, MOD–029–1, or MOD–030–2, including the
calculation of existing transmission capacity,
satisfies this requirement.
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would benefit from benchmarking
requirements, such as those described
by Cottonwood and Entegra. Dispatch
models should reflect technical
analysis, i.e., sound engineering, as well
as operating judgment and experience.97
If so, the available transfer or flowgate
capability forecasts should be close to
actual values. However, changes in
system conditions, among other
variables, can cause differences between
calculated and actual values for
available transfer or flowgate
capabilities. Such variations are to be
expected. If, however, a transmission
service provider’s calculations
consistently under- or over-estimate
available transfer or flowgate capability,
adjacent systems will be unable to
effectively model their own transfer or
flowgate capabilities, thus resulting in a
degradation to the reliable operation of
the Bulk-Power System.
162. In Order No. 890, the
Commission directed public utilities,
working through NERC, to modify
MOD–010 through MOD–025 to
incorporate a periodic review and
modification of various data models.98
The Commission found that updating
and benchmarking was essential to
accurately simulate the performance of
the transmission grid and to calculate
comparable available transfer capability
values. On rehearing, the Commission
clarified that the models used by the
transmission provider to calculate
available transfer capability, and not
actual available transfer capability
values, must be benchmarked.99
Updating and benchmarking of models
to actual events will ensure greater
accuracy, which will benefit
information provided to and used by
adjacent transmission service providers
who rely upon such information to plan
their systems. Accordingly, pursuant to
section 215(d)(5) of the FPA and section
39.5(f) of our regulations, the
Commission directs the ERO to develop
benchmarking and updating
requirements to measure modeled
available transfer and flowgate
capabilities against actual values. Such
requirements should specify the
frequency for benchmarking and
updating the available transfer and
flowgate capability values and should
require transmission service providers
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97 See
Order No. 693, FERC Stats. & Regs.
¶ 31,242 at P 5 (stating that in order for the
Commission to determine that Reliability Standard
is just and reasonable it must find, inter alia, that
the Reliability Standard is designed to achieve a
specified reliability goal and contains a technically
sound means to achieve this goal).
98 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
P 290.
99 Order No. 890–A, FERC Stats. & Regs. ¶ 31,261
at P 99.
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to update their models after any
incident that substantially alters system
conditions, such as generation outages.
163. The benchmarking and updating
requirements directed herein need not
be so specific that they set a maximum
discrepancy between the model and the
actual results. As stated above, a
transmission service provider should
retain some discretion to reflect unique
system conditions or modeling
assumptions in its available
transmission capability methodology.
There may be modeling assumptions or
actual system conditions that result in
wide variations between modeled
values and actual results. The purpose
of these benchmarking and updating
available transfer and flowgate
capability values is to increase accuracy
by improving transparency. However,
the Commission will not go so far as to
direct a maximum discrepancy.
Similarly, the Commission will not
require these benchmarking and
updating processes be open to
stakeholder input once the requirements
are in place. Allowing stakeholders to
participate in a transmission service
provider’s modeling practices would
place an undue burden on transmission
service providers and threaten their
ability to model their systems
effectively.
164. The Commission also believes
that the benchmarking requirements
directed herein should not be designed
or used by the ERO to monitor undue
discrimination. Transmission providers
within the Commission’s FPA sections
205 and 206 jurisdiction are required to
adhere to the Commission’s open access
and non-discrimination principles. If
the information gathered pursuant to
NERC’s benchmarking requirements
provides evidence of undue
discrimination against a jurisdictional
entity, such information should be
brought to the Commission’s attention
either by the ERO or another entity with
access to the modeling data. In
response, the Commission may
investigate the alleged behavior
pursuant to its authority under sections
205 and 206 of the FPA.
c. Treatment of Network Resource
Designations
NOPR Proposal
165. In the NOPR, the Commission
observed that NERC has not explained
its failure to include in each of the
available transfer capability
methodologies a requirement that base
generation dispatch schedules will
reflect the modeling of all network
resources and other resources that are
committed to or have the legal
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obligation to run, as they are expected
to run. The Commission stated that it
was therefore unclear whether the
proposed Reliability Standards address
the effect of available transfer capability
on designating and undesignating a
network resource. Although the
Commission proposed to approve the
proposed Reliability Standards as just
and reasonable and an improvement on
available transfer capability
transparency, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, the Commission
proposed to direct the ERO to develop
a modification to the Reliability
Standards to address these
requirements.
Comments
166. NERC admits that MOD–029–1
does not address the designation of
network resources, but states that
requirement R3.1.3 of MOD–028–1 may
address the Commission’s concern by
describing the key components to
determining total transfer capability,
namely: ‘‘Unit commitment and
dispatch order, to include all designated
network resources and other resources
that are committed or have the
obligation to run.’’ The Georgia
Companies and Duke agree, also citing
to the language of R3.1.3 of MOD–028–
1. They also argue that MOD–030–2
reflects the modeling of network
resources and other resources that have
the obligation to run, citing to
requirements R6.1.2 and R6.2.2, which
contain language similar to requirement
3.1.3 of MOD–028–1. Northwest
Utilities, Pacific Northwest state that
they support the comments and
arguments made by NERC.
167. Puget Sound contends that it is
appropriate for the proposed Reliability
Standards to require a model that best
reflects expected conditions for the
applicable horizon. Puget Sound argues
that the proposed MOD Reliability
Standards also should require
disclosure of the generation profile or
dispatch used in the total transfer
capability and available transfer
capability calculations. Puget Sound
suggests that incorporating a blanket
requirement built around the OATTdefined term ‘‘designated network
resource,’’ will not ensure a model run
that best reflects expected conditions.
As an example, Puget Sound states that
if a wind generation resource is
designated as a network resource, such
a designation would not guarantee that
the generation is available. Likewise,
Puget Sound states, designated
resources are increasingly undesignated
for monthly periods but are still run to
supply native load using point-to-point
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or secondary service. Thus, Puget Sound
contends, it is incorrect to assume that
a designated network resource runs at a
particular load level, based solely on its
designation status. Rather, Puget Sound
contends, the total transfer capability
and available transfer capability
calculations should simply correspond
with expected conditions, including an
expected dispatch and that the dispatch
condition be transparent.
168. TAPS questions the language of
the NOPR referring to the ‘‘modeling of
all designated network resources and
other resources that are committed to or
have the legal obligation to run, as they
are expected to run.’’ 100 TAPS contends
that the first part of this clause could be
interpreted as directing NERC to
develop modified standards that adopt
modeling assumptions as to use of
network resources that fail to reflect the
flexibility inherent in network service,
which allows for economic dispatch of
available resources. TAPS notes that,
even if designated, a network resource
does not have to operate. TAPS states
that the second phrase ‘‘as they are
expected to run’’ tempers this
requirement, but asks the Commission
to avoid being prescriptive in the Final
Rule as to how network resource is to
be modeled to avoid confusion.
169. TAPS also contends that the
NOPR proposal does not expressly
incorporate, or perhaps even leave room
for, the concept articulated in Order No.
890–C of reexamining the Commission’s
undesignation requirements, and in
particular the requirement of unitspecific undesignations for off-system
sales of system power, in light of better
information as to their practical impact
on the realistic determination of
available transfer capability. TAPS
questions the usefulness of modifying
the Reliability Standards to require unitspecific undesignations for resources
used to serve off-system sales,
suggesting that such undesignations on
a day-ahead basis are not likely to
usefully enhance the precision of
available transfer capability
calculations.
170. TAPS contends that the
Commission should initiate a process to
reexamine the interaction of network
resource undesignation requirements
with available transfer capability
calculations. TAPS states that it would
be contrary to the Commission’s procompetitive policies to discourage
beneficial transactions, including firm
system sales from entities other than the
customer’s host transmission provider,
particularly if it is unlikely that
available transfer capability calculations
would be made significantly more
precise by imposing unit-specific
undesignation requirements on system
sales where the supplier and purchaser
do not take network service on the same
transmission system. At a minimum,
TAPS contends, the Final Rule should
clearly afford NERC, through its
standards development process, the
flexibility to assess the impact of
network resource designations and
undesignations on available transfer
capability determinations and report
back to the Commission as to its
assessment, along with modified
Reliability Standards as appropriate.
TAPS argues that a more flexible
directive would enable NERC, through
its standards development process, to
access whether unit-specific network
resource undesignations are, in fact,
needed to allow transmission providers
to determine available transfer
capability when a network customer
seeks to make a sale of system power to
an off-system party.
100 Citing NOPR, FERC Stats. & Regs. ¶ 32,641 at
P 120.
101 See Order No. 693, FERC Stats. & Regs.
¶ 31,242 at P 119.
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Commission Determination
171. The Commission finds that
MOD–028–1 and MOD–029–1 fail to
address the directive in Order No. 693
to specify how transmission service
providers should determine which
generators should be modeled in service
when calculating available transfer
capability.101 Specifically, the
Commission directed the ERO to
develop a modification to the Reliability
Standards to specify that base
generation schedules used in the
calculation of available transfer
capability will reflect the modeling of
all designated network resources and
other resources that are committed to or
have the legal obligation to run, as they
are expected to run, and to address the
effect on available transfer capability of
designating and undesignating a
network resource.
172. NERC acknowledges that MOD–
029–1 fails to address this directive.
NERC and commenters cite to
Requirement R3.1.3 of MOD–028–2 in
support of arguments that the Reliability
Standard reflects the modeling of
designated network resources. That
requirement, however, governs the
calculation of total transfer capability,
not existing transmission commitments.
The only information provided as to the
effect of designating and undesignating
a network resource on existing
transmission commitments is in
Requirement R8 of MOD–028–1, which
merely states that ‘‘the firm capacity set
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64907
aside for Network Integration
Transmission Service’’ will be included.
The Reliability Standard fails to identify
how that firm capacity will be
calculated. By comparison,
Requirements R6.1.2 and R6.2.2 of
MOD–030–2 require transmission
service providers to calculate existing
transmission commitments by
accounting for the impact of firm
network service in their transmissions
model based on, among other things,
unit commitment and dispatch order
that includes all designated network
resources. Requirement R8 of MOD–
001–1 further requires the transmission
service provider to perform
recalculations at specified frequencies
to reflect changes over time.
173. The Commission therefore
directs the ERO, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, to develop a
modification to MOD–028–1 and MOD–
029–1 to specify that base generation
schedules used in the calculation of
available transfer capability will reflect
the modeling of all designated network
resources and other resources that are
committed to or have the legal
obligation to run, as they are expected
to run, and to address the effect on
available transfer capability of
designating and undesignating a
network resource.
174. With regard to Puget Sound’s
concern regarding the modeling of
designated network resources, as noted
above MOD–030–2 requires
transmission providers to account for
the impact of firm network service in
their transmission models. This
requirement is flexible enough to allow
transmission service providers to
account for the variable nature of
intermittent generation, as well as the
economic dispatch of all resources, as
noted by TAPS. To the extent either
Puget Sound or TAPS have additional
concerns regarding the development of
MOD–028–1 and MOD–029–1 on this
issue, they may pursue their concerns
through the standards development
process as NERC complies with the
directives above.
175. The Commission finds that it is
premature to consider revisiting its
network resource policies to reflect the
Reliability Standards adopted herein. As
discussed above, MOD–028–1 and
MOD–029–1 fail to address the
directives in Order No. 693 to specify
how transmission service providers
should determine which generators
should be modeled in service when
calculating available transfer capability.
It would therefore not be appropriate for
the Commission to revisit network
resource policies based on the current
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version of those Reliability Standards.
As NERC considers modification to
these standards, TAPS may participate
in the standards development process to
address its concerns regarding the
treatment of unit-specific network
resource undesignations on the
calculation of available transfer
capability.102
d. Updating Available Transfer
Capability and Available Flowgate
Capability Values
NOPR Proposal
176. In the NOPR, the Commission
proposed to approve MOD–001–1
including Requirement R8 and MOD–
030–2, Requirement R10. These
requirements require transmission
service providers that calculate
available transfer capability or available
flowgate capability to recalculate those
values at least one per hour for hourly
values, once per day for daily values,
and once per week for monthly values.
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Comment
177. Entegra contends that the
proposed Reliability Standard does not
mandate any consistency or
transparency regarding the timing of
updates to available transfer capability
calculations, nor does it require
transmission service providers to
consider whether such updates should
be required more frequently for
constrained facilities. Entegra states that
while Requirement R8 of MOD–001–1
requires transmission service providers
to update hourly, daily, and monthly
available transfer capability values once
every hour, day, or month, respectively,
it does not set forth a deadline for such
updates, nor does it require
transmission service providers to
disclose when such updates must occur,
and that therefore the values may have
become inaccurate by the time they are
eventually disclosed. Accordingly,
Entegra asks the Commission to direct
the ERO to revise MOD–001–1,
Requirement R8 to include a one-hour
time limit for updates to daily and
monthly available transfer capability
values. In addition, Entegra asks the
Commission to direct the ERO to modify
the Reliability Standard to require
102 In Order No. 890–D, issued concurrently with
this order, the Commission clarifies that, when a
buyer and seller of capacity from a network
resource both take network service on the same
transmission system and the power is delivered
under section 31.3 of the pro forma Open Access
Transmission Tariff (OATT) to another
transmission system on which the buyer’s network
load is located, the seller may support the
transaction by undesignating its resources on a
system basis. Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890–
D, 129 FERC ¶ 61,126 (2009).
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transmission service providers to
consider whether more frequent updates
are necessary for constrained facilities.
178. Cottonwood contends that
Requirement R8 of MOD–001–1 and
Requirement R10 of MOD–030–2 do not
address the procedures for determining
whether unscheduled or unanticipated
events, such as unplanned outages or
the return of a major transmission line
earlier than expected, justify the
updating of available transfer capability
values. Cottonwood argues that a lack of
such procedures will result in
inaccurate available transfer capability
values and accompanying service
issues. Cottonwood argues that, in the
event of such a material change in
system condition, available transfer
capability or available flowgate
capability values should be recalculated
more often than proposed in the
Reliability Standards. At a minimum,
Cottonwood argues, the Commission
should clarify that, for purposes of
compliance with its OATT, a
transmission service provider may not
rely on these Reliability Standards as a
‘‘safe harbor’’ for its failure to make
more frequent available transfer
capability value adjustments as
warranted by changes in system
conditions.
Commission Determination
179. We agree that, in order to be
useful, hourly, daily and monthly
available transfer capability and
available flowgate capability values
must be calculated and posted in
advance of the relevant time period.
Requirement R8 of MOD–001–1 and
Requirement R10 of MOD–030–2
require that such posting will occur far
enough in advance to meet this need.
With respect to Entegra’s request
regarding more frequent updates for
constrained facilities, we direct the ERO
to consider this suggestion through its
Reliability Standards development
process. Further, we agree with
Cottonwood regarding unscheduled or
unanticipated events. Therefore,
pursuant to section 215(d)(5) of the FPA
and section 39.5(f) of our regulations,
we direct the ERO to develop
modifications to MOD–001–1 and
MOD–030–2 to clarify that material
changes in system conditions will
trigger an update whenever practical.
Finally, we clarify that these Reliability
Standards shall not be used as a ‘‘safe
harbor’’ to avoid other, more stringent
reporting or update requirements.
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e. MOD–001–1, Consistent Treatment of
Assumptions
NOPR Proposal
180. In the NOPR, the Commission
expressed concern that the proposed
Reliability Standards did not preclude a
transmission service provider from
using data and assumptions in a way
that double counts their impact on
available transfer capability and thereby
skews the amount of capacity made
available to others.103 Although the
Commission recognized that it may be
appropriate for some variables to be
factored into multiple components of
the available transfer capability
calculation, such as facility ratings, the
Commission stated that the Reliability
Standards do not require that
assumptions affecting multiple
components of the available transfer
capability calculation are implemented
in a way that is consistent with their
actual effect on available transfer
capability. Accordingly, the
Commission proposed to direct the
ERO, pursuant to section 215(d)(5) of
the FPA and section 35.19(f) of its
regulations, to modify the proposed
Reliability Standards to ensure that they
preclude a transmission service
provider from using data and
assumptions in a way that double
counts their impact on available transfer
capability.
Comments
181. ISO/RTO Council states that the
double-counting issue has no
measurable impact on the reliability of
the Bulk-Power System and hence is
outside the mandate of the ERO. ISO/
RTO Council and Pacific Northwest
contend that ensuring increased
transparency of the implementation
documents is not critical to reliability or
within NERC’s area of responsibility as
the ERO. Separately, Midwest ISO
contends that the Reliability Standards
as written do not permit an entity to
double count the impact of data and
assumptions on available transfer
capability calculations and recommends
that the commission accept the
Reliability Standards as proposed.
182. Likewise, Northwest Utilities and
Pacific Northwest comment that the
Commission’s concern with doublecounting is better addressed through a
business practice than in the Reliability
Standards. Northwest Utilities contends
that even if a transmission service
provider were to double-count in the
manner the Commission suggests,
commercial sales of transmission
services would be impacted but not
103 NOPR,
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reliability. Northwest Utilities states
that making less available transfer
capability available than is possible
does not imperil Bulk-Power System
reliability because the system would be
used even less than the extent of its
capacity.
183. By contrast, TAPS supports the
Commission’s proposal to direct the
ERO to modify the Reliability Standards
to ensure that they do not allow a
transmission service provider to use
data and assumptions in a way that
double counts their impact on available
transfer capability. TAPS contends that
transmission providers must not be
permitted to calculate available transfer
capability using data and assumptions
that double count the impact of factors
that would artificially decrease available
transmission and create the appearance
of constraints. TAPS also states that the
NOPR proposal is consistent with Order
No. 890’s effort to enhance reliability
and competition through more accurate
and transparent calculation of available
transfer capability.
Commission Determination
184. As proposed, MOD–001–1 does
not restrict a transmission service
provider from double counting data
inputs or assumptions in the calculation
of available transfer or flowgate
capability. To the extent possible,
available transfer or flowgate capability
values should reflect actual system
conditions. The double-counting of
various data inputs and assumptions
could cause an understatement of
available transfer or flowgate capability
values and, thus, poses a risk to the
reliability of the Bulk-Power System.
We note that, in the Commission’s order
accepting the associated NAESB
business standards, issued concurrently
with this Final Rule in Docket No.
RM05–5–013, the Commission directs
EPSA to address its concerns regarding
the modeling of condition firm service
through the NERC Reliability Standards
development process.104 We reaffirm
here that modeling of available transfer
capability should consider the effects of
conditional firm service, including the
potential for double-counting.
Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, the Commission
directs the ERO to develop
modifications to MOD–001–1 pursuant
to the ERO’s Reliability Standards
development process to prevent the
double-counting of data inputs and
assumptions. In developing these
104 Standards for Business Practices and
Communication Protocols for Public Utilities, Order
No. 676–E, 129 FERC ¶ 61,162.
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modifications, the ERO should consider
the effects of conditional firm service.
f. MOD–001–1, Requirement R2
NOPR Proposal
185. In the NOPR, the Commission
proposed to approve MOD–001–1,
including Requirement R2. Requirement
R2 states that ‘‘Each Transmission
Service Provider shall calculate
[available transfer capability] or
[available flowgate capability] values as
listed below using the methodologies
selected by its Transmission
Operator(s).’’ A transmission service
provider must calculate these values
according to the following subrequirements: R2.1 ‘‘Hourly values for at
least the next 48 hours;’’ R2.2 ‘‘Daily
values for at least the next 31 days;’’ and
R2.3 states ‘‘Monthly values for at least
the next 12 months.’’
Comment
186. Entergy requests clarification of
the available transfer capability/
available flowgate capability
calculations that must be performed
under Requirement R2 of MOD–001–1.
Entergy states that it is unclear whether
these sub-requirements dictate a
minimum level of granularity in
calculated available flowgate capability
values and whether the subrequirements overlap each other or are
independent requirements. As an
example, Entergy states that a
transmission operator that calculates
hourly values for the next 48 hours,
under these sub-requirements, should
meet the requirement and not be
required to also calculate two, separate
daily values for the time period
captured by those hours. Thus, Entergy
contends, the hourly values should be
sufficient, in this example, to comply
with the Reliability Standard without
calculating any additional daily values.
187. Similarly, Entergy states that it is
unclear whether, in addition to the
calculation of daily available transfer
capability values over the next 31 days,
the transmission operator must also
calculate monthly available flowgate
capability values for the same period, or
whether the transmission operator may
simply calculate the daily values for the
31 days in the first month and then
calculate monthly values for the
remaining eleven months in the ‘‘the
next 12 months’’ period. Entergy states
that it believes that this is the intent of
the requirements because of the use of
the word ‘‘next’’ in Requirements R2.1,
R2.2 and R2.3 as well as the
parenthetical ‘‘(months 2–13)’’ in
Requirement R2.3.
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64909
188. Entegra asks the Commission to
direct the ERO to modify Requirement
R2 to require transmission service
providers to eliminate or minimize the
use of inconsistent modeling practices
over different timeframes. Entegra
contends that if a transmission service
provider determines that it is not
feasible to use consistent modeling
practices for all timeframes, the revised
standard should require transmission
service providers to identify and
document differences in models and
modeling practices due to available
transfer capability/available flowgate
capability calculation timeframes and
provide a justification for each of the
various modeling practices employed.
189. Entegra also asks the
Commission to direct the ERO to modify
Requirement R2.3 to clarify that
transmission service providers that
currently post available transfer
capability or available flowgate
capability values for a longer period
should continue to do so. Entegra
contends that failing to direct such a
revision would allow the ERO to adopt
a lowest common denominator rule in
violation of Order No. 672.105
Commission Determination
190. Under Requirement R2 of MOD–
001–1, transmission service providers
must calculate hourly, daily and
monthly values for available transfer
capability or available flowgate
capability. The requirement also sets a
minimum frequency for such
calculations. For example, a
transmission service provider must
calculate available transfer capability or
available flowgate capability hourly for
at least the next 48 hours. However, a
transmission service provider
calculating these values for a longer
period would comply with the
Reliability Standard. Thus, we reject the
notion Requirement R2 represents the
‘‘lowest common denominator.’’
191. To the extent necessary, we
clarify that the timeframes for
calculating available transfer capability
and available flowgate capability are not
concurrent. A transmission service
provider must calculate hourly values
for the next 48 hours. Beyond those 48
hours, the transmission service provider
must calculate daily values for at least
the next 31 calendar days. And, beyond
those 31 calendar days, a transmission
service provider must calculate monthly
values for at least the next 12 months
(months 2–13). This understanding is
supported by the fact that the ERO
describes each period as the ‘‘next’’
105 Citing Order No. 672, FERC Stats. & Regs.
¶ 31,204 at P 329.
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period and the next 12 months as
months 2 through 13.
192. In its filing letter, NERC states
that it requires applicable entities to
calculate available transfer capability or
available flowgate capability on a
consistent schedule and for specific
timeframes. In keeping with the
Commission’s goals of consistency and
transparency in the calculation of
available transfer capability or available
flowgate capability, the Commission
finds that transmission service
providers should use consistent
modeling practices over different
timeframes. If a transmission service
provider uses inconsistent modeling
practices over different timeframes, that
should be made explicit in its
implementation document along with a
justification for the inconsistent
practices. Accordingly, pursuant to
section 215(d)(5) of the FPA and section
39.5(f) of our regulations, the
Commission directs the ERO to develop
a modification to the Reliability
Standard pursuant to its Reliability
Standards development process
requiring transmission service providers
to include in their implementation
documents any inconsistent modeling
practices along with a justification for
such inconsistencies.
between one or more transmission
service providers. Entergy states that
some transmission service providers
may be parties to seams agreements that
do not address a forward-looking
congestion management process or the
allocation of flowgate capabilities
among multiple owners or users. Under
such circumstances, Entergy contends
that the purposes of sub-requirement
R3.5 would not be serviced by setting
forth the details of such agreement in
the available transfer capability
implementation document.
g. MOD–001–1, Requirement R3
NOPR Proposal
NOPR Proposal
196. In the NOPR, the Commission
proposed to approve MOD–001–1,
including Requirements R6 and R7.
Requirement R6 requires transmission
operators calculating total transfer
capability or total flowgate capability to
use assumptions no more limiting than
those used in the planning of operations
for the corresponding time period
studied, providing such planning of
operations has been performed for that
period. Similarly, Requirement R7
requires transmission service providers
calculating available transfer capability
or available flowgate capability to use
assumptions no more limiting than
those used in the planning of operations
for the corresponding time period
studied, providing such planning of
operations has been performed for that
period.
193. In the NOPR, the Commission
proposed to approve MOD–001–1,
including Requirement R3, which
requires transmission service providers
to prepare and keep a current available
transfer capability implementation
document. Sub-requirement R3.5
requires the transmission service
provider to include in the
implementation document a description
of the allocation processes used to
allocate transfer or flowgate capability:
(1) Among multiple lines or sub-paths
within a larger available transfer
capability path or flowgate; (2) among
multiple owners or users of an available
transfer capability path or flowgate; and
(3) between transmission service
providers to address issues such as
forward looking congestion management
and seams coordination.
srobinson on DSKHWCL6B1PROD with RULES2
Comment
194. Entergy requests that the
Commission direct NERC to clarify that
the applicability of these requirements
is not triggered merely by participation
in a seams agreement, but by the
transmission service provider’s
participation in a seams agreement that
also provides for a forward-looking
congestion management process
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Commission Determination
195. The Commission believes that
Requirement R3 is sufficiently clear
without making any distinction as to
what sort of seams agreements or other
type of agreement may be in place. If a
seams agreement does not consider
forward-looking congestion
management or allocation of flowgate
capabilities among multiple owners or
users, the information posted under this
requirement should so reflect.
Participation in a seams agreement does
not excuse a transmission service
provider from complying with this
requirement.
h. MOD–001–1, Requirements R6 and
R7
Comment
197. Entergy points out that, in Order
No. 890, the Commission stated that it
would adopt its ‘‘NOPR proposal to
require transmission providers to use
data and modeling assumptions for the
short- and long-term available transfer
capability calculations that are
consistent with that used for the
planning of operations and system
expansion, respectively, to the
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maximum extent possible.’’ 106 Entergy
also points out that, in Order No. 693,
the Commission stated that the process
and criteria ‘‘used to determine transfer
capabilities must be consistent with the
process and criteria used for other users
of the Bulk-Power System.’’ 107 Entergy
states that, as currently drafted,
Requirements R6 and R7 do not
specifically define ‘‘planning of
operations.’’ Entergy also states that the
phrase ‘‘for the corresponding time
period studied, providing such planning
of operations has been performed for
that period’’ is unclear, making it
difficult to determine the assumptions
that may not be more limiting.
Accordingly, Entergy asks the
Commission to direct NERC to modify
MOD–001–1, Requirements R6 and R7
to explicitly state whether the
assumptions used for long-term
planning, i.e., the assumptions used to
plan for native load and reliability, can
be no more limiting than the
assumptions used to calculate available
transfer capability or available flowgate
capability and total transfer capability
or total flowgate capability.
198. Entegra contends that the
proposed Reliability Standard would
permit transmission service providers to
use a wide range of assumptions for
available flowgate capability and total
transfer capability or total flowgate
capability calculations, which need not
be consistent with those calculations
used for different time periods, much
less with the assumptions used for the
planning of operations or system
operations.
Accordingly, Entegra asks the
Commission to direct the ERO to revise
MOD–001–1 to require transmission
service providers to use data and
assumptions for their short-term and
long-term available transfer capability or
available flowgate capability and total
transfer capability or total flowgate
capability calculations that are
consistent with (i.e., the same as) those
used in the planning of operations and
system expansion, respectively, to the
maximum extent possible, as required
by Order Nos. 693 and 890.108 In
addition, Entegra asks the Commission
to direct the ERO to revise the
requirements to explicitly require all
transmission service providers to
incorporate all data, modeling
assumptions, and mitigation procedures
used in operations planning and longterm expansion studies in their
106 Order No. 890, FERC Stats. & Regs. ¶ 31,241
at P 292.
107 Citing Order No. 693, FERC Stats. & Regs.
¶ 31,242 at P 758.
108 Citing Id. P 1057; Order No. 890, FERC Stats.
& Regs. ¶ 31,241 at P 292.
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available flowgate capability and total
transfer capability or total flowgate
capability models and calculations.
199. Midwest ISO contends that the
terms ‘‘assumptions’’ and ‘‘no more
limiting’’ as used in Requirements R6
and R7 are not specific enough for
entities to prepare for compliance.
Midwest ISO states, for example, that it
is unclear whether load assumption falls
within the scope of ‘‘assumption’’ and,
if so, which load assumption is deemed
to be ‘‘more limiting’’ than another.
Accordingly, Midwest ISO asks the
Commission to direct the ERO to
provide more specific details about
what constitutes an ‘‘assumption’’ and
to define the scope of the phrase ‘‘no
more limiting’’ so that the Reliability
Standard may be followed and audited
with greater specificity.
srobinson on DSKHWCL6B1PROD with RULES2
Commission Determination
200. With regard to Midwest ISO’s
concern, while the terms ‘‘assumptions’’
and ‘‘no more limiting’’ as used in
Requirements R6 and R7 could benefit
from further granularity, we find these
Requirements to be sufficiently clear for
purposes of compliance. Likewise, with
regard to Entegra’s concern, we agree
that transmission service providers
should use data and assumptions for
their available transfer capability or
available flowgate capability and total
transfer capability or total flowgate
capability calculations that are
consistent with those used in the
planning of operations and system
expansion. Under Requirements R6 and
R7, transmission service providers and
transmission operators must not
overstate assumptions that are used in
planning of operations. We believe these
requirements are sufficiently clear as
written. Nonetheless, we encourage the
ERO to consider Midwest ISO’s and
Entegra’s comments when developing
other modifications to the MOD
Reliability Standards pursuant to the
ERO’s Reliability Standards
development procedure.
201. While Entergy is correct that the
Standard does not define ‘‘planning of
operations,’’ we do not find either that
phrase or the phrase ‘‘for the
corresponding time period studied,
providing such planning of operations
has been performed for that period’’
unclear. It is not necessary for this
Reliability Standard to make an explicit
statement about the assumptions used
in long-term planning.
i. MOD–001–1, Requirement R9
NOPR Proposal
202. In the NOPR, the Commission
proposed to approve MOD–001–1,
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including Requirement R9, which
provides that ‘‘[w]ithin thirty calendar
days of receiving a request by any
Transmission Service Provider,
Planning Coordinator, Reliability
Coordinator, or Transmission Operator
for data * * * solely for the use in the
requestor’s [available transfer capability]
or [available flowgate capability]
calculations, each transmission service
provider receiving said request shall
begin to make the requested data
available to the requestor, subject to the
conditions specified in R9.1 and R9.2.’’
Sub-requirement R9.2 provides that
‘‘[t]his data shall be made available by
the Transmission Provider on the
schedule specified by the requestor (but
no more frequently than once per hour,
unless mutually agreed to by the
requestor and the provider).’’
Comments
203. Entergy asks NERC to clarify that,
while the transmission provider must
make the requested data available to the
requestor according to the schedule
specified by the requestor, the
transmission provider is not obligated to
provide the data on a more frequent
basis than the transmission provider
updates its available flowgate capability
models. Entergy contends that this
clarification would make subrequirement R9.2 consistent with the
apparent purpose of sub-requirement
R9.1, which seeks to minimize the
burden on the transmission service
provider by requiring the transmission
service provider to make the data
available to a requestor in the format
maintained by the transmission service
provider.
204. Entergy states that the Reliability
Standard does not require the exchange
of data regarding counterflows and
available transfer capability
recalculation frequency and timing, as
required by Order No. 890.109 Entergy
asks the Commission to direct the ERO
to modify Requirement R9 to require
transmission service providers to
exchange such information. In addition,
Entergy contends that the Reliability
Standard should be revised to mandate
periodic exchange of all model data and
on-going coordination of available
flowgate capability and total transfer
capability or total flowgate data among
adjacent transmission service providers,
rather than only requiring such data
exchange upon the request of a limited
class of users of the Bulk-Power System.
109 Citing Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 310.
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64911
Commission Determination
205. The Commission finds that,
under Requirement R9 of MOD–001–1,
a transmission service provider must
respond to requests for data even when
they are made more frequently than the
transmission service provider updates
its available transfer or flowgate
capability models. If a request is made
before the transmission service provider
has updated its model, the transmission
service provider must respond
providing the same data as previously
produced or making a statement that no
change has been made. The Commission
does not foresee this requirement as
becoming a burden because a requestor
is not likely to request more often than
the calculation frequency if they are
aware of the frequency with which the
value is updated. Additionally,
Requirement R9.2 addresses a maximum
frequency for which any entity can
request a given available transfer
capability or flowgate value. For these
reasons, the Commission will not direct
the proposed modifications.
206. In response to Entergy’s concern,
the Commission believes that
Requirement R9 is sufficiently clear
insofar as it requires the exchange of
data regarding counterflows and
available transfer capability
recalculation frequency and timing, as
required by Order No. 890.110
Requirement R9 requires transmission
service providers to provide available
transfer capability values for all
available transfer capability paths.
These values should include
information on counterflows because,
under Requirement R3.2 of MOD–001–
1, a transmission service provider must
include in its implementation
documents a description of how it
accounts for counterflows. Moreover,
under Requirement R9.1, a transmission
service provider must make its own data
available for up to 13 months after
receiving a request for data.
j. MOD–001–1, Counterflows
NOPR Proposal
207. In the NOPR, the Commission
reiterated its concern from Order No.
890 regarding consistency in the use of
counterflow assumptions in short-term
and long-term calculations of available
110 Order No. 890, FERC Stats. & Regs. ¶ 31,241
at P 310. The Commission found that the following
data shall, at a minimum be exchanged among
transmission providers for the purposes of available
transfer capability modeling: (1) Load levels; (2)
transmission planned and contingency outages; (3)
generation planned and contingency outages; (4)
base generation dispatch; (5) exiting transmission
reservations, including counterflows; (6) available
transfer capability recalculation frequency and
times; and (7) source/sink modeling identification.
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transfer capability.111 The Commission
noted, in the NOPR, that the MOD
Reliability Standards achieve
consistency by requiring each
transmission service provider to identify
in its available transfer capability
implementation document how it
accounts for counterflows and to
calculate available transfer capability
using assumptions no more limiting
than those used in the planning of
operations for the corresponding time
period.
208. Requirement R3.2 of MOD–001–
1 requires a transmission service
provider to include in its available
transfer or flowgate capability
implementation document a description
of the manner in which the transmission
service provider will account for
counterflows. The Commission
expressed concern, however, that the
Reliability Standards place no limit on
the parameters the transmission service
provider can use to account for
counterflows. Accordingly, the
Commission proposed to direct a review
of the additional parameters and
assumptions included by each
transmission service provider in its
implementation document and sought
comment on whether additional
requirements should be directed to
eliminate the potential for undue
discrimination in the provision of
transmission service.
srobinson on DSKHWCL6B1PROD with RULES2
Comments
209. Entegra contends that the
Commission should direct the ERO to
modify Requirement R3.2 of MOD–001–
1 to ensure that counterflows are
modeled consistently and to require
transmission service providers to
provide a justification, along with work
papers and analyses, for the counterflow
percentage used in their calculations of
firm and non-firm available transfer
capability or available flowgate
capability. Entegra contends that the
Reliability Standard should also require
each transmission service provider to
measure and account for counterflows
in a manner that reflects actual
operations and system conditions.
Accordingly, Entegra suggests that the
Reliability Standard should require
transmission service providers to
benchmark the treatment of
counterflows against actual events and
to update the models and counterflow
methodology. Entegra also suggests that
the MOD–001–1 should require
transmission service providers to adopt
111 NOPR, FERC Stats. & Regs. ¶ 32,641 at p. 91;
Order No. 890, FERC Stats. & Regs. ¶ 31,241 at
p. 292–93; Order No. 693, FERC Stats. & Regs.
¶ 31,242 at p. 1039.
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a methodology that will not restrict
competition or result in unduly
discriminatory treatment.
Commission Determination
210. As discussed above, the
benchmarking of available transfer
capability and available flowgate
capability values and their components
will provide information necessary to
determine whether the calculations are
being performed in a consistent manner.
The audit of sub-requirement R3.1
directed above will address all
parameters used to calculate available
transfer capability or available flowgate
capability that are necessary to validate
the calculations. Furthermore,
transmission service providers within
the Commission’s jurisdiction under
section 205 of the FPA are already
required to not adopt a methodology
that will restrict competition or result in
unduly discriminatory treatment. For
these reasons, Entegra’s suggested
modifications of sub-requirement R3.2
are not necessary at this time.
2. MOD–004–1, Capacity Benefit Margin
NOPR Proposal
211. Requirements R5.1 and R6.1 of
MOD–004–1 require transmission
service providers to establish capacity
benefit margin values for each path and
flowgate that reflect consideration of
both (i) studies provided by load-serving
entities and resource planners
demonstrating a need for capacity
benefit margin and (ii) applicable
reserve margin or resource adequacy
requirements. In preparing their studies,
Requirements R3.1 and R4.1 direct loadserving entities and resource planners to
use one or more of the following to
determine the generation capability
import requirement: (i) Loss of load
expectation studies, (ii) loss of load
probability studies, (iii) deterministic
risk-analysis studies, and/or (iv)
applicable reserve margin or resource
adequacy requirements. With regard to
the allocation and use of transmission
capacity set aside as capacity benefit
margin, Requirement R1.3 requires the
transmission service provider to include
in its capacity benefit margin
implementation document the
procedure for a load-serving entity or
balancing authority to use transmission
capacity set aside as capacity benefit
margin, including the manner in which
the transmission service provider ‘‘will
manage’’ situations where the requested
use of capacity benefit margin exceeds
the capacity benefit margin available.
212. In the NOPR, the Commission
expressed concern that, as proposed, the
Reliability Standard would allow a
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transmission service provider to
calculate, allocate, and use capacity
benefit margin in a way that impairs the
reliable operation of the Bulk-Power
System. The Commission explained
that, under the Reliability Standard, the
transmission service provider is to
‘‘reflect consideration’’ of studies
provided by load-serving entities and
resource planners demonstrating a need
for capacity benefit margin and
‘‘manage’’ situations where the
requested use of capacity benefit margin
exceeds the capacity benefit margin
available. The Commission observed
that the Reliability Standard places no
bounds on this ‘‘consideration’’ and
‘‘management’’ and, for example, would
permit a transmission service provider
to make decisions regarding the use of
capacity benefit margin based solely on
economic considerations
notwithstanding a demonstration of
need for capacity benefit margin by a
load-serving entity or resource planner.
The Commission therefore proposed,
pursuant to section 215(d)(5) of the FPA
and section 39.5(f) of our regulations, to
direct the ERO to develop a
modification to the Capacity Benefit
Margin Methodology (MOD–004–1) to
ensure that the Reliability Standard
would not allow a transmission service
provider to calculate, allocate, and use
capacity benefit margin in a way that
impairs the reliable operation of the
Bulk-Power System.
213. The Commission also expressed
concern regarding references to
applicable reserve margin and resource
adequacy requirements in the
determination of the generation
capability import requirements by loadserving entities and resource planners
under Requirements R3.1 and R4.1. The
Commission stated that, under the
phrasing of those provisions, loadserving entities and resource planners
must determine their generation
capability import requirement by using
one or more of loss of load expectation
studies, loss of load probability studies,
deterministic risk-analysis studies, and
applicable reserve margin or resource
adequacy requirements. As a result, the
Commission commented, a load-serving
entity or resource planner could rely
solely on reserve margin and resource
adequacy requirements to demonstrate a
need for capacity benefit margin
without any analysis of loss of load
expectations, loss of load probabilities,
or deterministic risk. In comparison, the
Commission observed that
Requirements 5.1 and 6.1 obligate the
transmission service provider to
consider both the studies provided by
load-serving entities and resource
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planners and applicable reserve margin
and resource adequacy requirements
when calculating capacity benefit
margin and allocating it to particular
paths or flowgates. The Commission
therefore proposed, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, to direct the ERO to
develop a modification to MOD–004–1
to require load-serving entities and
resource planners to determine
generation capability import
requirements by reference to relevant
studies and applicable reserve margin or
resource adequacy requirements, as
relevant.
srobinson on DSKHWCL6B1PROD with RULES2
Comments
214. NERC objects to the
Commission’s proposed modification to
MOD–004–1. To address a perceived
disparity in MOD–004–1, NERC
explains that, based on stakeholder
guidance, it determined that the actual
manner in which a load-serving entity
or resource planner determines its
generation capability import
requirement may differ significantly
based on the requestor’s internal
practices, as well as the regulatory
regime under which it operates. NERC
states that the use of the words ‘‘one or
more’’ in the Reliability Standard was
intended to indicate that an entity
desiring to have capacity benefit margin
withheld for its potential use could
establish that need using any one of the
methods described. NERC states that the
entity also has the option to provide
additional studies or information if it so
desired or was obligated to do so. In the
case of a transmission service provider
or transmission planner, however,
NERC states that the Reliability
Standard drafting team felt that it was
important that any information
provided be considered when
establishing an appropriate level of
capacity benefit margin.
215. Georgia Companies contend that
a transmission service provider cannot
ensure that the calculation of capacity
benefit margin would not impair the
reliable operation of the Bulk-Power
System because that would require
ensuring resource adequacy, which a
transmission service provider cannot
do. Georgia Companies state that a
transmission service provider must rely
on resource adequacy information
provided by load serving entities when
managing transmission reliability.
Therefore, Georgia Companies contend
that the Commission should accept the
NERC-proposed language in MOD–004–
1 that transmission providers reflect
consideration of any studies received
from customers.
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216. Georgia Companies also state
that, on its surface, it appears that
MOD–004–1 appears inconsistent by
allowing a load serving entity or
resource planner to perform one or more
of the listed options while requiring a
transmission service provider or
transmission planner to use all options.
Nevertheless, Georgia Companies
contend that the requirements are
accurate and consistent as written
because the relevant studies are not
applicable in all regions. Thus, Georgia
Companies ask the Commission to not
direct the ERO to develop a
modification to MOD–004–1 to require
load serving entities and resource
planners to determine generation
capability import requirements by
reference to relevant studies and
applicable reserve margin or resource
adequacy requirements. If the
Commission does direct such action,
Georgia Companies contend that it
could require a load serving entity or
resource planner to perform studies that
are not required (nor applicable or used)
by multiple State agencies, RTOs, ISOs,
or other regional authorities.
217. Midwest ISO expresses concern
that the Reliability Standards drafting
team interpreted the language from
Order Nos. 890 and 693 such that a load
serving entity’s request to set aside
capacity benefit margin is final, and that
no input is permitted by the
transmission service provider, even if
the load serving entity is part of an ISO
or RTO. Midwest ISO contends that this
interpretation could result in an
unreasonable over-reservation of
capacity benefit margin, considering the
scant likelihood of actual impairment of
the reliability of the system. Midwest
ISO contends that the benefit to system
reliability that would result from setting
aside capacity benefit margin for a lowprobability scenario is outweighed by
the complexity of compliance with an
inflexible interpretation of the
Commission’s orders. Thus, Midwest
ISO asks the Commission to direct the
ERO to consider the transmission
service provider’s role in assessing the
total amount of capacity benefit margin
reasonably required to preserve the
reliability of the system.
218. TAPS supports the Commission’s
proposal to direct the ERO to develop
modifications to the Reliability
Standard that require capacity benefit
margin set-asides to determine
generation capability import
requirements by reference to relevant
studies and applicable reserve margin or
resource adequacy requirements, as
relevant. TAPS expresses concern,
however, that the NOPR proposal could
be interpreted as requiring load-serving
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64913
entities and resource planners to
perform such assessments even if they
are not requesting that transmission be
set aside for capacity benefit margin.
Accordingly, TAPS asks the
Commission to clarify that
Requirements R3 and R4 of MOD–004–
1 require performance assessments only
by those load-serving entities and
resource planners that are requesting
capacity benefit margin to be set aside.
219. The ITC Companies also support
the Commission’s proposed
modification to MOD–004–1. The ITC
Companies state that they agree with the
Commission that the requirement that
the transmission service provider is to
‘‘reflect consideration’’ of studies
provided by the load serving entity or
resource planning in establishing the
capacity benefit margin under MOD–
004–1 is not specific enough and results
in an unbounded requirement. The ITC
Companies contend that it is not a
burdensome request for the load-serving
entity or resource planner to provide a
detailed study to support the generator
capability import requirement used in
setting the capacity benefit margin.
Commission Determination
220. We agree with NERC that a
transmission service provider should
consider any information provided in
establishing an appropriate level of
capacity benefit margin. Similarly, we
agree with the Georgia Companies that
all relevant information should be
considered in establishing an
appropriate level of capacity benefit
margin, including information provided
by customers. However, in determining
the appropriate generation capacity
import requirement as part of the sum
of capacity benefit margin to be
requested from the transmission service
provider, it would not be appropriate for
a load-serving entity or resource planner
to rely exclusively on a reserve margin
or adequacy requirement established by
an entity that is not subject to this
Standard. Thus, we hereby adopt the
NOPR proposal to direct the ERO to
develop a modification to Requirements
R3.1 and R.4.1 of MOD–004–1 to require
load-serving entities and resource
planners to determine generation
capability import requirements by
reference to one or more relevant
studies (loss of load expectation, loss of
load probability or deterministic risk
analysis) and applicable reserve margin
or resource adequacy requirements, as
relevant. Such a modification should
ensure that a transmission service
provider has adequate information to
establish the appropriate level of
capacity benefit margin.
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221. In response to TAPS concerns,
we believe that the Reliability Standard
is sufficiently clear that load-serving
entities and resource planners who do
not request capacity benefit margin be
set aside are not required to perform the
studies prescribed in MOD–004–1.
Requirements R3 and R4 require loadserving entities and resource planners
determining the need for transmission
capacity to be set aside as capacity
benefit margin for imports into
balancing authority to use certain
studies. Thus, if a load-serving entity or
resource planner is not determining
such a need because it chooses not to
request capacity benefit margin to be set
aside, there is no obligation to use the
studies listed in Requirements R3.1 and
R4.1. Moreover, the requirement is to
‘‘use’’ the listed studies. Thus, a loadserving entity or resource planner could
use a study that has been conducted by
another entity, such as an ISO or RTO.
222. We agree with the Midwest ISO
that ISOs, RTOs, and other entities with
a wide view of system reliability needs
should be able to provide input into
determining the total amount of
capacity benefit margin required to
preserve the reliability of the system.
However, Requirements R1.3 and R7
already make clear that determinations
of need for generation capability import
requirement made by a load serving
entity or resource planner are not final.
Further, the third bullet of
Requirements R5 and R6 explicitly lists
reserve margin or resource adequacy
requirements established by RTOs and
ISOs among the factors to be considered
in establishing capacity benefit margin
values for available transfer capability
paths or flowgates used in available
transfer capability or available flowgate
capability calculations. In fact, it is for
this reason that we uphold the NOPR
proposal. Therefore, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, the Commission
directs the ERO to modify MOD–004–1
to clarify the term ‘‘manage’’ in
Requirement R1.3. This modification
should ensure that the Reliability
Standard clarify how the transmission
service provider will manage situations
where the requested use of capacity
benefit margin exceeds the capacity
benefit margin available.
3. MOD–008–1, Transfer Reliability
Margin
Comments
a. General
224. Entegra states that the Reliability
Standard does not establish a maximum
transmission reserve margin, as required
by Order No. 890. Entegra states that the
Reliability Standard gives transmission
operators unbounded discretion to
adopt whatever transmission reserve
margin they choose, without placing
any substantive limits on parameters,
modeling requirements, criteria, or
assumptions used to calculate the
transmission reserve margin.
Accordingly, Entegra asks the
Commission to direct the ERO to
establish a maximum transmission
reserve margin. Entegra points out that
the Commission found, in Order No.
890, that the ‘‘percentage of ratings
reduction’’ method is a reasonable
method because it is relatively simple to
apply and does not restrict transmission
operators from using a more
sophisticated method if appropriate.
Comments
Commission Determination
225. The Commission will not direct
that a maximum transmission reserve
margin be established here. Although
the Commission previously stated that
the ‘‘percentage of ratings reduction’’
method is reasonable, the Commission
does not believe that it is necessary to
fix a maximum value or percentage of
transfer capability set aside as
transmission reserve margin. As stated
above, the Commission believes that it
is appropriate for transmission service
providers to retain some level of
discretion. We believe that transmission
service providers should retain the
discretion to manage risks associated
with their particular system
configurations and physical limitations.
Nonetheless, we believe that it would be
inappropriate for a transmission service
provider to set transmission reserve
margin excessively and unjustifiably
high. The transparency set by these
MOD Reliability Standards will allow
the Commission, NERC and other to
monitor transmission reserve margin
values to determine if they are
reasonable and internally consistent.
The Commission will evaluate evidence
of excessive transmission reserve
margins on a case-by-case basis as
reports of any such occurrences arise.
The Commission, therefore, declines to
direct the proposed modification to
MOD–008–1.
NOPR Proposal
4. MOD–028–1, Area Interchange
Methodology
223. In the NOPR, the Commission
proposed to approve Reliability
Standard MOD–008–1 without
modification.
226. In the NOPR, the Commission
proposed to approve Reliability
Standard MOD–028–1 without
modification.
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227. FPL points out that the
introduction to MOD–028–1 provides
that the area interchange methodology is
characterized by determination of
incremental transfer capability via
simulation, from which total transfer
capability can be mathematically
derived. FPL contends that
mathematical derivation of total transfer
capability is overly simplistic for
implementation. FPL explains that the
simple mathematical additions and
subtractions ignore the interactions
between existing commitments going
between different balancing authorities
as well as the different distribution
factors that various existing
commitments may have on different
flow gates.
Commission Determination
228. FPL did not adequately explain
its concern about the mathematics
required to derive total transfer
capability. The Commission does not
intend to force any party to implement
an unrealistically simplistic
methodology, and notes that
Requirement R1 provides parties using
the area interchange methodology the
latitude to specify the manner of
computation necessary to allow other
parties to validate the computation.
b. MOD–028–1, Requirement R2
NOPR Proposal
229. In the NOPR, the Commission
proposed to approve MOD–028–1,
including Requirement R2, which
provides that, when calculating total
transfer capability for available transfer
capability paths, transmission operators
must use a transmission model that
contains modeling data and topology of
its reliability coordinator’s area of
responsibility, modeling data and
topology (or equivalent representation)
for immediately adjacent and beyond
reliability coordination areas, and
facility ratings specified by the
generator owners and transmission
owners.
Comments
230. FPL points out that subrequirement R2.2 requires the use of
‘‘modeling data and topology (or
equivalent representation) for
immediately adjacent and beyond
Reliability Coordination areas.’’ FPL
contends that the term ‘‘beyond’’ is
vague and subject to different
interpretation. Accordingly, FPL asks
the Commission to direct the ERO to
address this ambiguity.
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Commission Determination
231. The Commission understands
sub-requirement R2.2 of MOD–028–1 to
mean that, when calculating total
transfer capability for available transfer
capability paths, a transmission operator
shall use a transmission model that
includes relevant data from reliability
coordination areas that are not adjacent.
While we believe that the provision is
reasonably clear, the Commission agrees
that the term ‘‘and beyond’’ could be
better explained. Accordingly, pursuant
to section 215(d)(5) of the FPA and
section 39.5(f) of our regulations, the
Commission directs the ERO to develop
a modification sub-requirement R2.2
pursuant to its Reliability Standards
development process to clarify the
phrase ‘‘adjacent and beyond Reliability
Coordination areas.’’
c. MOD–028–1, Requirement R5
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NOPR Proposal
232. In the NOPR, the Commission
proposed to approve MOD–028–1
including Requirement R5, which
requires transmission operators to
establish total transfer capability for
each available transfer capability path
according to the following schedule: (1)
At least once within the seven calendar
days prior to the specified period for
total transfer capabilities used in hourly
and daily available transfer capability
calculations; (2) at least once per
calendar month for total transfer
capabilities used in monthly available
transfer capability calculations; and (3)
within 24 hours of the unexpected
outage of a 500 kV or higher
transmission facility or transformer with
a low-side voltage of 200 kV or higher
for total transfer capabilities in effect
during the anticipated duration of the
outage, provided such outage is
expected to last 24 hours or longer.
Comment
233. FPL comments that subrequirement R5.2 provides that total
transfer capability be established
‘‘[w]ithin 24 hours of the unexpected
outage of a 500 kV or higher
transmission Facility or transformer
with a low-side of 200 kV or higher for
[total transfer capabilities] in effect
during the anticipated duration of the
outage.’’ FPL contends that this subrequirement is too restrictive and
burdensome in certain situations. As an
example, FPL states that meeting this
requirement will be difficult if a facility
is expected to be out of service for an
extended time frame, e.g., a catastrophic
transformer failure which could take a
year to replace. FPL asks the
Commission to consider a graduated
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64915
time frame for reposting where hourly
data for the next 168 hours would be
reposted within 24 hours; the following
23 days of daily data would be reposted
within 48 hours; and, the 13 months of
monthly data would be reposted within
five working days. FPL contends that
this would allow time for the extent of
the damage to be determined and proper
assessments of replacement times to be
established.
applied in R6.1 can be less than 5
percent. FPL contends that once a
distribution factor is selected it should
be applied for all paths so that there is
not a different distribution factor for
different paths. FPL further contends
that the distribution factor to be used
should be clearly stated in the available
transfer capability implementation
document.
Commission Determination
234. The Commission believes that, as
written, the time frames established in
Requirement R5 are just and reasonable
because they balance the need to
reliably operate the grid with the burden
on transmission operators to recalculate
total transfer capability even when total
transfer capability does not often
change. Nevertheless, the Commission
agrees that a graduated time frame for
reposting could be reasonable in some
situations. Accordingly, the ERO should
consider this suggestion when making
future modifications to the Reliability
Standards.
237. The Commission agrees that any
distribution factor to be used should be
clearly stated in the implementation
document, and that to facilitate
consistent and understandable results
the distribution factors used in
determining total transfer capability
should be applied consistently.
Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f)
of our regulations, the Commission
directs the ERO to develop a
modification to MOD–028–1 pursuant to
its Reliability Standards development
process to address these two concerns.
d. MOD–028–1, Requirement R6
NOPR Proposal
235. Requirement R6 of MOD–028–1
requires transmission service providers
to establish total transfer capability for
each available transfer capability path
by use of process specified in the subrequirements. Requirement R6.1
requires transmission operators to
determine the incremental transfer
capability for each available transfer
capability path by increasing generation
and/or decreasing load within the
source balancing authority area and
decreasing generation and/or increasing
load within the balancing authority area
until either: A system operating limit is
reached on the transmission service
provider’s system or a system operating
limit is reached on any other adjacent
system in the transmission model that is
not on the study path and the
distribution factor is 5 percent or
greater.
Comments
236. Regarding sub-requirement R6.1,
FPL contends that the 5 percent or less
distribution factor should apply
regardless of whether the limitation is
on the study path or on an adjacent
system. FPL contends that allowing
application of the 5 percent distribution
factor only on adjacent systems will
create confusion and will cause
inconsistent available transfer capability
postings depending on who is
calculating the path. FPL also points out
that the footnote for sub-requirement
R6.1 states that a distribution factor
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Commission Determination
5. MOD–029–1, Rated System Path
Methodology
a. Sub-Requirement R2.7
NOPR Proposal
238. In the NOPR, the Commission
stated that NERC failed to explain, and
it was not clear why certain applicable
entities would be required to use pre1994 total transfer capability values
under sub-requirement R2.7 in the
Rated System Path Methodology. The
Commission expressed concern that
requiring pre-1994 total transfer
capability values to remain in place
without adequate explanation
essentially exempts certain paths from
the total transfer capability
requirements in the Rated System Path
Methodology and may result in total
transfer capability values that are
incorrectly based on stale assumptions
and data. Accordingly, the Commission
sought comment on whether it should
direct the ERO to develop a
modification to the Rated System Path
Methodology (MOD–029–1) to remove
sub-requirement R2.7 as unsupported.
Comments
239. Many commenters contend that
the Commission should retain subrequirement R2.7 of MOD–029–1.112
Some urge the Commission to give due
weight to the technical expertise of the
ERO with respect to the inclusion of
112 E.g., EEI, Northwestern, Northwest Utilities,
LADWP, Avista, Modesto, Pacific Northwest,
PacifiCorp, Puget Sound, SMUD, Salt River, SWAT,
TANC and Tucson.
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sub-requirement R2.7.113 Commenters
explain that the path-rating
methodology in MOD–029–1 represents
the current methodology for calculating
available transfer capability by entities
operating within the area of the Western
Electricity Coordinating Council
(WECC). They contend that although
these values can be based on pre-1994
total transfer capability values, they
must be updated seasonally within
WECC and, thus, are not stale.114
240. Northwestern claims that the
basic premise of the WECC rating
process is that new path ratings or a
new rating for an upgraded path should
not adversely impact the transfer
capability of a path with either an
accepted or existing rating. If a path’s
transfer capability is adversely
impacted, Northwestern states that the
owners of the path seeking the rating
would have to mitigate the impacts.
Likewise, Pacific Northwest, Public
Power Council and Snohomish state
that the Existing Paths within WECC are
reviewed by the WECC Planning
Committee and annually by the WECC
Operating Committee to assign an
appropriate system operating limit for
each path. As such, they contend, the
Existing path rating cannot yield total
transfer capability or available transfer
capability values in excess of the
technically based seasonal system
operating limit. SMUD notes that the
industry has been using this system for
fifteen years and, in that time, no one
operating under these limits has filed
any complaint, formal challenge, or
request for a change.
241. Some commenters argue that it
would place extreme burden on WECC
to re-rate all the paths in its path rating
catalog that have an Existing Rating 115
or Other designation; a total of 45
paths.116 Northwestern contends that
requiring Existing Rating paths to go
through some new process could
seriously undermine the reliability and
113 E.g., EEI, Pacific Northwest, Public Power
Council and SMUD.
114 E.g., EEI, Northwestern, Northwest Utilities,
LADWP, Avista, Modesto, Pacific Northwest,
PacifiCorp, Puget Sound, SMUD, Salt River, SWAT,
TANC and Tucson.
115 Existing Ratings are defined by WECC as
transmission path ratings that were known and
used in operation as of January 1, 1994. See, WECC,
Overview of Policies and Procedures for Regional
Planning Project Review, Project Rating Review, and
Progress Reports (Revised April 2005), available at
https://www.wecc.biz/library/WECC%20Documents/
Miscellaneous%20Operating%20and%20Planning
%20Policies%20and%20Procedures/Overview%20
Policies%20Procedures%20RegionalPlanning
%20ProjectReview%20ProjectRating%20Progress
Reports_07-05.pdf.
116 E.g., Modesto, Northwestern, Northwest
Utilities, Nevada Companies, Pacificorp, and
TANC.
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economic value the path owners have
appropriately built into their long-range
plan. Similarly, PacifiCorp argues that
removal of sub-requirement R2.7 would
hinder path ratings already in progress
and negatively impact reliance on
transmission rights because many
WECC path ratings are dependent upon
parallel interactions and ratings with
the parallel facilities owned by other
transmission providers. Thus,
PacifiCorp and Northwest Utilities
contend, if sub-requirement R2.7 is
removed, there will be likely be
multiple contract disputes.
Furthermore, if the Commission directs
removal of requirement R2.7 from
MOD–030–2, PacifiCorp contends that it
will be impossible for entities to meet
the one-year implementation schedule.
Some commenters contend that the
existing total transfer capabilities are
operationally proven and that re-rating
the paths within WECC would divert
resources from higher reliability
priorities for several years for no
apparent reliability benefit.117
242. By contrast, ISO/RTO Council
supports the removal of subrequirement R2.7. ISO/RTO Council
states that requiring pre-1994 total
transfer capability values to remain in
place without adequate explanation
essentially exempts certain paths from
the total transfer capability
requirements in the Rated System Path
Methodology and may result in total
transfer capability values that are
incorrectly based on stale assumptions
and criteria. To avoid continuance of or
reversion to the pre-1994 total transfer
capability value for a path under subrequirement R2.7, ISO/RTO Council
states that each RTO and ISO would be
required to conduct comprehensive and
time consuming studies of the paths
they operate within a one-year period.
ISO/RTO Council contends that it
would be unreasonable to require that
this level of effort in the absence of any
explanation by NERC why such studies
are necessary or what benefit it believes
will result. Accordingly, ISO/RTO
Council asks the Commission to direct
the ERO to remove this subrequirement.
Commission Determination
243. The Commission approves
Requirement R2.7 as proposed by NERC.
As commenters note, although some
total transfer capability values were
developed for paths prior to 1994,
WECC regularly reviews these paths to
confirm that those values remain valid.
Moreover, WECC requires re-rating of a
117 E.g., Avista, LADWP, Modest, Salt River,
SWAT, TANC, and Tucson.
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Rated System path in a variety of
instances.118 As a result, we find that
commenters have provided sufficient
evidence that the use of pre-1994 total
transfer capability values for paths
within WECC does not exempt those
paths from the total transfer capability
requirement in the Rated System Path
Methodology. We are further satisfied
that ratings for existing paths with pre1994 total transfer capability values are
not incorrectly based on stale
assumptions because the existing path
ratings must be adjusted for seasonal
variances.
244. Although Requirement R2.7
appears to have been crafted to
accommodate existing practices within
WECC, the Commission points out that
MOD–029–1 is a national Reliability
Standard. Thus, the requirement is
equally binding upon transmission
operators and transmission service
providers using the Rated System Path
Methodology to calculate total transfer
capabilities or available transfer
capabilities for path outside of WECC.
The Commission therefore clarifies that
any transmission operator or
transmission service provider operating
outside of WECC that uses the Rated
System Path Methodology must
demonstrate to the ERO and the
Commission a similar need to
implement Requirement R2.7.
b. Counterschedules
Comment
245. Puget Sound comments that
counterflows are a mandatory
component of the available transfer
capability formula but contends that it
is common practice in the Western
Interconnection to incorporate
counterschedules into non-firm
available transfer capability
calculations, instead of counterflows as
defined in the formula. Puget Sound
therefore requests that the Commission
clarify in the Final Rule that using
counterschedules will not be considered
a violation of MOD–029–1. In addition,
Puget Sound asks the Commission to
clarify that counterflows and
counterschedules are interchangeable
terms, consistent with Western
Interconnection practices.
118 See WECC, Overview of Polices and
Procedures for Regional Planning Project Review,
Project Rating Review, and Progress Reports
(Revised April 2005), Sect. 2.3 Paths Subject To
This Procedure, available at: https://www.wecc.biz/
library/WECC%20Documents/Miscellaneous
%20Operating%20and%20Planning
%20Policies%20and%20Procedures/
Overview%20Policies%20Procedures%20
RegionalPlanning%20ProjectReview%20
ProjectRating%20ProgressReports_07-05.pdf.
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Commission Determination
246. Puget Sound’s request is
reasonable, and insofar as calculating
non-firm available transfer capability
using counterschedules as opposed to
counterflows achieves substantially
equivalent results, using them will not
be considered a violation. However, we
do not have enough information to
determine that the terms are generally
interchangeable in all circumstances.
The ERO should consider Puget Sound’s
concerns on this issue when making
future modifications to the Reliability
Standards.
6. MOD–030–2, Flowgate Methodology
247. In the NOPR, the Commission
proposed to approve MOD–030–2
without modification. Because MOD–
030–2 wholly superseded MOD–030–1,
NERC proposed to make the Reliability
Standard effective on the same date
upon which MOD–030–1 would have
become effective. Thus, the Commission
proposed to approve MOD–030–2 with
an effective date set as the first day of
the first quarter no sooner than one
calendar year after approval of the
Reliability Standard and its related three
standards (MOD–001–1, MOD–028–1,
and MOD–29–1).
a. MOD–030–2, Requirements R2.4 and
R2.5
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NOPR Proposal
248. In the NOPR, the Commission
proposed to approve MOD–030–2,
including sub-requirements R2.4 and
R2.5. Sub-requirement R2.4 provides
that the transmission operator shall, at
a minimum, establish the total flowgate
capability of each of the defined
flowgates as equal to: (1) For thermal
limits, the system operating limit, of the
flowgate; and (2) for voltage or stability
limits, the flow that will respect the
system operating limit of the flowgate.
Sub-requirement R2.5 provides that the
transmission operator shall, at a
minimum, establish the total flowgate
capability once per calendar year.
Comments
249. Entergy states that it interprets
sub-requirements R2.4 and R2.5 as
requiring an annual reevaluation to
confirm the total flowgate capability of
a defined flowgate is correctly set at the
system operating limit of the flowgate
based on thermal limits or the
appropriate flow that will respect the
system operating limit of the flowgate
based on voltage or stability limits.
Entergy contends that, when considered
with sub-requirement R2.4, subrequirement R2.5 could create
confusions as to whether, as part of the
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annual ‘‘re-establishment’’ of the total
flowgate capability, the transmission
operators must first re-establish the
system operating limit of each defined
flowgate. Entergy states that the studies
and tests that must be performed to
establish the system operating limit of a
set of transmission facilities typically
require significant time and resources,
and it is unlikely that they could be
completed for all flowgates within one
year. Accordingly, Entergy requests
clarification that, as part of the annual
establishment of the total flowgate
capability of a flowgate, the
transmission operator is not required to
re-rate transmission facilities on an
annual basis.
Commission Determination
250. The Commission finds that,
under sub-requirements R2.4 and R2.5,
transmission operators are not required
to update system operating limits of
each flowgate when establishing the
annual total flowgate capability.
However, as per sub-requirement R2.5.1,
the transmission operator should update
the total flowgate capability within
seven calendar days of the notification
if it is notified of a change in the rating
by the transmission owner that would
affect the total flowgate capability of a
flowgate used in the available flowgate
capability process.
b. MOD–030–2, Requirements R3 and
R10
NOPR Proposal
251. The Commission proposed, in
the NOPR, to approve MOD–030–2
including Requirements R3 and R10.
Requirement R3 requires the
transmission operator to make available
to the transmission service provider a
transmission model to determine
available flowgate capability that meets
the criteria provided in the subrequirements. Requirement R10, and its
sub-requirements, provides that each
transmission service provider shall
recalculate available flowgate capability,
utilizing the updated models described
in sub-requirements R3.2, R3.3 and
Requirement R5, at a minimum on the
following frequency unless none of the
calculated values identified in the
available flowgate capability equation
have changed: For hourly availability
flowgate capability, once per hour; for
daily availability flowgate capability,
once per day; and for monthly
availability flowgate capability, once per
week. Sub-requirements R3.2 and R3.3
require that the transmission operator
make available to the transmission
service provider a transmission model
for determination of availability
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64917
flowgate capability that is: Updated at
least once per day for availability
flowgate capability for intra-day, next
day, and days two through thirty; and
updated at least once per month for
availability flowgate capability
calculations for months two through
thirteen. Requirement R5 addresses
further requirements for data included
in the models.
Comment
252. Entergy states that it understands
sub-requirements R3.2 and R3.3 as
establishing a requirement that the
transmission model used by the
transmission service provider must be
updated, or resolved, with a frequency
of once a day and/or once per month,
according to the applicable availability
flowgate capability calculation. On the
other hand, Entergy notes, Requirement
R10 establishes requirements that the
transmission service provider
recalculates availability flowgate
capability by algebraically decrementing
or incrementing availability flowgate
capability values as appropriate, using
the most recently updated transmission
model on a more frequent basis. Entergy
requests clarification that the
transmission model used in the
available flowgate capability
calculations does not need to be
updated more frequently than under the
timelines set forth in sub-requirements
R3.2 and R3.3, i.e., that the transmission
model itself does not need to be updated
according to the timelines in
Requirement R10, which would only
apply to the recalculation of availability
flowgate capability values.
Commission Determination
253. The Commission finds that subrequirements R3.2 and R3.3 set the
frequency by which the transmission
model used in the available flowgate
capability calculations needs to be
updated. Transmission operators are not
required to update the transmission
model more frequently than prescribed
in these sub-requirements. Under
requirement R10, transmission service
providers must use the transmission
models provided by transmission
operators to recalculate available
flowgate capability on a more frequent
basis, i.e., hourly, once per hour; daily,
once per day; and, monthly, once per
week. A transmission service provider’s
obligations under Requirement R10
should not require transmission
operators to update transmission models
any more frequently than required in
sub-requirements R3.2 and R3.3.
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c. MOD–030–2, Existing Transmission
Commitments, Requirement R6
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NOPR Proposal
254. In the NOPR, the Commission
proposed to approve MOD–030–2,
including Requirement R6, which sets
variables to use in calculating the
impact of existing transmission
commitments for firm commitments.
These variables include: The impact of
all firm network integration
transmission service including native
load and network service load, the
impact of all confirmed firm point-topoint transmission service expected to
be scheduled including roll-over rights,
the impact of any grandfathered firm
obligation expected to be scheduled, the
impact of other firm services
determined by the transmission service
provider. Requirement R7 requires the
transmission service provider to
consider similar variables when
calculating the impact of existing
transmission commitments for non-firm
commitments.
Comments
255. Cottonwood states that, during
the stakeholder process, it informed
NERC that the existing transmission
commitment calculation procedures in
Requirement R6 were insufficiently
detailed, and particularly failed to
ensure that transmission service
providers do not overstate the capacity
set aside for existing transmission
commitment purposes. Although NERC
responded that the responsible
Reliability Standard drafting team has
required the use of dispatch modeling
information to determine these impacts,
Cottonwood states NERC also clarified
that the processes used to calculate
existing transmission commitments
should be included in the available
transfer capability implementation
documents. Cottonwood expresses
concern that the NERC standards
drafting team did not adequately
address its concerns.
256. Cottonwood contends that
overstatement of existing transmission
commitments is a serious problem for
transmission customers because it
understates the available transfer
capability/available flowgate capability
identified in the models, even though
the system could actually carry
additional service. Cottonwood further
contends that overstatement of existing
transmission commitments also can lead
to the appearance of phantom
congestion and base case overloads in
the models, which effectively means
that the existing transmission
commitment impacts on certain
flowgates is greater than the flowgates’
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capacity, and, thus, these flowgates are
overloaded in the available transfer
capability power flow models, and
access to the transmission system is
reduced. To address these concerns,
Cottonwood asks the Commission to
direct the ERO to modify MOD–030–2 to
include requirements that ensure that
the generation dispatch model
incorporates the way generating units
actually are dispatched in daily
operation, and any and all operating
procedures used to maintain flows
within limits. Cottonwood further
suggests that impacts from neighboring
systems should be taken into account
and properly modeled.
257. Entegra contends that NERC’s
proposal does not comply with the
Commission’s directives in Order Nos.
693 and 890. Entegra states that the
proposed existing transmission
commitments calculation is loose and
unclear and the proposed requirements
do not prevent transmission service
providers from overstating the flowgate
capacity set aside for existing
transmission purposes, which leads to
base case contingency overloads.
Accordingly, Entegra asks the
Commission to direct the ERO to modify
the Reliability Standard to require
transmission providers to use an
accurate and realistic dispatch model
and to benchmark existing transmission
commitment calculations against realtime flows to ensure that these values
are not being overstated. In addition,
Entegra contends that transmission
service providers should be required to
identify and report to NERC, on a
periodic basis, all base case congestion
overloads over five percent and chronic
base case congestion overloads for
further investigation and action.
Commission Determination
258. In Order No. 890, the
Commission determined that existing
transmission commitments 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; (4) rollover
rights associated with long-term firm
service; and (5) other uses identified
through the NERC process.119 Further,
the Commission decided that existing
transmission commitments should not
be used to set aside transfer capability
for any type of planning or contingency
reserve, which are instead addressed
through capacity benefit margin and
transfer reliability margin
119 Order No. 890, FERC Stats. & Regs. ¶ 31,241
at P 244.
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calculations.120 We find that, as written,
the ERO’s definition of existing
transmission capacity satisfies the
Commission’s directions in Order No.
890.
259. Under Requirements R6 and R7
of MOD–030–2, a transmission provider
must sum the impact of certain defined
transmission commitments as well as
other firm and non-firm services
determined by the TSP. Relevant impact
is undefined as are ‘‘other’’ firm and
non-firm services. Thus, there is
potential for a transmission service
provider to overstate or understate
existing transmission commitments.
However, this concern is mitigated by
fact that, under MOD–001–1
Requirement R2, transmission service
providers must recalculate available
transfer capability or available flowgate
capability (which include existing
transmission commitments) for specific
time periods. Entities are also required
to make their assumptions available. In
addition, in measures M13 and M14 of
MOD–030–2, NERC states that a
recalculated existing transmission
commitment value that is within 15
percent or 15 MW, whichever is greater,
of the originally calculated values, is
evidence that the transmission service
provider used the requirements defined
in R6 and R7. We therefore decline to
direct the modifications proposed.
d. MOD–030–2, Power Transfer and
Outage Transfer Distribution Factors
NOPR Proposal
260. Requirement R2 of MOD–030–2
provides that, in determining which
flowgates to use in the available
flowgate capability process the
transmission operator must use, at a
minimum, certain criteria as
enumerated in the sub-requirements.
Requirement R2.1.1 requires
transmission operators to consider the
results of a first contingency transfer
analysis from all adjacent balancing
authority source and sink combinations
up to the path capability such that at a
minimum the first three limiting
elements and their worst associated
contingency combinations with an
outage transfer distribution factor of at
least 5 percent and within the
transmission operator’s system are
included in the flowgates unless the
interface between such adjacent
balancing authorities is accounted for
using another available transfer
capability. Requirement R2.1.4 requires
transmission operators to consider any
limiting element or contingency where
the coordination of the limiting
120 Id.
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element/contingency combination is not
addressed through a different
methodology, and, among other things,
any generator within the transmission
service provider’s area has at least a 5
percent power distribution factor or
outage transfer distribution factor
impact on the flowgate when delivered
to the aggregate load of its own area.
srobinson on DSKHWCL6B1PROD with RULES2
Comments
261. Entegra states that NERC’s
proposal gives transmission operators
the discretion to use arbitrarily small
distribution factors, without requiring
any justification or explanation as to
why the chosen value is appropriate.
Entegra also states that the use of lower
distribution factors may affect reliability
insofar as it conflicts with other
Reliability Standards, e.g., the
transmission loading relief procedure,
that uses a five percent distribution
factor. Accordingly, Entegra asks the
Commission to direct the ERO to modify
the Reliability Standard to set a five
percent default value for both the power
transfer and outage transfer distribution
factors. Entegra states that the revised
Reliability Standard should require
transmission operators to justify their
choice of distribution factors if less than
five percent. In addition, Entegra states
that NERC should require transmission
operators using a lower value to develop
appropriate procedures to address any
conflicts between the distribution factor
values chosen for available transfer
capability purposes and those used for
other purposes, such as the transmission
loading relief procedure.
Commission Determination
262. In the NOPR, the Commission
stated that it is appropriate for
transmission service providers to retain
some level of discretion in the
calculation of available transfer
capability or available flowgate
capability. Requiring absolute
uniformity in criteria and assumptions
across all transmission service providers
would preclude transmission service
providers from calculating available
transfer capability or available flowgate
capability in a way that accommodates
the operation of their particular systems.
Similarly, the Commission believes that
it is appropriate for transmission
operators to retain some discretion.
Accordingly, the Commission will not
direct the ERO to set a specific default
value for both the power transfer and
outage transfer distribution factors.
Moreover, transmission service
providers are required to include in
their available flowgate capability
implementation documents the criteria
used by the transmission operator to
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identify sets of transmission facilities as
flowgates that are to be considered in
the available flowgate capability
calculations. Thus, we are satisfied by
the transparency achieved in the
Reliability Standard as written.
e. MOD–030–2, Treatment of Adjacent
Systems
NOPR Proposal
263. In the NOPR, the Commission
proposed to approve MOD–030–2
including sub-requirements R3.5, R5.2
and R5.3. Sub-requirement R3.5 requires
transmission operators to make
available to the transmission service
provider a transmission model to
determine available flowgate capability
that meets and contains modeling data
and system topology (or equivalent
representation) for immediately adjacent
and beyond reliability coordination
areas. When calculation available
flowgate capabilities, sub-requirement
R5.2 requires transmission service
providers to include in the transmission
model expected generation and
transmission outages, additions, and
retirements within the scope of the
model as specified in the
implementation document and in effect
during the applicable period of the
calculation for the transmission service
provider’s area, all adjacent
transmission service providers, and any
transmission service providers with
which coordination agreements have
been executed. In addition, under subrequirement R5.3, transmission service
providers must, for external flowgates,
use the available flowgate capability
provided by the transmission service
provider that calculates available
flowgate capability for that flowgate.
Comments
264. Entegra states that the proposed
requirements for MOD–030–2,
specifically sub-requirements R3.5,
R5.2, and R5.3, do not require a
transmission service provider to
represent adjacent systems in a realistic
manner or to update its representations
of adjacent systems at the same
frequency as the transmission service
provider’s models of its own system.
Entegra states that the requirements also
do not have a measure to assess the
validity of a transmission service
provider’s representation of adjacent
systems. Accordingly, Entegra asks the
Commission to direct the ERO to modify
MOD–030–2 to require transmission
service providers to exchange all model
data (e.g., load, generation profile, net
interchange, transactions, outages, and
discrete transmission and generation
elements) necessary to provide an
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64919
accurate representation of adjacent
systems and that transmission service
providers update the model data with
the same frequency that the
transmission service provider updates
models of its own system. Entegra also
suggests that the revised Reliability
Standard should require transmission
service providers to benchmark and
update their representations of adjacent
systems on an on-going basis.
Commission Determination
265. All modeling data used by a
transmission service provider to
represent conditions of adjacent systems
should reflect actual system operations
and the models developed should be
based on sound engineering principles.
The Commission finds that the
exchange of data provided under these
Reliability Standards should provide
transmission service providers with
sufficient data to make realistic
estimations of available flowgate
capability on adjacent systems. Under
Requirement R9 of MOD–001–1, a
transmission service provider must
respond to requests for data even when
they are made more frequently than the
transmission service provider updates
its available transfer or flowgate
capability models. Thus, transmission
service providers should have access to
the most current data available for
adjacent systems. In light of these
existing requirements, we deny
Entegra’s request to direct the ERO to
modify the standard to require
transmission service providers to update
their representations of adjacent systems
on an on-going basis.
266. Pursuant to the modifications to
MOD–001–1 directed above,
transmission service providers will be
required to benchmark and update their
available transfer or flowgate capability
calculations. This benchmarked data
should provide a sufficient basis to
determine whether transmission service
providers are modeling adjacent systems
in a realistic manner. The Commission
will address concerns of unrealistic
modeling of adjacent systems on a caseby-case basis if, for example, the matter
is raised in a complaint before the
Commission. Thus, the Commission
declines to direct the modification
proposed here.
f. MOD–030–2, Effective Date
Comment
267. Entergy supports NERC’s
implementation plan with respect to
MOD–030–2, which would require
compliance one calendar year after
approval of MOD–030–2 and its related
three standards (MOD–001–1, MOD–
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028–1, and MOD–029–1) by all
appropriate regulatory authorities.
Because MOD–030–2 requires
information from neighboring reliability
entities for use in the development of its
available transfer capability and
available flowgate capability values and
some of that information may not be
available until MOD–028–1 and MOD–
29–1 become effective, Entergy agrees
with NERC that it is essential that all
three methodologies and MOD–001–1
become effective at the same time.
268. Entergy also asks clarification
regarding the stated effective date.
Entergy contends that defining the
effective date of MOD–030–2 with
reference to a detail in an earlier version
of the Reliability Standard that is
proposed to be superseded creates a lack
of clarity. Accordingly, Entergy
recommends that NERC revise MOD–
030–2 to incorporate the same effective
date language used in MOD–001–1,
MOD–028–1, and MOD–029–1.
Commission Determination
269. As noted above, the Commission
approves the proposal to make these
Reliability Standards effective on the
first day of the first calendar quarter that
is twelve months beyond the date that
the Reliability Standards are approved
by all applicable regulatory authorities.
Although MOD–030–2 defines its
effective date with reference to the
effective date of MOD–030–1, the
Commission finds that this direction is
sufficiently clear in the context of the
current proceeding. To the extent
necessary, we clarify MOD–030–2 shall
become effective on the first day of the
first calendar quarter that is twelve
months beyond the date that the
Reliability Standards are approved by
all applicable regulatory authorities.
The Commission also directs the ERO to
make explicit such detail in any future
version of this or any other Reliability
Standard.
srobinson on DSKHWCL6B1PROD with RULES2
C. Violation Risk Factors and Violation
Severity Levels
NOPR Proposal
270. The Commission proposed to
accept NERC’s commitment to file
violation severity levels and violation
risk factors at a later time. The
Commission noted that the Violation
Severity Level Order was issued after
NERC developed the violation severity
level assignments for the Reliability
Standards at issue in this proceeding.121
The Commission acknowledged that, as
121 NOPR,
FERC Stats. & Regs. ¶ 32,641 at P 123,
citing North American Electric Reliability Corp.,
123 FERC ¶ 61,284, at P 20–35 (2008) (Violation
Severity Level Order).
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a result, NERC was unable to evaluate
and modify the proposed violation
severity levels to comply with the
Commission’s guidelines prior to filing
the proposed Reliability Standards. The
Commission therefore proposed to
direct the ERO to reevaluate the
violation severity levels associated with
all of the proposed Reliability Standards
based on the Commission’s guidelines
outlined in the Violation Severity Level
Order and prepare appropriate
revisions. In addition, the Commission
proposed to accept NERC’s proposal to
allow NERC staff to review the violation
risk factors through an open stakeholder
process to ensure that they are
consistent with the intent of the
violation risk factor definition and
guidance provided in the Violation Risk
Factor Order and the Violation Risk
Factor Rehearing Order.122 The
Commission proposed to direct NERC to
file revised violation severity levels and
violation risk factors no later than 120
days before the Reliability Standards
become effective.
Comments
271. Puget Sound states that it
supports the Commission’s proposal
that NERC not file violation risk factors
and violation severity levels at this time.
Puget Sound also states that it supports
the Commission’s proposal to allow
NERC staff time to review the violation
risk factors through an open stakeholder
process to ensure that they are
consistent with Commission precedent.
Puget Sound also contends that no
requirement of the proposed MOD
Reliability Standards should be assigned
a violation risk factor exceeding
‘‘Lower’’ because the potential
violations of these standards would not
directly affect the electrical state or the
capability of the Bulk-Power System, or
the ability to effectively monitor and
control the Bulk-Power System.123 For
the same reason, Puget Sound also
contends that the MOD Reliability
Standards should not be assigned
violation severity levels greater than
‘‘Lower.’’
272. The Joint Municipals also argue
that the Commission should direct
NERC to assign low violation risk
factors to the Reliability Standards
approved here. The Joint Municipals
point out, as the Commission did in the
NOPR, that the NERC Reliability
Standards drafting team adjusted the
violation risk factors to ‘‘lower’’ from
‘‘medium,’’ in view of what appears to
122 North American Electric Reliability Corp., 119
FERC ¶ 61,145, at P 9 (Violation Risk Factor Order),
order on reh’g, 120 FERC ¶ 61,145 (2007).
123 Citing Violation Risk Factor Order, 119 FERC
¶ 61,145 at P 9.
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be the consensus that the available
transfer capability-related Reliability
Standards are not critical to system
reliability.
273. By contrast, Midwest ISO
contends that the original set of
violation risk factors assigned by the
Reliability Standard drafting team and
submitted to industry vote are valid.
Midwest ISO states that the violation
risk factors already have been through
an open stakeholder process in which
the proposed Reliability Standards were
commented on and voted upon multiple
times. Further, Midwest ISO contends
that continued delay in filing the
violation risk factors contravenes
NERC’s earlier commitment to file in a
timely manner.
Commission Determination
274. The Commission adopts the
NOPR proposal and directs the ERO to
reevaluate the violation risk factors and
violation severity levels associated with
all of the proposed MOD Reliability
Standards based on the Commission’s
precedent and to prepare appropriate
revisions. The Commission notes that in
Order No. 722, the Commission
encouraged the ERO to develop a new
and comprehensive approach that
would better facilitate the assignment of
violation severity levels and violation
risk factors both prospectively and to
approved Reliability Standards.124
NERC responded by making an
informational filing proposing a new
method for assigning violation risk
factors and violation severity levels.
Although the Commission reserves
judgment of the merits of the ERO’s
proposals presented in the
informational filing, the Commission
accepts the ERO’s commitment to
reevaluate the violation risk factors and
violation severity levels associated with
these MOD Reliability Standards
through an open stakeholder process to
ensure that they are consistent with the
intent of violation risk factor definitions
and Commission precedent. The
Commission hereby directs the ERO to
file revised violation severity levels and
violation risk factors no later than 120
days before the Reliability Standards
become effective. In light of this
reevaluation of the violation severity
levels and violation risk factors, we find
the arguments raised by Puget Sound
and the Joint Municipals to be
premature.
124 Version Two Facilities Design, Connections
and Maintenance Reliability Standards, Order No.
722, 126 FERC ¶ 61,255, at P 45 (2009).
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D. Disposition of Other Reliability
Standards
1. MOD–010–1 through MOD–025–1
NOPR Proposal
275. In the NOPR, the Commission
proposed to allow NERC to address
revisions to MOD–010 through MOD–
025 to incorporate a requirement for
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. These Reliability
Standards are generally intended to
establish consistent data requirements,
reporting procedures and system models
for use in reliability analysis. As such,
the Commission proposed to find that
NERC is correct that these Reliability
Standards were not a part of the
available transfer capability
modifications required in Order Nos.
890 and 693.
Commission Determination
276. The Commission hereby adopts
its NOPR proposal and will allow NERC
to address revisions to MOD–010
through MOD–025 through a separate
project. In Order No. 693, the
Commission identified nine Reliability
Standards as the core of the available
transfer capability initiative directed in
Order No. 890.125 None of the
Reliability Standards MOD–010 through
MOD–025 were identified as part of that
initiative.
2. Reliability Standards To Be Retired or
Withdrawn
srobinson on DSKHWCL6B1PROD with RULES2
NOPR Proposal
277. In the NOPR, the Commission
proposed to approve NERC’s request to
retire MOD–006–0 and MOD–007–0 and
to withdraw its request for approval of
MOD–001–0, MOD–002–0, MOD–003–
0, MOD–004–0, MOD–005–0, MOD–
008–0, and MOD–009–0. The
Commission also proposed to find that
MOD–001–0, MOD–002–0, MOD–003–
0, MOD–004–0, MOD–005–0, MOD–
008–0, and MOD–009–0 are all
superseded by the available transfer
capability calculations required by the
proposed MOD Reliability Standards in
this proceeding are, upon the
effectiveness of the proposed MOD
Reliability Standards, no longer
necessary.
278. The Commission also proposed
to not grant NERC’s request to withdraw
FAC–012–1, nor approve the retirement
125 Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 206.
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of FAC–013–1.126 With respect to these
two Reliability Standards, the
Commission disagreed with NERC that
they are wholly superseded by the MOD
Reliability Standards addressed in these
proceeding. The Commission noted that,
under FAC–012–1, reliability
coordinators and planning authorities
would be required to document the
methodology used to establish interregional and intra-regional transfer
capabilities and to state whether the
methodology is applicable to the
planning horizon or the operating
horizon. The Commission also noted
that, under FAC–013–1, reliability
coordinators and planning authorities
are required to establish a set of interregional and intra-regional transfer
capabilities that are consistent with the
methodology documented under FAC–
012–1, which could require the
calculation of transfer capabilities for
both the planning horizon and the
operating horizon. The Commission
posited that these FAC Reliability
Standards were necessary because the
proposed MOD Reliability Standards
provide only for the calculation of
available transfer capability and its
components, including total transfer
capability, in the operating horizon.127
Thus, the Commission stated, the
proposed MOD Reliability Standards do
not govern the calculation of transfer
capabilities in the planning horizon, i.e.,
beyond 13 months in the future.
279. In Order No. 693, the
Commission approved FAC–013–1, but
declined to approve or remand
FAC–012–1. The Commission expressed
concern that FAC–012–1 merely
required the documentation of a transfer
capability methodology without
providing a framework for that
methodology including data inputs and
modeling assumptions.128 The
Commission also expressed concern that
the criteria used to calculate transfer
capabilities for use in determining
available transfer capability must be
identical to those used in planning and
operating the system.129 The
Commission directed the ERO to modify
FAC–012–1 to provide a framework for
the transfer capability calculation
methodology that takes account of the
need for consistency in the criteria used
to calculate transfer capabilities.130
126 NOPR,
FERC Stats. & Regs. ¶ 32,641 at P 138.
MOD–001–1, Requirement R2.3.
128 Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 777.
129 Id. P 782.
130 Id. P 779, 782.
127 See
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64921
Comments
280. NERC does not object to the
Commission proposal to retain
FAC–012–1 and FAC–013–1 but asks
the Commission for additional time to
make the appropriate revisions. Instead
of directing NERC to file the proposed
modifications within 120 days prior to
the effective date of the available
transfer capability-related MOD
Reliability Standards, NERC proposes
that the Commission instead require
that these changes be filed 60 days
before the Reliability Standards become
effective. NERC states that this will
provide it with additional time to
develop these changes in accordance
with the Reliability Standards
development process, and minimize the
probability that special exceptions to
the process be granted in order to meet
the Commission’s proposed deadline. In
addition, NERC states that this delay
will help ensure that these changes do
not take undue precedence ahead of
other issues currently prioritizes and
being addressed in the NERC standards
development work plan.
281. EEI, Duke, First Energy, FPL and
Puget Sound object to the Commission’s
proposal to retain
FAC–012–1 and FAC–013–1. EEI states
that although the NOPR defined the
operating horizon to include the next
twelve months (i.e., months 2–13),
Order No. 890 defined the operating
horizon as ‘‘day-ahead and preschedule’’ and the planning horizon as
‘‘beyond the operating horizon.’’131
Thus, EEI argues that the proposed
MOD Reliability Standards provide for
the calculation of available transfer
capability during part of the planning of
horizon even though they do not
address the calculation of available
transfer capability beyond month 13.
282. EEI further contends that there is
no reliability concern created by retiring
FAC–012–1 and FAC–013–1 just as
there are no reliability benefits obtained
by complying with them. EEI contends
that this is particularly true in the
Eastern Interconnection where the
Eastern Interconnection Reliability
Assessment Group exists as a forum for
organizing reliability-related modeling
and planning activities by defining
various studies and cases, as well as
common assumptions, for the long-term
planning horizon. Thus, EEI contends,
the Commission should not view the
retiring of FAC–012–1 and FAC–013–1
as creating a vacuum; rather, the
proposed MOD Reliability Standards
have ‘‘wholly superseded’’ them by
replacing their only useful components.
131 Citing Order No. 890, FERC Stats. & Regs.
¶ 31,241 at P 323 and Attachment C.
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In the alternative, if the Commission
decides to retain FAC–012–1, EEI
suggests that the Commission direct
NERC to consider moving the
substantive content of FAC–012–1 into
a technical guidance document and
have the document appended to an
approved FAC Reliability Standard.
283. Duke states that it supports
NERC’s proposal to retire FAC–013–1
when the MOD Reliability Standards
become effective and to withdraw its
request for approval of FAC–012–1.
Duke states that it does not believe that
available transfer capability calculations
made past a 13 month period are
sufficient to support reliable long-term
transmission service and so supports
EEI’s comments related to calculations
made past month 13. Duke also
contends that, in the Eastern
Interconnect region, regional
assessments and planning are occurring
for transfer capabilities in the planning
horizon (i.e., period of time after 13
months) in various forums such as
Southeastern Electric Reliability
Council’s long-term study group and the
Eastern Interconnection Reliability
Assessment Group. Duke states that
other efforts exist in response to Order
No. 890’s regional planning
requirements such as the Southeast
Inter-Regional Participation Process and
the North Carolina Transmission
Planning Collaborative. Duke contends
that these and other regional planning
efforts will effectively ensure that levels
of transfer capability are maintained to
meet regional and interconnection wide
reliability requirements in the planning
horizon.
284. If the Commission adopts
FAC–012–1 and retains FAC–013–1,
then Duke requests that the Commission
require FAC–012–1 to be revised to
focus on the development of a
methodology for calculation interregional and intra-regional transfer
capabilities for use in assessing the
ability of the Bulk-Power System to
support potentially large, diverse
regional transfers of power in a reliable
manner, rather than calculation of total
transfer capabilities or available transfer
capabilities for evaluation of service
requests. Duke contends that there is no
Commission requirement for the posting
of total transfer capabilities and/or
available transfer capabilities beyond 13
months. Further, if the Commission
approves FAC–012–1, Duke requests
that it be made applicable to just the
planning coordinator, and not the
reliability coordinator, since the
Reliability Standard would focus on the
planning timeframe. Similarly, Duke
recommends that the Commission direct
the ERO to modify FAC–013–1 to
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establish and communicate the transfer
capabilities developed using the
methodology specified in FAC–012–1.
285. FirstEnergy agrees that the
MOD–001–1 addresses the scheduling,
operating and planning horizons, as
those terms were described in Order No.
693.132 However, if the Commission
chooses to direct the ERO to retain
FAC–012–1 and FAC–013–1,
FirstEnergy asks the Commission to
limit the FAC standards to the use of
transmission capability for transmission
planning and remove redundant
provisions for the calculation of transfer
capability addressed elsewhere in the
MOD Reliability Standards, especially
for other purposes such as the
calculation of available transfer
capability. FirstEnergy states that the
FAC and the MOD Reliability Standards
each address the calculation of transfer
capability in the operational timeperiod. To eliminate this redundancy,
FirstEnergy suggests that the
Commission direct the ERO to assign
the treatment of operational transfer
capability to the MOD Reliability
Standards and eliminate the reference to
the use of transfer capability in the
operational horizon in the operational
standards. FirstEnergy further contends
that the FAC Reliability Standards are
ambiguous since they require the
calculation of a parameter, transfer
capability in the planning horizon, for
which the purpose is not described or
specified. Nevertheless, FirstEnergy
states that it strongly supports the
standard drafting team’s conclusion that
the best method for addressing total
transfer capability accurately and
clearly is within the MOD Reliability
Standards.
286. FPL contends that the
elimination of FAC–012–1 and FAC–
013–1 would not create a void. FPL
states that the total transfer capability
and available transfer capability in the
long-term planning horizon are not tied
to a specific path for posting purposes,
but instead look at the transmission
network limits for which expansion
projects would be initiated to meet the
long-term needs for firm transmission
service. Although the MOD Reliability
Standards do not require the posting of
transfer capabilities beyond 13 months,
FPL states that this is only a minimum
requirement that reflects the impractical
nature of pre-determined transfer
capability calculations for the planning
horizon after the 13th month. FPL
contends that the study of transmission
service requests beyond the 13th month
of the planning horizon requires specific
knowledge and assumptions, and such
requests could not be granted based on
pre-determined calculations alone. For
these reasons FPL agrees with NERC’s
recommendation to withdraw
Reliability Standard FAC–012–1 and
retire FAC–013–1.
287. Pacific Northwest contends that
MOD–003–0 should not be retired or
withdrawn. Pacific Northwest states that
MOD–030–2 requires regional reliability
organizations to develop and document
procedures that allow transmission
service customers to inquire about
calculations of total transfer capability
and available transfer capability,
timeframes for response and posting
requirements applicable to the regional
reliability organization. Pacific
Northwest contends that this procedure
fills gaps in the current NAESB business
practice in that the procedure facilitates
the provision of information about
available transfer capability and total
transfer capability calculations for
transmission paths with multiple
owners but with one available transfer
capability rating and one seasonal
operating transfer capability rating.
132 Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 1047.
133 Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 782.
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Commission Determination
288. The Commission hereby adopts
the NOPR proposal and approves
NERC’s request to retire MOD–006–0
and MOD–007–0 and to withdraw its
request for approval of MOD–001–0,
MOD–002–0, MOD–003–0, MOD–004–
0, MOD–005–0, MOD–008–0, and
MOD–009–0. The Commission also
finds that MOD–001–0, MOD–002–0,
MOD–003–0, MOD–004–0, MOD–005–
0, MOD–008–0, and MOD–009–0 are all
superseded by the available transfer
capability calculations required by the
proposed MOD Reliability Standards in
this proceeding are, upon the
effectiveness of the proposed MOD
Reliability Standards, no longer
necessary.
289. Consistent with its NOPR
proposal, the Commission finds that
NERC has not addressed the
requirements of Order No. 693 with
regard to the calculation of transfer
capabilities in the planning horizon. In
Order No. 693 the Commission
expressed concern that the criteria used
to calculate transfer capabilities for use
in determining available transfer
capability must be identical to those
used in planning and operating the
system.133 As EEI observes, in Order No.
890, the Commission offered, as an
example, a possible definition of the
operating horizon as the day-ahead and
pre-scheduling periods and the
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planning horizon as anything beyond
the operating horizon.134 However,
NERC has already defined the near-term
planning horizon as years one through
five in sub-requirement R1.2 of TPL–
005. The Commission believes that this
definition should be consistent
throughout the Reliability Standards.
290. The Commission recognizes that
the calculation of transfer capabilities in
the planning horizon (years one through
five) may not be so accurate to support
long-term scheduling of the
transmission system but we do believe
that such forecasts will be useful for
long-term planning, in general, by
measuring sufficient long-term capacity
needed to ensure the reliable operation
of the Bulk-Power System. Although
regional planning authorities have
developed similar efforts in response to
Order No. 890, we believe that the
requirements imposed by FAC–012 and
FAC–013 need not be duplicative of
those existing efforts and, by contrast,
should be focused on improving the
long-term reliability of the Bulk-Power
System pursuant to the ERO’s
Reliability Standards. We believe that
these responsibilities would be
appropriately assigned to the planning
coordinator and not the reliability
coordinator.
291. The Commission hereby adopts
its NOPR proposal to deny NERC’s
request to withdraw FAC–012–1 and
retire FAC–013–1. Instead, pursuant to
section 215(d)(5) of the FPA and section
39.5(f) of our regulations, the
Commission directs the ERO to develop
modifications to FAC–012–1 and FAC–
013–1 to comply with the relevant
directives of Order No. 693 135 and, as
otherwise necessary, to make the
requirements of those Reliability
Standards consistent with those of the
MOD Reliability Standards approved
herein as well as this Final Rule. These
modifications should also remove
redundant provisions for the calculation
of transfer capability addressed
elsewhere in the MOD Reliability
Standards. In making these revisions,
the ERO should consider the
development of a methodology for
calculation of inter-regional and intraregional transfer capabilities. The
Commission accepts the ERO’s request
for additional time to prepare the
modifications and so directs the ERO to
submit the modifications to FAC–012–1
and FAC–013–1 no later than 60 days
134 Order No. 890, FERC Stats. & Regs. ¶ 31,241
at P 323.
135 Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 779, 782.
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17:05 Dec 07, 2009
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before the MOD Reliability Standards
become effective.
E. Applicability
Comments
292. Supported by Austin, ERCOT
requests that the Commission act to
ensure the proposed Reliability
Standards are not applied to the ERCOT
region. ERCOT contends that the
proposed Reliability Standards have no
value in the ERCOT region because
ERCOT does not have a transmission
market and it manages congestion by
employing a security constrained
economic dispatch. ERCOT further
contends that the proposed MOD
Reliability Standards are actually
counter-productive to the efficient
operation of the ERCOT grid and
markets. ERCOT states that there are
two primary concerns associated with
available transfer capability,
underutilization and oversubscription of
the grid. ERCOT contends that these
concerns only apply in regions that have
transmission markets, and primarily
physical markets, where the available
transfer capability calculation can
actually be performed because there are
transmission obligations that can be
netted against total transfer capability.
ERCOT further contends that neither
concern arises in the ERCOT region
because there is no transmission market.
293. Similarly, ERCOT contends that
capacity benefit margin has no
relevance in ERCOT because there is no
transmission market and all energy
schedules are respected inside ERCOT
without the need for transmission
reservations. ERCOT further argues that
requiring ERCOT to set aside
transmission capacity to meet the
proposed capacity benefit margin
obligation would actually be counterproductive because it would inhibit
efficient dispatch of the system, thereby
creating artificial congestion to respect
the reserved capacity benefit margin.
ERCOT also contends that transfer
reliability margin is irrelevant in the
ERCOT region because ERCOT manages
all operational issues through redispatch. Furthermore, because
available transfer capability is
undefined in the ERCOT region, ERCOT
argues that the Reliability Standards
establishing the calculation
methodologies are also irrelevant with
the region.
294. NYISO asks the Commission to
clarify that the MOD Reliability
Standards should be interpreted with a
reasonable degree of flexibility to
accommodate the special characteristics
of ISOs and RTOs. NYISO contends that
the MOD Reliability Standards were
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64923
written to accommodate physical
reservation transmission systems and do
not include provisions that
accommodate the special characteristics
of NYISO’s financial reservation model.
NYISO states that it has reached an
informal agreement with NERC through
which NYISO believes it could comply
with the requirements of MOD–029–1 as
written. NYISO also asks the
Commission to indicate that it will
entertain a future NYISO request for
confirmation that it is in compliance
with the NERC Reliability Standards.
NYISO further asks the Commission to
clarify that it expects NERC and the
regional entities to accommodate
financial transmission rights based open
access market designs when evaluating
the compliance of the NYISO, and to the
extent relevant, other ISOs and RTOs,
with the proposed MOD Reliability
Standards.
295. Entergy requests clarification
whether entities that use a value of zero
for transfer reliability margin and
capacity benefit margin are technically
maintaining transfer reliability margin
or capacity benefit margin and, if not,
whether MOD–004–1 and MOD–008–1
apply to those entities. Entergy contends
that if the transfer reliability margin and
capacity benefit margin Reliability
Standards do apply to entities that
maintain a value of zero, the Reliability
Standards should only require that the
transmission reserve margin and
capacity benefit margin implementation
documents state that no capacity benefit
margin or transfer reliability margin setaside exists. In addition, Entergy
requests clarification whether MOD–
008–1 applies to entities that only use
transfer reliability margin in system
impact studies when evaluating longterm firm transmission service requests
and whether such entities would be
required to maintain a transfer
reliability margin implementation
document.
Commission Determination
296. In Order No. 693, the
Commission found that a Reliability
Standard must provide for the Reliable
Operation of the Bulk-Power System
facilities and may impose a requirement
on any user, owner or operator of such
facilities.136 The Commission went on
to say that a Reliability Standard should
be a single standard that applies across
the North American Bulk-Power System
to the maximum extent this is
achievable taking into account physical
differences in grid characteristics and
regional Reliability Standards that result
136 Order No. 693, FERC Stats. & Regs. ¶ 31,242
at P 5.
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in more stringent practices.137 A
Reliability Standard can also account for
regional variations in the organizational
and corporate structures of transmission
owners and operators, variations in
generation fuel type and ownership
patterns, and regional variations in
market design if these affect the
proposed Reliability Standard. In
addition, a Reliability Standard should
have no undue negative effect on
competition. Following these principles,
the Commission finds that the
applicability of these Reliability
Standards should take into
consideration regional differences such
as those highlighted by commenters.
297. With respect to the enforcement
of these Reliability Standards, the
Commission finds that their
requirements are sufficiently clear so
that an entity should be aware of what
it must do to comply.138 The
Commission believes that an entity is
able to comply with these Reliability
Standards even if there are physical
differences in grid characteristics or
variations in market design that create
challenges. To the extent that a
transmission provider, an ISO or RTO
has a concern regarding the enforcement
of these Reliability Standards, the
Commission believes that this is a
compliance issue best addressed on a
case-by-case basis in the context of a
compliance proceeding. For this same
reason, the Commission declines to offer
its opinion as to whether NYISO is in
compliance with the Reliability
Standards. As the ERO for North
America, NERC is uniquely qualified to
enforce its own Reliability Standards.
298. In response to Entergy’s
comment, the Commission notes that
MOD–008–1 is applicable only to
transmission operators that maintain
transmission reliability margin.
Although MOD–004–1 is not as explicit
with regard to its applicability, we
believe that its applicability is
implicitly reserved to those entities that
maintain capacity benefit margin. Thus,
it does not appear that Entergy, or any
other entity, would be in violation of
MOD–004–1 or MOD–008–1 if it does
not maintain transmission reliability
margin or capacity benefit margin.
Similarly, in response to ERCOT, we
believe that it is appropriate to exempt
entities within ERCOT from complying
with these Reliability Standards. We
agree that, due to physical differences of
ERCOT’s transmission system, the MOD
Reliability Standards approved herein
would not provide any reliability
benefit within ERCOT.
137 Id.
P 6.
id. P 254.
17:05 Dec 07, 2009
NOPR Proposal
299. NERC proposed to modify its
Glossary of Terms to add twenty
definitions that are used in the five
proposed Reliability Standards,
including the following definitions of
‘‘ATC Path’’, ‘‘Business Practices’’, and
‘‘Postback’’:
ATC Path: Any combination of Point of
Receipt (POR) and Point of Delivery (POD)
for which Available Transfer Capability
(ATC) is calculated; and any Posted Path.139
Business Practices: Those business rules
contained in the Transmission Service
Provider’s applicable tariff, rules, or
procedures; associated Regional Reliability
Organization or Regional Entity business
practices; or North American Energy
Standards Board (NAESB) Business Practices.
Postback: Positive adjustments to Available
Transfer Capability (ATC) or Available
Flowgate Capability (AFC) as defined in
Business Practices. Such Business Practices
may include processing of redirects and
unscheduled service.
300. In the NOPR, the Commission
proposed to approve the addition of
these terms to the NERC Glossary. The
Commission also proposed to direct
NERC to modify the definition of
Postback to eliminate its reference to
Business Practices, another defined
term. The Commission observed that the
definition of Business Practices includes
a reference to the ‘‘regional reliability
organization.’’ The Commission stated
that, in Order No. 693, the Commission
directed NERC to eliminate references to
regional reliability organizations as
responsible entities in the Reliability
Standards because such entities are not
users, owners or operators of the BulkPower System. Accordingly the
Commission proposed to direct NERC to
remove from the proposed definition of
Business Practices, the reference to
regional reliability organizations and
replace it with the term Regional Entity.
The Commission noted, however, that
Regional Entity is not currently defined
in the NERC Glossary. The Commission
therefore proposed to direct NERC to
develop a definition of Regional Entity
consistent with section 215(a) of the
FPA 140 and 18 CFR 39.1 (2008), to be
included in the NERC Glossary.
Comments
301. Puget Sound states that it agrees
with the Commission that the term
‘‘Postback’’ is not fully determinative
and requests that the Commission reject
the definition as redundant and
unnecessary. Puget Sound states that for
a particular point of receipt/point of
139 See
138 See
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F. Definitions
140 16
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U.S.C. 824o.
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delivery combination, the existing
transmission capacity component
includes confirmed reservations utilized
on that particular point of receipt/point
of delivery combination. Puget Sound
states that processing firm redirects or
annulments to the confirmed
reservation reduces the existing
commitment component, which in turn
increases the resultant available transfer
capability, achieving the same result as
the desired effect of the Postback term.
Puget Sound further contends that
requiring a Postback component
assumes that once a reservation is
confirmed on a particular point of
reservation/point of receipt combination
the impact of the confirmed reservation
will always be present in the available
transfer capability calculation,
regardless of future redirects,
annulments, or recalls that are
processed. Puget Sound contends that
accepting the Postback definition would
add an unnecessary component to the
available transfer capability formula,
increasing the recordkeeping and
documentation burden for applicable
entities.
302. SMUD and Salt River ask the
Commission to clarify that the proposed
definition of ‘‘ATC Path’’ does not limit
a transmission provider’s flexibility to
treat multiple parallel interconnections
between balancing authorities as a
single path. NERC proposes to define
‘‘ATC Path’’ as: ‘‘Any combination of
Point of Receipt and Point of Delivery
for which [available transfer capability]
is calculated; and any Posted Path.’’
SMUD and Salt River note that this
definition references the definition of
‘‘Posted Path’’ in the Commission’s
regulations, 18 CFR § 37.6(b)(1), which
defines ‘‘Posted Path’’ as any control
area to control area interconnection and
any path for which a customer requests
to have available transfer capability and
total transfer capability posted. They
contend that one possible way to
interpret ‘‘control area to control area
interconnection’’ would be to treat each
physical interconnection between
Balancing Authorities as creating a
separate available transfer capability
path. They argue that the Commission
should clarify the definition so as to
recognize that available transfer
capability paths may or should be
comprised of multiple, parallel
interconnections between Balancing
Authorities as reliability interests
determine.
303. SMUD and Salt River also ask the
Commission to direct the ERO to modify
the definition of ‘‘ATC Path’’ to remove
reference to the Commission’s
regulations. They argue that the
reference is inappropriate as applied to
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them because SMUD and Salt River are
not subject to the Commission’s
regulations. They also contend that
confusion could arise if the Commission
revises its definition of Posted Path and
thereby effectively modifies the
Reliability Standards.
Commission Determination
304. The Commission believes that
the definition of Postback is not fully
determinative. NERC should be able to
define this term without reference to the
Business Practices, another defined
term. Accordingly, the Commission
adopts its NOPR proposal and directs
the ERO to develop a modification to
the definition of Postback to eliminate
the reference to Business Practices.
Although we are sensitive to Puget
Sound’s concern that the required
Postback component may increase the
recordkeeping burden on some entities,
in other regions the component may be
critical. We disagree that the term’s
existence assumes that once a
reservation is confirmed on a particular
point of reservation/point of receipt
combination the impact of the
confirmed reservation will always be
present in the available transfer
capability calculation. However, we
would consider suggestions that would
allow entities to comply with the
requirements as efficiently as possible,
such as a regional difference through the
ERO’s standards development
procedure.
305. The Commission also adopts its
NOPR proposal to direct the ERO to
develop a modification to the definition
of Business Practices that would remove
the reference to regional reliability
organizations and replace it with the
term Regional Entity. We also direct the
ERO to develop a definition of the term
Regional Entity to be included in the
NERC Glossary.
306. We agree with SMUD and Salt
River that the definition of ‘‘ATC Path’’
should not limit a transmission
provider’s flexibility to treat multiple
parallel interconnections between
balancing authorities as a single path,
and that available transfer capability
paths may comprise multiple, parallel
interconnections between Balancing
Authorities when such treatment is
appropriate to maintain reliability. We
also agree that the definition should not
reference the Commission’s regulations.
The Commission’s regulations are not
applicable to all registered entities and
are subject to change. We therefore
direct the ERO to develop a
modification to the definition of ‘‘ATC
Path’’ that does not reference the
Commission’s regulations.
Number of
respondents
Data collection
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Mandatory data exchanges .............................................................................
Explanation of change of ATC values .............................................................
Recordkeeping .................................................................................................
Total Annual Hours for Collection:
Reporting + recordkeeping hours =
3,480 + 24,660 = 28,140 hours.
Cost to Comply:
Reporting = $2,811,240
24,660 hours @ $114 an hour (average
cost of attorney ($200 per hour),
consultant ($150), technical ($80),
and administrative support ($25))
Recordkeeping = $185,875 (same as
below)
Labor (file/record clerk @ $17 an
hour) 3,480 hours @ $17/hour =
$59,150
Storage 137 respondents @ 8,000 sq.
ft. × $925 (off site storage) =
$126,725
Total costs = $2,997,115
Labor $ ($2,811,240 + $59,150) +
Recordkeeping Storage Costs
($126,725)
141 44
142 5
U.S.C. 3507(d).
CFR 1320.11.
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17:05 Dec 07, 2009
IV. Information Collection Statement
307. The following collections of
information contained in this final rule
have been submitted to the Office of
Management and Budget (OMB) for
review under section 3507(d) of the
Paperwork Reduction Act of 1995.141
OMB’s regulations require OMB to
approve certain information collection
requirements imposed by agency
rule.142
308. The Commission solicited
comments on the need for and the
purpose of the information contained in
these Mandatory Reliability Standards
and the corresponding burden to
implement them. The Commission did
receive comments on specific
requirements in the Reliability
Standards and how their impact would
be burdensome. We have addressed
those concerns elsewhere in this Final
Rule. However, we did not receive
comments on our reporting burden
estimates. The Commission has updated
the burden requirements to be
consistent with our directions in this
Final Rule.
Burden Estimate: The public reporting
and records retention burdens for the
proposed reporting requirements and
the records retention requirement are as
follows.143
Number of
responses
137
137
137
309. OMB’s regulations require it to
approve certain information collection
requirements imposed by an agency
rule. The Commission is submitting
notification of this Final Rule to OMB.
If the proposed requirements are
adopted they will be mandatory
requirements.
Title: Mandatory Reliability Standards
for the Calculation of Available Transfer
Capability, Capacity Benefit Margins,
Transmission Reliability Margins, Total
Transfer Capability, and Existing
Transmission Commitments and
Mandatory Reliability Standards for the
Bulk-Power System.
Action: Final Rule.
OMB Control No.: 1902–0244.
Respondents: Business or other for
profit.
Frequency of responses: On occasion.
Necessity of the Information:
Hours per
response
1
1
1
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80
100
30
Total annual
hours
10,960
13,700
3,480
310. Internal Review: The
Commission has reviewed the approved
reliability standards and made a
determination that these requirements
are necessary to implement section 215
of the Energy Policy Act of 2005. These
requirements conform to the
Commission’s plan for efficient
information collection, communication
and management within the energy
industry. The Commission has to assure
itself, by means of internal review, that
there is specific, objective support for
the burden estimates associated with the
information requirements.
311. 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
143 These burden estimates apply only to this
Final Rule and do not reflect upon all of FERC–516
or FERC–717.
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Director, Phone: (202) 502–8415, fax:
(202) 273–0873, e-mail:
michael.miller@ferc.gov.].
312. For submitting comments
concerning the collection(s) 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 Information and
Regulatory Affairs, Washington, DC
20503 [Attention: Desk Officer for the
Federal Energy Regulatory Commission,
phone (202) 395–4650, fax: (202) 395–
7285, e-mail:
oira_submission@omb.eop.gov.].
V. Environmental Analysis
313. 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.144 The actions proposed
here fall within the categorical
exclusion in the Commission’s
regulations for rules that are clarifying,
corrective or procedural, for information
gathering, analysis, and
dissemination.145
VI. Regulatory Flexibility Act
314. The Regulatory Flexibility Act of
1980 (RFA) 146 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. The MOD Reliability Standards
apply to transmission service providers
and transmission operators.
Transmission service providers and
transmission operators are entities
responsible for the reliability of a
transmission system. They operate or
direct the operations of the transmission
facilities or control facilities used for the
transmission of electric energy in
interstate commerce. Accordingly, these
entities do not fall typically within the
definition of a small entity.147
315. Section 215(d)(2) of the FPA
provides that the Commission may
approve, by rule or order, a proposed
Reliability Standard or modification to a
proposed Reliability Standard if it meets
the statutory standard for approval,
giving due weight to the technical
expertise of the ERO. Alternatively, the
Commission may remand a Reliability
Standard pursuant to section 215(d)(4)
of the FPA. Further, the Commission
may order the ERO to submit to the
Commission a proposed Reliability
Standard or a modification to a
Reliability Standard that addresses a
specific matter if the Commission
considers such a new or modified
Reliability Standard appropriate to
‘‘carry out’’ section 215 of the FPA. The
Commission’s action in this final rule is
based on its authority pursuant to
section 215 of the FPA.
316. As indicated above,
approximately 137 entities will be
responsible for compliance with the
three new Reliability Standards. Of
these only six, or less than five percent,
have output of four million MWh or less
per year.148 The Commission does not
consider this a substantial number.
Based on this understanding, the
Commission certifies that this Final
Rule will not have a significant
economic impact on a substantial
number of small entities. Accordingly,
no regulatory flexibility analysis is
required.
VII. Document Availability
317. 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
FERC’s Home Page (https://www.ferc.gov)
and in FERC’s Public Reference Room
during normal business hours (8:30 a.m.
to 5 p.m. Eastern time) at 888 First
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Abbreviation
320. These regulations are effective
February 8, 2010. The Commission
notes that although the determinations
made in this Final Rule are effective
February 8, 2010, the MOD Reliability
Standards approved herein will not
become effective until the first day of
the first quarter no sooner than one
calendar year after approval by all
appropriate regulatory authorities where
approval is required. 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.
By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Appendix A: Commenting Party
Acronyms
American Public Power Association.
Austin, City of.
Avista Corporation.
Bonneville Power Administration.
ColumbiaGrid.
Cottonwood Energy Company.
Duke Energy Carolinas, LLC.
Edison Electric Institute.
Electric Power Supply Corporation.
Electric Reliability Council of Texas, Inc.
Entegra Power Group LLC.
144 Regulations Implementing the National
Environmental Policy Act of 1969, Order No. 486,
52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs.
¶ 30,783 (1987).
145 18 CFR 380.4(a)(5).
17:05 Dec 07, 2009
VIII. Effective Date and Congressional
Notification
Commenter name
APPA .........................................................
Austin ........................................................
Avista ........................................................
Bonneville ..................................................
ColumbiaGrid ............................................
Cottonwood ...............................................
Duke ..........................................................
EEI ............................................................
EPSA .........................................................
ERCOT ......................................................
Entegra ......................................................
VerDate Nov<24>2008
Street, NE., Room 2A, Washington, DC
20426.
318. From FERC’s Home Page on the
Internet, this information is available on
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 the
docket number excluding the last three
digits of this document in the docket
number field.
319. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from FERC
Online Support at 202–502–6652 (toll
free at 1–866–208–3676) or e-mail at
ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. E-mail the
Public Reference Room at
public.referenceroom@ferc.gov.
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146 5
U.S.C. 601–612.
definition of ‘‘small entity’’ under the
Regulatory Flexibility Act refers to the definition
provided in the Small Business Act, which defines
a ‘‘small business concern’’ as a business that is
147 The
PO 00000
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dominant in its field of operation. See 15 U.S.C. 632
(2000).
148 Id.
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64927
Abbreviation
Commenter name
Entergy ......................................................
FirstEnergy ................................................
FPL ............................................................
Georgia .....................................................
ISO/RTO Council ......................................
ITC Companies .........................................
Entergy Services Inc.
FirstEnergy Service Company.
Florida Power & Light Company.
Georgia Transmission Corporation.
ISO/RTO Council.
International Transmission Company, Michigan Electric Transmission Company, LLC, and ITC Midwest LLC.
Los Angeles Dept. of Water and Power.
Midwest ISO.
Modesto Irrigation District.
Nevada Power Company and Sierra Pacific Power
Company.
New York ISO.
North American Electric Reliability Corp.
Northwest Requirements Utilities.
Northwestern Corporation.
Pacific Northwest Generating Cooperative.
PacifiCorp.
Public Power Council.
Public Utility District No. 1 of Snohomish County.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District.
Salt River Project.
South Carolina Public Service Authority, Sacramento Municipal Utility District and MEAG Power.
Southwest Area Transmission Sub-Regional Planning Group.
Transmission Access Policy Study Group.
Transmission Agency of Northern California.
Tucson Electric Power Company.
LADWP .....................................................
MISO .........................................................
Modesto ....................................................
Nevada Companies ..................................
NYISO .......................................................
NERC ........................................................
Northwest Utilities .....................................
Northwestern .............................................
Pacific Northwest ......................................
PacifiCorp ..................................................
Public Power Council ................................
Snohomish ................................................
Puget Sound .............................................
SMUD ........................................................
Salt River ..................................................
Joint Municipals ........................................
SWAT ........................................................
TAPS .........................................................
TANC ........................................................
Tucson ......................................................
[FR Doc. E9–28620 Filed 12–7–09; 8:45 am]
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]]>Agencies
[Federal Register Volume 74, Number 234 (Tuesday, December 8, 2009)]
[Rules and Regulations]
[Pages 64884-64927]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-28620]
[[Page 64883]]
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Part III
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 40
Mandatory Reliability Standards for the Calculation of Available
Transfer Capability, Capacity Benefit Margins, Transmission Reliability
Margins, Total Transfer Capability, and Existing Transmission
Commitments and Mandatory Reliability Standards for the Bulk-Power
System; Final Rule
Federal Register / Vol. 74 , No. 234 / Tuesday, December 8, 2009 /
Rules and Regulations
[[Page 64884]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM08-19-000, et al.; Order No. 729]
Mandatory Reliability Standards for the Calculation of Available
Transfer Capability, Capacity Benefit Margins, Transmission Reliability
Margins, Total Transfer Capability, and Existing Transmission
Commitments and Mandatory Reliability Standards for the Bulk-Power
System
Issued November 24, 2009.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: Pursuant to section 215 of the Federal Power Act, the
Commission approves six Modeling, Data, and Analysis Reliability
Standards submitted to the Commission for approval by the North
American Electric Reliability Corporation, the Electric Reliability
Organization certified by the Commission. The approved Reliability
Standards require certain users, owners, and operators of the Bulk-
Power System to develop consistent methodologies for the calculation of
available transfer capability or available flowgate capability.
Pursuant to section 215(d)(5) of the FPA and Sec. 39.5(f) of our
regulations, the Commission also directs the ERO to develop certain
modifications to the MOD Reliability Standards. Finally, the Commission
directs NERC to retire the existing MOD Reliability Standards replaced
by the versions approved here.
DATES: Effective Date: This rule will become effective February 8,
2010.
FOR FURTHER INFORMATION CONTACT:
Jonathan First (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8529.
Cory Lankford (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-6711.
Christopher Young (Technical Information), Office of Electric
Reliability, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, (202) 502-6403.
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
Numbers
I. Background............................................... 5
A. Order Nos. 888 and 889............................... 5
B. Order Nos. 890 and 693............................... 9
II. MOD Reliability Standards............................... 13
A. Coordination with Business Practice Standards........ 17
B. Available Transmission System Capability, MOD-001-1.. 19
C. Capacity Benefit Margin Methodology, MOD-004-1....... 26
D. Transmission Reliability Margin Methodology, MOD-008- 41
1......................................................
E. Three Methodologies for Calculating Available 51
Transfer Capability....................................
1. Area Interchange Methodology, MOD-028-1.......... 53
2. Rated System Path Methodology, MOD-029-1......... 61
3. Flowgate Methodology, MOD-030-2.................. 65
F. Implementation Plan.................................. 72
III. Discussion............................................. 75
A. Approval, Implementation and Audit of the MOD 75
Reliability Standards..................................
1. Approval of the MOD Reliability Standards........ 83
2. Implementation Timeline.......................... 92
3. Implementation Document Audits................... 96
a. Authority to Direct Audits................... 96
b. Performance of Audits........................ 112
c. Additional Requirements to Prevent Undue 132
Discrimination.................................
B. Modification of the Reliability Standards............ 137
1. MOD-001-1........................................ 137
a. Availability of the Implementation Documents. 137
b. Dispatch Model Assumptions................... 152
c. Treatment of Network Resource Designations... 165
d. Updating Available Transfer Capability and 176
Available Flowgate Capability Values...........
e. MOD-001-1, Consistent Treatment of 180
Assumptions....................................
f. MOD-001-1, Requirement R2.................... 185
g. MOD-001-1, Requirement R3.................... 193
h. MOD-001-1, Requirements R6 and R7............ 196
i. MOD-001-1, Requirement R9.................... 202
j. MOD-001-1, Counterflows...................... 207
2. MOD-004-1, Capacity Benefit Margin............... 211
3. MOD-008-1, Transfer Reliability Margin........... 223
4. MOD-028-1, Area Interchange Methodology.......... 226
a. General...................................... 227
b. MOD-028-1, Requirement R2.................... 229
c. MOD-028-1, Requirement R5.................... 232
d. MOD-028-1, Requirement R6.................... 235
5. MOD-029-1, Rated System Path Methodology......... 238
a. Sub-Requirement R2.7......................... 238
b. Counterschedules............................. 245
6. MOD-030-2, Flowgate Methodology.................. 247
a. MOD-030-2, Requirements R2.4 and R2.5........ 248
b. MOD-030-2, Requirements R3 and R10........... 251
c. MOD-030-2, Existing Transmission Commitments, 254
Requirement R6.................................
[[Page 64885]]
d. MOD-030-2, Power Transfer and Outage Transfer 260
Distribution Factors...........................
e. MOD-030-2, Treatment of Adjacent Systems..... 263
f. MOD-030-2, Effective Date.................... 267
C. Violation Risk Factors and Violation Severity Levels. 270
D. Disposition of Other Reliability Standards........... 275
1. MOD-010-1 through MOD-025-1...................... 275
2. Reliability Standards to be Retired or Withdrawn. 277
E. Applicability........................................ 292
F. Definitions.......................................... 299
IV. Information Collection Statement........................ 307
V. Environmental Analysis................................... 313
VI. Regulatory Flexibility Act.............................. 314
VII. Document Availability.................................. 317
VIII. Effective Date and Congressional Notification......... 320
Before Commissioners: Jon Wellinghoff, Chairman; Suedeen G. Kelly, Marc
Spitzer, and Philip D. Moeller.
1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Federal Energy Regulatory Commission (Commission) approves, and directs
modifications to, six Modeling, Data and Analysis (MOD) Reliability
Standards submitted to the Commission by the North American Electric
Reliability Corporation (NERC), the Commission-certified Electric
Reliability Organization (ERO) for the United States.\2\ The approved
Reliability Standards pertain to methodologies for the consistent and
transparent calculation of available transfer capability or available
flowgate capability. Pursuant to section 215(d)(5) of the FPA and
section 39.5(f) of our regulations, the Commission directs the ERO to
develop certain modifications to the MOD Reliability Standards.\3\ The
Commission also directs NERC to retire the existing MOD Reliability
Standards replaced by the versions approved here. The retirement of
these Reliability Standards will be effective upon the effective date
of the approved MOD Reliability Standards.
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\1\ 16 U.S.C. 824o (2006).
\2\ North American Electric Reliability Corp., 116 FERC ] 61,062
(ERO Certification Order), order on reh'g & compliance, 117 FERC ]
61,126 (2006) (ERO Rehearing Order), aff'd, Alcoa Inc. v. FERC, 564
F.3d 1342 (D.C. Cir. 2009).
\3\ 16 U.S.C. 824o(d)(5).
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2. In Order No. 890, the Commission found that the lack of a
consistent and transparent methodology for calculating available
transfer capability is a significant problem because the calculation of
available transfer capability, which varies greatly depending on the
criteria and assumptions used, may allow the transmission service
provider to discriminate in subtle ways against its competitors.\4\ In
Order No. 693, the Commission reiterated its concerns expressed in
Order No. 890 and stated that available transfer capability raises both
comparability and reliability issues, and that it would be
irresponsible to require consistency in the available transfer
capability calculation without considering the reliability impact of
those decisions.\5\ The calculation of available transfer capability is
one of the most critical functions under the open access transmission
tariff (OATT) because it determines whether transmission customers can
access alternative power supplies. Improving transparency and
consistency of available transfer capability calculation methodologies
will eliminate transmission service providers' wide discretion in
calculating available transfer capability and ensure that customers are
treated fairly in seeking alternative power supplies. The Commission
believes that the Reliability Standards approved here address the
potential for undue discrimination by requiring industry-wide
transparency and increased consistency regarding all components of the
available transfer capability calculation methodology and certain
definitions, data, and modeling assumptions.
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\4\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007),
FERC Stats. & Regs. ] 31,241 (2007), order on reh'g, Order No. 890-
A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261 (2007),
order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), order on
reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009).
\5\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, 72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ]
31,242, at P 1022 (2007), order on reh'g, Order No. 693-A, 120 FERC
] 61,053 (2007).
---------------------------------------------------------------------------
3. The Commission approves the Reliability Standards filed by NERC
in this proceeding as just, reasonable, not unduly discriminatory or
preferential, and in the public interest.\6\ These Reliability
Standards represent a step forward in eliminating the broad discretion
previously afforded transmission service providers in the calculation
of available transfer capability. The approved Reliability Standards
will enhance transparency in the calculation of available transfer
capability, requiring transmission operators and transmission service
providers to calculate available transfer capability using a specific
methodology that is both explicitly documented and available to
reliability entities who request it.\7\ The approved Reliability
Standards also require documentation of the detailed representations of
the various components that comprise the available transfer capability
equation, including the specification of modeling and risk assumptions
and the disclosure of outage processing rules to other reliability
entities. These actions will make the processes to calculate available
transfer capability and its various components more transparent, which
in turn will allow the Commission and others to ensure consistency in
their application. By promoting consistency, standardization and
transparency, these Reliability Standards enhance the reliability of
the Bulk-Power System.
---------------------------------------------------------------------------
\6\ 16 U.S.C. 824o(d)(2).
\7\ Reliability entities include: Transmission service
providers, planning coordinators, reliability coordinators, and
transmission operators as those entities are defined in the NERC
Glossary of Terms Used in Reliability Standards (Glossary),
(Effective February 12, 2008), available at: https://www.nerc.com/docs/standards/rs/Glossary_12Feb08.pdf. Standards adopted by the
North American Energy Standards Board (NAESB) govern disclosure of
this information to other entities. The Commission accepts the
associated NAESB business practices in a Final Rule issued
concurrently in Docket No. RM05-5-013. See Standards for Business
Practices and Communication Protocols for Public Utilities, No. 676-
E, 129 FERC 61,162 (2009).
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4. On March 19, 2009, the Commission issued its Notice of Proposed
Rulemaking (NOPR) proposing to approve the six MOD
[[Page 64886]]
Reliability Standards.\8\ The Commission also proposed to direct NERC
to retire the currently effective MOD Reliability Standards along with
one FAC Reliability Standard. The Commission proposed that NERC retain
another FAC Reliability Standard, FAC-012-1, and proposed that the ERO
develop modifications to conform with the MOD Reliability Standards
approved herein. The Commission also proposed to direct NERC to expand
the disclosure provisions and conduct audits of certain implementation
documents associated with the Reliability Standards to be approved
herein. In response to the NOPR, comments were filed by 37 interested
parties. In the discussion below, we address the issues raised by these
comments. Appendix A to this Final Rule lists the entities that filed
comments on the NOPR.
---------------------------------------------------------------------------
\8\ Mandatory Reliability Standards for the Calculation of
Available Transfer Capability, Capacity Benefit Margins,
Transmission Reliability Margins, Total Transfer Capability, and
Existing Transmission Commitments and Mandatory Reliability
Standards for the Bulk-Power System, 74 FR 12747 (March 25, 2009),
FERC Stats. & Regs. ] 32,641 (2009) (``NOPR'').
---------------------------------------------------------------------------
I. Background
A. Order Nos. 888 and 889
5. In April 1996, as part of its statutory obligation under
sections 205 and 206 of the FPA \9\ 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.\10\ 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 that 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.\11\ 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).\12\ After their OATTs became effective,
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.
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\9\ 16 U.S.C. 824d, 824e.
\10\ 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), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\11\ 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.
\12\ See Order No. 888, FERC Stats. & Regs. ] 31,036 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 service provider).
---------------------------------------------------------------------------
6. The same day it issued Order No. 888, the Commission issued a
companion order, Order No. 889,\13\ addressing the separation of
vertically integrated utilities' transmission and merchant functions,
the information transmission service 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.
---------------------------------------------------------------------------
\13\ 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).
---------------------------------------------------------------------------
7. Among the information public utilities were required to post on
their OASIS was the transmission service provider's calculation of
available transfer capability. Though the Commission acknowledged that
before-the-fact measurement of the availability of transmission service
is ``difficult,'' the Commission concluded that it was important to
give potential transmission customers ``an easy-to-understand indicator
of service availability.'' \14\ Because formal methods did not then
exist to calculate available transfer capability and total transfer
capability, the Commission encouraged industry efforts to develop
consistent methods for calculating available transfer capability and
total transfer capability.\15\ Order No. 889 ultimately required
transmission service providers to base their calculations on ``current
industry practices, standards and criteria'' and to describe their
methodology in an Attachment C to their tariffs.\16\ The Commission
noted that the requirement that transmission service providers make
available for purchase only available transfer capability that is
posted as available ``should create an adequate incentive for them to
calculate available transfer capability and total transfer capability
as accurately and as uniformly as possible.'' \17\
---------------------------------------------------------------------------
\14\ Order No. 889, FERC Stats. & Regs. ] 31,035 at 31,749.
\15\ Id. at 31,750.
\16\ Id.
\17\ Id.
---------------------------------------------------------------------------
8. Although 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 did not standardize the
methodology for calculating available transfer capability, nor did it
impose any specific requirements regarding the disclosure of the
methodologies used by each transmission service provider.\18\ As a
result, a variety of methodologies to calculate available transfer
capability have been used with very few clear rules governing their
use. Moreover, there was often very little transparency about the
nature of these calculations, given that many transmission service
providers historically filed only summary explanations of their
available transfer capability methodologies in Attachment C to their
OATTs.
---------------------------------------------------------------------------
\18\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,749
n.610.
---------------------------------------------------------------------------
B. Order Nos. 890 and 693
9. Section 215 of the FPA requires a Commission-certified ERO to
develop mandatory and enforceable Reliability Standards that provide
for the reliable operation of the Bulk-Power System, which are subject
to Commission review and approval. If approved, the Reliability
Standards are enforced by the ERO subject to Commission oversight, or
by the Commission independently. As the ERO, NERC worked with industry
to develop Reliability Standards improving consistency and transparency
of available transfer capability calculation methodologies. On April 4,
2006, as
[[Page 64887]]
modified on August 28, 2006, NERC submitted to the Commission a
petition seeking approval of 107 proposed Reliability Standards,
including 23 Reliability Standards pertaining to Modeling, Data and
Analysis (MOD). The MOD group of Reliability Standards is intended to
standardize methodologies and system data needed for traditional
transmission system operation and expansion planning, reliability
assessment and the calculation of available transfer capability in an
open access environment.
10. On February 16, 2007, the Commission issued Order No. 890,
which addressed and remedied opportunities for undue discrimination
under the pro forma OATT adopted in Order No. 888. Among other things,
the Commission required industry-wide consistency and transparency of
all components of available transfer capability calculation and certain
definitions, data and modeling assumptions. The Commission concluded
that the lack of industry-wide criteria for the consistent calculation
of available transfer capability poses a threat to the reliable
operation of the Bulk-Power System, particularly with respect to the
inability of one transmission service provider to know with certainty
its neighbors' system conditions affecting its own available transfer
capability values. As a result of this reliability concern, the
Commission found that the proposed available transfer capability
reforms were also supported by FPA section 215, through which the
Commission has the authority to direct the ERO to submit a Reliability
Standard that addresses a specific matter.\19\ Thus, the Commission in
Order No. 890 directed industry to develop Reliability Standards, using
the ERO's Reliability Standards development procedures, that provide
for consistency and transparency in the methodologies used by
transmission owners to calculate available transfer capability.
---------------------------------------------------------------------------
\19\ FPA section 215(d)(5). 16 U.S.C. 824o(d)(5).
---------------------------------------------------------------------------
11. The Commission stated in Order No. 890 that the available
transfer capability-related Reliability Standards should, at a minimum,
provide a framework for available transfer capability, total transfer
capability and existing transmission commitments calculations. The
Commission did not require that there be just one computational process
for calculating available transfer capability because, among other
things, it found that the potential for discrimination and decline in
reliability level does not lie primarily in the choice of an available
transfer capability calculation methodology, but rather in the
consistent application of its components, input and exchange data, and
modeling assumptions.\20\ The Commission found that, if all of the
available transfer capability components, certain data inputs and
certain assumptions are consistent, the three available transfer
capability calculation methodologies would produce predictable and
sufficiently accurate, consistent, equivalent and replicable
results.\21\
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\20\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 1029.
\21\ Id. P 1030.
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12. On March 16, 2007, the Commission issued Order No. 693,
approving 83 of the 107 Reliability Standards filed by NERC in April
2006.\22\ Of the 83 approved Reliability Standards, the Commission
approved ten MOD Reliability Standards.\23\ However, the Commission
directed NERC to prospectively modify nine of the ten approved MOD
Reliability Standards to be consistent with the requirements of Order
No. 890.\24\ The Commission reiterated the requirement from Order No.
890 that all available transfer capability components (i.e., total
transfer capability, existing transmission commitments, capacity
benefit margin, and transmission reliability margin) and certain data
input, data exchange, and assumptions be consistent and that the number
of industry-wide available transfer capability calculation formulas be
few in number, transparent and produce equivalent results.\25\ The
Commission directed public utilities, working through the NERC
Reliability Standards and North American Energy Standards Board (NAESB)
business practices development processes, to produce workable solutions
to implement the available transfer capability-related reforms adopted
by the Commission. The Commission also deferred action on 24 proposed
Reliability Standards, which did not contain sufficient information to
enable the Commission to propose a disposition.\26\
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\22\ Order No. 693, FERC Stats. & Regs. ] 31,242.
\23\ Id. P 1010.
\24\ Id.
\25\ Id. P 1029-30; see also Order No. 890, FERC Stats. & Regs.
] 31,241 at P 207.
\26\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 287-303.
Some of these Reliability Standards required the regional
reliability organizations to develop criteria for use by users,
owners or operators within each region. The Commission set aside
such Reliability Standards and directed NERC to provide additional
details prior to considering them for approval. Id. P 287-303.
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II. MOD Reliability Standards
13. In response to the requirements of Order No. 890 and related
directives of Order No. 693,\27\ on August 29, 2008, NERC submitted for
Commission approval five MOD Reliability Standards: MOD-001-1--
Available Transmission System Capability, MOD-008-1--TRM Calculation
Methodology (hereinafter Transmission Reliability Margin Methodology),
MOD-028-1--Area Interchange Methodology, MOD-029-1--Rated System Path
Methodology, and MOD-030-1--Flowgate Methodology.\28\ On November 21,
2008, NERC submitted for Commission approval a sixth MOD Reliability
Standard: MOD-004-1--Capacity Benefit Margin (hereinafter Capacity
Benefit Margin Methodology). On March 6, 2009, NERC submitted for
Commission approval: MOD-030-2--a revised Flowgate Methodology
Reliability Standard and withdrew its request for approval of MOD-030-
1.\29\
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\27\ The Reliability Standards were originally due on December
10, 2007. See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 223.
NERC requested additional time to develop the Reliability Standards
in order to address concerns raised in its stakeholder process. See
NERC November 21, 2007 Request for Extension of Time, Docket No.
RM05-17-000, et al., at 7. The Commission ultimately granted three
requests for extension of time, extending NERC's deadline by over
seven months, so that NERC could develop the Reliability Standards
proposed here.
\28\ NERC designates the version number of a Reliability
Standard as the last digit of the Reliability Standard number.
Therefore, version zero Reliability Standards end with ``-0'' and
version one Reliability Standards end with ``-1.''
\29\ The MOD Reliability Standards are not codified in the CFR
and are not attached to the Final Rule. They are, however, available
on the Commission's eLibrary document retrieval system and on the
ERO's Web site, https://www.nerc.com.
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14. The Available Transmission System Capability Reliability
Standard (MOD-001-1) serves as an ``umbrella'' Reliability Standard
that requires each applicable entity to select and implement one or
more of the three available transfer capability methodologies found in
MOD-028-1, MOD-029-1, or MOD-030-2. MOD-004-1 and MOD-008-1 provide for
the calculation of capacity benefit margin and transmission reliability
margin, which are inputs into the available transfer capability
calculation. NERC states that its filing wholly addresses eight of the
24 Reliability Standards that the Commission did not approve in Order
No. 693 because further information was needed.
15. NERC contends that the Reliability Standards will have no undue
negative effect on competition, nor will they unreasonably restrict
available transfer capability on the Bulk-Power System
[[Page 64888]]
beyond any restriction necessary for reliability and do not limit use
of the Bulk-Power System in an unduly preferential manner. NERC
contends that the increased rigor and transparency introduced in the
development of available transfer capability and available flowgate
capability calculations serve to mitigate the potential for undue
advantages of one competitor over another. Under the Reliability
Standards, applicable entities are prohibited from making transmission
capability available on a more conservative basis for commercial
purposes than for either planning for native load or use in actual
operations, thereby mitigating the potential for differing treatment of
native load customers and transmission service customers. NERC states
that data exchange, which has been heretofore voluntary, is now
mandatory and it is required that the data be used in the available
transfer capability/available flowgate capability calculations. None of
these requirements exist in the current available transfer capability-
related Reliability Standards. NERC contends that these improvements
help the Commission achieve many of the primary objectives of Order No.
890 regarding transparency, standardization and consistency in
available transfer capability calculations.
16. NERC states that all three methodology Reliability Standards
(MOD-028-1, MOD-029-1, and MOD-030-2) share fundamental equations that,
while mathematically equivalent, are written in slightly different
forms. As a result, the manner of determining the components varies
between methodologies. The employment of any two methodologies, given
the same inputs, may produce similar, but not identical, results. As
noted by NERC there are fundamental differences in the proposed
methodologies that can keep them from producing identical results. For
example, the rated system path methodology does not use the same
frequent simulations of power flow used by the other two methodologies.
NERC states that the rated system path methodology therefore will
rarely generate numbers that identically match those determined by an
entity using the other two methodologies.
A. Coordination With Business Practice Standards
17. NERC states that it has worked closely and collaboratively with
NAESB, conducting numerous joint meetings and conference calls, to
develop the MOD Reliability Standards and related NAESB business-
practice standards.\30\ NERC states that the focus of the MOD
Reliability Standards is to address only the reliability aspects of
available transfer capability and available flowgate capability, not
commercial aspects, except to the extent that commercial system
availability closely matches actual remaining system capability. The
associated NAESB business practice standards are intended to focus on
the competitive aspects of these processes. Through implementation of
these Reliability Standards, access to the grid may indirectly be
restricted, but NERC states that NAESB business practices and
Commission orders related to these Reliability Standards ensure that
any limitation will be applied in a manner that ensures open access and
promotes competition.
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\30\ As noted above, the Commission addresses the NAESB business
practices in a Final Rule issued concurrently in Docket No. RM05-5-
013. See Standards for Business Practices and Communication
Protocols for Public Utilities, Order No. 676-E, 129 FERC ] 61,162
(2009).
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18. According to NERC, it and NAESB have coordinated the
development of these business practices and the Reliability Standards
to ensure that there are no duplications or double counting between the
business practice standards and the Reliability Standards. They intend
to continue to coordinate as necessary so that the available transfer
capability-related Reliability Standards are compatible and consistent.
B. Available Transmission System Capability, MOD-001-1
19. NERC proposes the Available Transmission System Capability
Reliability Standard (MOD-001-1) as part of a set of Reliability
Standards which are designed to work together to support a common
reliability goal: To ensure that transmission service providers
maintain awareness of available system capability and future flows on
their own systems as well as those of their neighbors. NERC states
that, historically, differences in implementation of available transfer
capability methodologies and a lack of coordination between
transmission service providers have resulted in cases where available
transfer capability has been overestimated. As a result, systems have
been oversold, resulting in potential or actual violations of system
operating limits and interconnection reliability operating limits. NERC
states that MOD-001-1 is the foundational Reliability Standard that
obliges entities to select a methodology and then calculate available
transfer capability or available flowgate capability using that
methodology. NERC contends that such selection ensures that the
determination of available transfer capability is accurate and
consistent across North America and that the transmission system is
neither oversubscribed nor underutilized.
20. NERC states that, unlike the current set of voluntary available
transfer capability standards, MOD-001-1 requires adherence to a
specific documented and transparent methodology. NERC states that it
requires applicable entities to calculate available transfer capability
on a consistent schedule and for specific timeframes. According to
NERC, MOD-001-1 requires users, owners and operators to disclose
counterflow assumptions and outage processing rules to other
reliability entities. NERC states that this Reliability Standard
prohibits applicable entities from making transmission capability
available on a more conservative basis for commercial purposes for
either planning for native load or use in actual operations. NERC's
MOD-001-1 also requires entities, for the first time, to exchange and
use available transfer capability data. NERC states that the
Reliability Standard reflects industry's consensus best practices for
determining available transfer capability.
21. MOD-001-1 includes nine requirements, which apply to all
transmission service providers and transmission operators. To ensure
consistency of enforcement, NERC states that each requirement is
supported by a measure that identifies what is required and how the
requirement will be enforced.
22. Under Requirement R1, a transmission operator must select one
of three methodologies for calculating available transfer capability or
available flowgate capability for each available transfer capability
path for each time frame (hourly, daily or monthly) for the facilities
in its area. As stated above, the three methodologies are: The area
interchange methodology, the rated system path methodology, and the
flowgate methodology.
23. Several requirements within this MOD-001-1 address the
calculation of available transfer capability or available flowgate
capability. Requirement R2 requires each transmission service provider
to calculate available transfer capability or available flowgate
capability values hourly for the next 48 hours, daily for the next 31
calendar days and monthly for the next 12 months. Requirement R6
requires each transmission operator in its calculation of total
transfer capability or total flowgate capability to use assumptions no
more limiting than those used in its
[[Page 64889]]
planning of operations. NERC contends that, consistent with the
requirements of Order No. 890 and related directives of Order No. 693,
Requirement R6 will minimize the differences between total transfer
capability and total flowgate capability for transmission and transfer
capability used in native load and reliability assessment studies.\31\
Similarly, Requirement R7 requires each transmission service provider,
in its calculation of available transfer capability or available
flowgate capability, to use assumptions no more limiting than those
used in its planning of operations. NERC contends that this requirement
addresses the Commission's directive in Order No. 693 for the ERO to
modify the available transfer capability Reliability Standards to
include a requirement that the assumptions used in available transfer
capability and available flowgate capability calculations be consistent
with those used for planning the expansion or operation of the Bulk-
Power System to the maximum extent possible.\32\ Requirement R8
requires each transmission service provider to recalculate available
transfer capability at a certain specified interval (hourly, daily,
monthly) unless the input values specified in the available transfer
capability calculation have not changed. NERC contends that Requirement
R8 satisfies the Commission's directive to calculate available transfer
capability on a consistent time interval.\33\
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\31\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 237;
Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1051.
\32\ Order No. 693, FERC Stats. & Regs. ] 1,242 at P 1057; see
also Order No. 890, FERC Stats. & Regs. ] 31,241 at P 292.
\33\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 301;
Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1057.
---------------------------------------------------------------------------
24. MOD-001-1 also includes several record keeping and information
sharing requirements for transmission service providers. Requirement R3
requires each transmission service provider to keep an available
transfer capability implementation document that explains the
implementation of its chosen methodology(ies), its use of counterflows,
the identities of entities with which it exchanges information for
coordination purposes, any capacity allocation processes, and the
manner in which it considers outages. Requirement R4 requires
transmission service providers to keep specific reliability entities
advised regarding changes to the available transfer capability
implementation document.\34\ Requirement R5 requires the transmission
service provider to make the available transfer capability
implementation document available to those same reliability
entities.\35\ Finally, Requirement R9 allows a transmission service
provider thirty calendar days to begin to respond to a request from any
other transmission service provider, planning coordinator, reliability
coordinator or transmission operator for certain data to be used in the
requestor's available transfer capability or available flowgate
capability calculations.
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\34\ These include: each planning coordinator, reliability
coordinator, and transmission operator associated with the
transmission service provider's area; and each planning coordinator,
reliability coordinator, and transmission service provider adjacent
to the transmission service provider's area.
\35\ Although the Reliability Standards only require the
transmission service provider to make the available transfer
capability implementation document available to certain reliability
entities, the NAESB standard on OASIS posting requirements (Standard
001-13.1.5) requires transmission service providers to provide a
link to the document on OASIS.
---------------------------------------------------------------------------
25. In Order No. 693, the Commission directed the ERO to develop
modifications to the available transfer capability Reliability
Standards to include a requirement that applicable entities make
available assumptions and contingencies underlying available transfer
capability and total transfer capability calculations. NERC contends
that this Reliability Standard addresses this issue by requiring
disclosure in the available transfer capability implementation document
under Requirement R3.1 and part of the data exchange required by
Requirement R9. NERC states that it has agreed with NAESB that
requirements for posting information are more appropriately addressed
through the NAESB process. Accordingly, NERC states that NAESB will be
addressing the requirements associated with posting this information,
instead of NERC.
C. Capacity Benefit Margin Methodology, MOD-004-1
26. The Capacity Benefit Margin Methodology Reliability Standard
(MOD-004-1) provides for the calculation of capacity benefit margin.
NERC defines capacity benefit margin as the amount of firm transmission
capability set aside by the transmission service provider for load-
serving entities, whose loads are located on that transmission service
provider's system, to enable access by the load-serving entities to
generation from interconnected systems to meet generation reliability
requirements.\36\ The purpose of this Reliability Standard is to
promote the consistent and reliable calculation, verification, setting
aside, and use of capacity benefit margin to support analysis and
system operations. NERC states that setting aside of capacity benefit
margin for a load-serving entity allows that entity to reduce its
installed generating capacity below that which may otherwise have been
necessary without interconnections to meet its generation reliability
requirements. NERC states that the transmission transfer capability
preserved as capacity benefit margin is intended to be used by the
load-serving entities only in times of emergency generation
deficiencies.
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\36\ See NERC Glossary.
---------------------------------------------------------------------------
27. Reliability Standard MOD-004-1 applies to transmission service
providers, transmission planners, load-serving entities, resource
planners and balancing authorities. As discussed more fully below, NERC
states that it does not specify a particular methodology for
calculating capacity benefit margin, but rather improves transparency
by requiring adherence to specific documented and transparent
methodology to ensure consistent and reliable calculation,
verification, preservation and use of capacity benefit margin.
28. To improve consistency and transparency in the calculation of
capacity benefit margin, the Reliability Standard imposes twelve
requirements on entities electing to use a capacity benefit margin.
Requirement R1 requires the transmission service provider that
maintains capacity benefit margin to prepare and keep current a
capacity benefit margin implementation document that includes at a
minimum: (1) The process through which a load-serving entity within a
balancing authority associated with the transmission service provider,
or the resource planner associated with that balancing authority area,
may ensure that its need for transmission capacity to be set aside as
capacity benefit margin will be reviewed and accommodated by the
transmission service provider to the extent transmission capacity is
available; (2) the procedure and assumptions for establishing capacity
benefit margin for each available transfer capability path or flowgate;
and (3) the procedure for a load-serving entity or balancing authority
to use transmission capacity set aside as capacity benefit margin,
including the manner in which the transmission service provider will
manage situations where the requested use of capacity benefit margin
exceeds the amount of capacity benefit margin available.
29. Requirement R2 requires the transmission service provider to
make its current capacity benefit margin implementation document
available to the transmission operators, transmission service
providers, reliability
[[Page 64890]]
coordinators, transmission planners, resource planners, and planning
coordinators that are within or adjacent to the transmission service
provider's area, and to the load-serving entities and balancing
authorities within the transmission service providers area, and notify
those entities of any changes to the capacity benefit margin
implementation document prior to the effective date of the change.
30. Requirements R3 and R4 require each load-serving entity and
resource planner to determine the need for transmission capacity to be
set aside as capacity benefit margin for imports into a balancing
authority by using one or more of the following to determine the
generation capability import requirement: \37\ loss of load expectation
studies, loss of load probability studies, deterministic risk-analysis
studies, and reserve margin or resource adequacy requirements
established by other entities, such as municipalities, state
commissions, regional transmission organizations, independent system
operators, regional reliability organizations, or regional entities.
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\37\ NERC defines the generation capability import requirement
as the amount of generation capability from external sources
identified by a load-serving entity or resource planner to meet its
generation reliability or resource adequacy requirement as an
alternative to internal resources.
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31. Requirement R5 requires the transmission service provider to
establish at least every 13 months a capacity benefit margin value for
each available transfer capability path or flowgate to be used for
available transfer capability or available flowgate capability during
the 13 full calendar months (months 2-14) following the current month
(the month in which the transmission service provider is establishing
the capacity benefit margin values). Similarly, Requirement R6 requires
the transmission planner to establish a capacity benefit margin value
for each available transfer capability path or flowgate to be used in
planning during each of the full calendar years two through ten
following the current year (the year in which the transmission planner
is establishing the capacity benefit margin values). All values must
reflect consideration of each of the following, if available: (1) Any
studies performed by load-serving entities or resource planners
pursuant to Requirement R3 for loads within the transmission service
provider's area; or (2) any reserve margin or resource adequacy
requirements for loads within the transmission service provider's area
established by other entities, such as municipalities, state
commissions, regional transmission organizations, independent system
operators, regional reliability organizations, or regional entities.
Once determined, the capacity benefit margin values will be allocated
along available transfer capability paths based on the expected import
paths or source regions provided by load-serving entities or resource
planners. Capacity benefit margin values for flowgates will be
allocated based on the expected import paths or source regions provided
by load-serving entities or resource planners and the distribution
factors associated with those paths or regions, as determined by the
transmission service provider.
32. Requirements R7 and R8 require the transmission service
provider and the transmission planner to notify all load-serving
entities and resource planners that determined they had a need for
capacity benefit margin of the amount, or the amount planned, of
capacity benefit margin set aside, within 31 calendar days after the
establishment of capacity benefit margin.
33. Requirement R9 requires the transmission service provider that
maintains capacity benefit margin and the transmission planner to
provide, subject to confidentiality and security requirements, copies
of the applicable supporting data, including any models, used for
determining capacity benefit margin or allocating capacity benefit
margin over each available transfer capability path or flowgate to each
of the associated transmission operators and to any transmission
service provider, reliability coordinator, transmission planner,
resource planner, or planning coordinator within 30 calendar days of
their making a request for the data.
34. Requirement R10 requires the load-serving entity or balancing
authority to request to import energy over firm transfer capability set
aside as capacity benefit margin only when experiencing a declared
level 2 or higher NERC energy emergency alert.\38\
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\38\ Under Reliability Standard EOP-002-2 Reliability
Coordinators initiate an energy emergency alert when a balancing
authority within its control area experiences a potential or actual
energy emergency. NERC has established three levels of energy
emergency alerts (one through three) to clarify the severity of the
potential or actual energy emergency.
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35. When reviewing an arranged interchange service request using
capacity benefit margin, Requirement R11 requires all balancing
authorities and transmission service providers to waive, within the
bounds of reliable operation, any real-time timing and ramping
requirements.
36. Requirement R12 requires all transmission service providers
maintaining capacity benefit margin to approve, within the bounds of
reliable operation, any arranged interchange using capacity benefit
margin that is submitted by an ``energy deficient entity'' \39\ under
an energy emergency alert level 2 if the capacity benefit margin is
available, the emergency is declared within the balancing authority
area of the energy deficient entity, and the load of the energy
deficient entity is located within the transmission service provider's
area.
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\39\ Energy deficient entities are defined by NERC in the
Capacity and Energy Emergencies Reliability Standard. See EOP-002-2,
Attachment 1.
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37. NERC states that MOD-004-1 complies with the requirements of
Order No. 890 and related directives of Order No. 693 because it sets
criteria that allow load-serving entities to request transfer
capability to be set aside in the form of capacity benefit margin in a
consistent and transparent manner. Consistent with the Commission's
direction, the Reliability Standard provides an approach for
determining capacity benefit margin that is flexible and does not
mandate a particular methodology.\40\ NERC supports this approach
because various parts of the country have already developed robust
methodologies for determining capacity benefit margin. NERC states that
Requirements R3 and R4 allow load-serving entities and resource
planners to perform specific studies to determine their need for
capacity benefit margin. By specifying the types of studies load-
serving entities or resource planners must perform, NERC contends that
MOD-004-1 ensures that capacity benefit margin and transmission
reliability margin are not used for the same purpose.\41\ In response
to the Commission's transparency requirement,\42\ NERC states that
Requirement R9 ensures that capacity benefit margin studies are made
available to the appropriate reliability entities for their review and
analysis. With regard to public disclosure, NERC states that it has
agreed with NAESB that requirements for posting information are more
appropriately addressed through the NAESB process.
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\40\ Citing Order No. 693, FERC Stats. & Regs. ] 31,242 at P
1078; see also Order No. 890, FERC Stats. & Regs. ] 31,241 at P 257.
\41\ Citing Order No. 693, FERC Stats. & Regs. ] 31,242 at P
1105.
\42\ Citing id. P 1077.
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38. Requirements R5 and R6 require that the transmission service
provider and transmission planner utilize the information contained in
the studies if it has been provided to them when establishing capacity
benefit margin values and mandate the re-evaluation of
[[Page 64891]]
capacity benefit margin at least once every thirteen months.\43\ NERC
states that, consistent with Order Nos. 890 and 693, Requirements R5
and R6 also require allocation of capacity benefit margin based on the
available transfer methodology chosen under MOD-001-1.\44\ NERC states
that Requirements R10, R11 and R12 specify the manner in which capacity
benefit margin is to be used.\45\ NERC states that any additional
requirements specified by the transmission service provider must be
identified in the capacity benefit margin implementation document, as
mandated in Requirement R1.3.
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\43\ Citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P
358. NERC states that it chose thirteen months to ensure enough
flexibility for a yearly update without being so prescriptive as to
require it on a specific day.
\44\ Citing id. P 257; Order No. 693, FERC Stats. & Regs. ]
31,242 at P 1082.
\45\ Citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P
256-7.
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39. In response to the requirement that capacity benefit margins
values be verifiable,\46\ NERC states that Requirements R5, R6 and R9
ensure that the studies used to establish a need for capacity benefit
margin are made available to any of the reliability entities specified
in Requirement R9 that request them. NERC explains that the Reliability
Standard does not mandate the verification of amounts of capacity
benefit margin requested by the transmission service provider because
it would place a functional entity (either the transmission service
provider or transmission planner) in the position of having to judge
the quality of each request, which could create conflicts of interest
or potentially result in liability for that entity. Rather than mandate
any particular approach for validation, NERC states that Requirements
R3 and R4 mandate the specific kinds of studies to be performed and
supporting information that is to be maintained when determining the
underlying need for capacity benefit margin. To the extent that
entities do not use these methods or maintain this supporting
information, NERC states that they will be in violation of the
Reliability Standard.
---------------------------------------------------------------------------
\46\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1077.
---------------------------------------------------------------------------
40. In response to the Commission's call for clarity in the process
for requesting capacity benefit margin,\47\ NERC states that
Requirement R1.1 requires the transmission service provider to explain
the process by which load-serving entities and resource planners may
ensure that their need for transmission capacity to be set aside as
capacity benefit margin is reviewed and accommodated by the
transmission service provider to the extent transmission capacity is
available. Requirement R1.3 requires the transmission service provider
to describe the procedure for load-serving entities and resource
planners to use transmission capacity that has been set aside as
capacity benefit margin. If the requested use of capacity benefit
margin exceeds the amount of capacity benefit margin available,
Requirement R1.3 also requires a description of how the transmission
service provider will manage such situations. In addition, NERC states
that Requirements R7 and R8 mandate that the transmission service
provider notify load-serving entities and resource planners that
determined they had a need for capacity benefit margin of the amount of
capacity benefit margin set aside, so that they may make informed
decisions about how to proceed if their full request for capacity
benefit margin could not be accommodated.
---------------------------------------------------------------------------
\47\ Id. P 1081.
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D. Transmission Reliability Margin Methodology, MOD-008-1
41. The Transmission Reliability Margin Methodology Reliability
Standard (MOD-008-1) provides for the calculation of transmission
reliability margin. Transmission reliability margin is transmission
transfer capability set aside to mitigate risks to operations, such as
deviations in dispatch, load forecast, outages, and similar such
conditions.\48\ It is distinctly different from capacity benefit
margin, which is transmission transfer capability set aside to allow
for the import of generation upon the occurrence of a generation
capacity deficiency. MOD-008-1 describes the reliability aspects of
determining and maintaining a transmission reliability margin and the
components of uncertainty that may be considered when making that
calculation. The purpose of this Reliability Standard is to promote the
consistent and reliable calculation, verification, preservation, and
use of transmission reliability margin to support analysis and system
operations.
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\48\ See NERC Glossary, available at: https://www.nerc.com/docs/standards/rs/Glossary_2009April20.pdf.
---------------------------------------------------------------------------
42. Reliability Standard MOD-008-1 applies only to transmission
operators that have elected to keep a transmission reliability margin.
As discussed more fully in the discussion section below, NERC states
that the Reliability Standard does not specify one approach for
calculating transmission reliability margin, but rather improves
transparency by providing the key requirements and items that must be
contained in any transmission reliability margin methodology.
43. To improve the transparency of transmission reliability margin
calculations, the Reliability Standard imposes five requirements on
transmission service providers electing to keep a transmission
reliability margin. Requirement R1 provides that a transmission
operator must keep a transmission reliability margin implementation
document that explains how specific risks such as aggregate load
forecast uncertainty, load distribution uncertainty, and forecast
uncertainty in transmission system topology \49\ are accounted for in
the transmission reliability margin, how transmission reliability
margin is allocated, and how transmission reliability margin is
determined for various time frames.
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\49\ This includes, but is not limited to: Forced or unplanned
outages and maintenance outages; allowances for parallel path (loop
flow) impacts; allowances for simultaneous path interactions;
variations in generation dispatch (including, but not limited to,
forced or unplanned outages, maintenance outages and location of
future generation); short-term system operator response (operating
reserve actions); reserve sharing requirements; and inertial
response and frequency bias.
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44. Requirement R2 allows a transmission operator to account only
for the risks identified in Requirement R1 in transmission reliability
margin, and prohibits the transmission operator from incorporating
risks that are addressed in capacity benefit margin. It allows reserve
sharing to be included in transmission reliability margin.
45. Requirement R3 requires each applicable entity to make the
transmission reliability margin implementation document and associated
information available to the following reliability entities if
requested: Transmission service provider, reliability coordinator,
planning coordinator, transmission planner, and transmission operator.
46. Requirement R4 provides that each applicable transmission
operator must determine the transmission reliability margin value per
the methods described in the transmission reliability margin
implementation document at least once every thirteen months. Finally,
Requirement R5 states that each applicable transmission operator must
provide that transmission reliability margin value to its transmission
service providers and transmission planners no more than seven days
after it ha
