Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 64890-64904 [2012-26111]
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Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations
Issued in Seattle, Washington, on October
9, 2012.
John Warner,
Manager, Operations Support Group, Western
Service Center.
Administration Order 7400.9W,
Airspace Designations and Reporting
Points, dated August 8, 2012, and
effective September 15, 2012, is
amended as follows:
[FR Doc. 2012–25925 Filed 10–23–12; 8:45 am]
Paragraph 5000
Class D airspace.
*
*
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AWP CA D
BILLING CODE 4910–13–P
*
Hawthorne, CA [Amended]
Jack Northrop Field/Hawthorne Municipal
Airport, CA
(Lat. 33°55′22″ N., long. 118°20′07″ W.)
That airspace extending upward from the
surface to and including 2,500 feet MSL
within 2.6-mile radius of the Jack Northrop
Field/Hawthorne Municipal Airport, and that
airspace 1.5 miles north and 2 miles south of
the 229° bearing of the airport extending from
the 2.6-mile radius to 3.8 miles southwest,
and that airspace 2 miles north and 1.5 miles
south of the 096° bearing of the airport
extending from the 2.6-mile radius to 3.9
miles east of the airport, excluding the Los
Angeles Airport Class D and that portion
within the Torrance CA, Class D airspace
area. This Class D airspace is effective during
the specific dates and times established in
advance by a Notice to Airmen. The effective
date and time will thereafter be continuously
published in the Airport/Facility Directory.
Paragraph 6004 Class E airspace areas
designated as an extension to Class D or
Class E surface area.
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*
*
AWP CA E4
*
*
Hawthorne, CA [Amended]
Jack Northrop Field/Hawthorne Municipal
Airport, CA
(Lat. 33°55′22″ N., long. 118°20′07″ W.)
That airspace extending upward from the
surface within 2 miles north and .5 miles
south of the 096° bearing of Jack Northrop
Field/Hawthorne Municipal Airport,
beginning 3.9 miles east of the airport
extending to 6.3 miles east of the airport.
This Class E airspace area is effective during
the specific dates and times established in
advance by a Notice to Airmen. The effective
date and time will thereafter be continuously
published in the Airport/Facility Directory.
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM10–23–002; Order No. 1000–
B]
Transmission Planning and Cost
Allocation by Transmission Owning
and Operating Public Utilities
Federal Energy Regulatory
Commission, DOE.
ACTION: Order on rehearing and
clarification.
AGENCY:
The Federal Energy
Regulatory Commission affirms its basic
determinations in Order Nos. 1000 and
1000–A, amending the transmission
planning and cost allocation
requirements established in Order No.
890 to ensure that Commissionjurisdictional services are provided at
just and reasonable rates and on a basis
that is just and reasonable and not
unduly discriminatory or preferential.
This order affirms the Order No. 1000
transmission planning reforms that:
Require that each public utility
transmission provider participate in a
regional transmission planning process
that produces a regional transmission
plan; provide that local and regional
transmission planning processes must
provide an opportunity to identify and
evaluate transmission needs driven by
public policy requirements established
SUMMARY:
by state or federal laws or regulations;
improve coordination between
neighboring transmission planning
regions for new interregional
transmission facilities; and remove from
Commission-approved tariffs and
agreements a federal right of first
refusal. This order also affirms the
Order No. 1000 requirements that each
public utility transmission provider
must participate in a regional
transmission planning process that has:
A regional cost allocation method for
the cost of new transmission facilities
selected in a regional transmission plan
for purposes of cost allocation and an
interregional cost allocation method for
the cost of new transmission facilities
that are located in two neighboring
transmission planning regions and are
jointly evaluated by the two regions in
the interregional transmission
coordination process required by this
Final Rule. Additionally, this order
affirms the Order No. 1000 requirement
that each cost allocation method must
satisfy six cost allocation principles.
DATES:
Effective November 23, 2012.
FOR FURTHER INFORMATION CONTACT:
Melissa Nimit, Federal Energy
Regulatory Commission, Office of the
General Counsel, 888 First Street NE.,
Washington, DC 20426, (202) 502–
6638.
Shiv Mani, Federal Energy Regulatory
Commission, Office of Energy Policy
and Innovation, 888 First Street NE.,
Washington, DC 20426, (202) 502–
8240.
SUPPLEMENTARY INFORMATION:
Before Commissioners: Jon Wellinghoff,
Chairman; Philip D. Moeller, John R.
Norris, and Cheryl A. LaFleur.
Issued October 18, 2012
Table of Contents
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Paragraph
No.
I. Introduction ...........................................................................................................................................................................................
II. Transmission Planning ........................................................................................................................................................................
A. Regional Transmission Planning .................................................................................................................................................
1. Role of Section 217(b)(4) of the Federal Power Act ............................................................................................................
2. Regional Transmission Planning Requirements ...................................................................................................................
3. Consideration of Transmission Needs Driven by Public Policy Requirements .................................................................
B. Nonincumbent Transmission Developers ...................................................................................................................................
1. Legal Authority ......................................................................................................................................................................
2. Requirement To Remove a Federal Right of First Refusal from Commission-Jurisdictional Tariffs and Agreements,
and Limits on the Applicability of That Requirement .........................................................................................................
3. Framework To Evaluate Transmission Projects Submitted for Selection in the Regional Transmission Plan for Purposes of Cost Allocation ........................................................................................................................................................
C. Interregional Transmission Coordination ....................................................................................................................................
1. Implementation of the Interregional Transmission Coordination Requirements ..............................................................
III. Cost Allocation ...................................................................................................................................................................................
1. Cost Allocation Principle 2—No Involuntary Allocation of Costs to Non-beneficiaries ..........................................................
IV. Information Collection Statement ......................................................................................................................................................
V. Document Availability ........................................................................................................................................................................
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Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations
64891
Paragraph
No.
VI. Effective Date ......................................................................................................................................................................................
Appendix A: Abbreviated Names of Petitioners
I. Introduction
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1. In Order No. 1000,1 the
Commission amended the transmission
planning and cost allocation
requirements established in Order No.
890 2 to ensure that the rates, terms and
conditions of service provided by public
utility providers are just and reasonable
and not unduly discriminatory or
preferential. Order No. 1000’s
transmission planning reforms require:
(1) Each public utility transmission
provider to participate in a regional
transmission planning process that
produces a regional transmission plan;
(2) that local and regional transmission
planning processes must provide an
opportunity to identify and evaluate
transmission needs driven by public
policy requirements established by state
or federal laws or regulations; (3)
improved coordination between
neighboring transmission planning
regions for new interregional
transmission facilities; and (4) the
removal from Commission-approved
tariffs and agreements of a federal right
of first refusal.
2. Order No. 1000 also requires that
each public utility transmission
provider must participate in a regional
transmission planning process that has:
(1) A regional cost allocation method for
the cost of new transmission facilities
selected in a regional transmission plan
for purposes of cost allocation and (2)
an interregional cost allocation method
for the cost of new transmission
facilities that are located in two
neighboring transmission planning
regions and are jointly evaluated by the
two regions in the interregional
transmission coordination process
required by this Final Rule. Order No.
1000 also requires that each cost
1 Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public
Utilities, Order No. 1000, 76 FR 49842 (Aug. 11,
2011), FERC Stats. & Regs. ¶ 31,323 (2011), order
on reh’g, Order No. 1000–A, 139 FERC ¶ 61,132
(2012).
2 Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890,
72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs.
¶ 31,241, order on reh’g, Order No. 890–A, 73 FR
2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261
(2007), order on reh’g and clarification, Order No.
890–B, 73 FR 39092 (July 8, 2008), 123 FERC ¶
61,299 (2008), order on reh’g, Order No. 890–C, 74
FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228
(2009), order on clarification, Order No. 890–D, 74
FR 61511 (Nov. 25 2009), 129 FERC ¶ 61,126
(2009).
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allocation method must satisfy six cost
allocation principles.
3. In Order No. 1000–A, the
Commission largely affirmed the
reforms adopted in Order No. 1000. The
Commission concluded that taken
together, the reforms adopted in Order
No. 1000 will ensure that Commissionjurisdictional services are provided at
just and reasonable rates and on a basis
that is just and reasonable and not
unduly discriminatory or preferential.
The Commission therefore rejected
requests to eliminate, or substantially
modify, the various reforms adopted in
Order No. 1000. The Commission did
however, make a number of
clarifications.
4. Several petitioners have sought
further rehearing and clarification of the
Commission’s determinations in Order
No. 1000–A.3 The Commission largely
affirms the determinations reached in
Order No. 1000–A, making clarifications
to address matters raised by petitioners.
II. Transmission Planning
A. Regional Transmission Planning
5. Order No. 1000 built on the reforms
adopted in Order No. 890 to improve
regional transmission planning. First,
Order No. 1000 required each public
utility transmission provider to
participate in a regional transmission
planning process that produces a
regional transmission plan and complies
with existing Order No. 890
transmission planning principles.4
3 A list of petitioners filing requests for rehearing
and/or clarification is provided in Appendix A.
Southwest Power Pool (SPP) filed a request for
clarification and/or reconsideration of Order No.
1000–A. While SPP denominates its pleading as a
request for clarification, it is, in fact, a late-filed
request for rehearing. Pursuant to section 313(a) of
the Federal Power Act (FPA), 16 U.S.C. 825l(a)
(2006), an aggrieved party must file a request for
rehearing within thirty days after the issuance of
the Commission’s order. Because the 30-day
rehearing deadline is statutory, it cannot be
extended, and SPP’s request for rehearing must be
rejected as untimely. Moreover, the courts have
repeatedly recognized that the time period within
which a party may file an application for rehearing
of a Commission order is statutorily established at
30 days by section 313(a) of the FPA and that the
Commission has no discretion to extend that
deadline. See, e.g., City of Campbell v. FERC, 770
F.2d 1180, 1183 (D.C. Cir. 1985); Boston Gas Co. v.
FERC, 575 F.2d 975, 977–79 (1st Cir. 1978).
Furthermore, we note that the issues raised by SPP
are similar to those raised by other petitioners,
which are summarized and addressed below in
section II.B.2 of this order.
4 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 68.
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Second, Order No. 1000 adopted
reforms under which transmission
needs driven by Public Policy
Requirements are considered in local
and regional transmission planning
processes.5 The Commission explained
that these reforms work together to
ensure that public utility transmission
providers in every transmission
planning region, in consultation with
stakeholders, evaluate proposed
alternative solutions at the regional
level that may resolve the region’s needs
more efficiently or cost-effectively than
solutions identified in the local
transmission plans of individual public
utility transmission providers.6 The
Commission noted that, as in Order No.
890, the transmission planning
requirements in Order No. 1000 do not
address or dictate which transmission
facilities should be either in the regional
transmission plan or actually
constructed, and that such decisions are
left in the first instance to the judgment
of public utility transmission providers,
in consultation with stakeholders
participating in the regional
transmission planning process.7
1. Role of Section 217(b)(4) of the
Federal Power Act
a. Order No. 1000–A
6. In Order No. 1000–A, the
Commission affirmed Order No. 1000’s
conclusion that the Commission has
ample legal authority under the Federal
Power Act (FPA) to undertake its
regional transmission planning reforms.
Among other things, Order No. 1000–A
rejected arguments that FPA section
217(b)(4) 8 prohibits or otherwise limits
the Commission’s ability to undertake
these reforms.9 Order No. 1000–A
5 Id. The Commission explained that Public
Policy Requirements are those established by state
or federal laws or regulations, meaning enacted
statutes (i.e., passed by the legislature and signed
by the executive) and regulations promulgated by
a relevant jurisdiction, whether within a state or at
the federal level. Id. P 2. Order No. 1000–A clarified
that this included transmission needs driven by
local laws or regulations. Order No. 1000–A, 139
FERC ¶ 61,132 at P 319.
6 Id.
7 Id. P 68 n.57.
8 16 U.S.C. 824s (2006).
9 Order No. 1000–A, 139 FERC ¶ 61,132 at PP
168–179.
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Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations
acknowledged claims by some
petitioners that Order No. 681,10 which
requires transmission organizations that
are public utilities with organized
electricity markets to make available
long-term firm transmission rights that
satisfy certain guidelines, expressly
notes a preference for load-serving
entities.11 Order No. 1000–A found that
Order No. 681’s priority for load-serving
entities in the allocation of long-term
firm transmission rights supported by
existing transmission capacity is not
inconsistent with Order No. 1000,
which addresses planning and cost
allocation for new transmission.12 Order
No. 1000–A also found that the
transmission planning reforms will aid,
and not hinder, load-serving entities in
meeting their reasonable transmission
needs.13
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b. Request for Rehearing
7. Transmission Access Policy Study
Group argues that in Order No. 1000–A,
the Commission suggested for the first
time that the preference for load-serving
entity long-term rights established in
Order No. 681 applies only to existing
transmission capacity ‘‘but not in the
broader context of planning new
transmission capacity.’’ 14 Transmission
Access Policy Study Group contends
that the Commission erred in suggesting
that Order No. 681 does not apply to
new transmission facilities, contending
that Order No. 681 extended the
preference to be afforded load-serving
entities to long-term rights from existing
capacity to new capacity by providing
that ‘‘[w]hen * * * transmission
upgrades [that are rolled into
transmission rates] come into service,
the transmission rights that result from
such investments will be made available
as rights from ‘existing capacity.’ ’’ 15
Transmission Access Policy Study
Group states that this provision had one
limited exception—where a
transmission upgrade is participantfunded.16 It contends that this exception
is inapplicable to the new transmission
facilities at issue in this proceeding, as
Order No. 1000 specifically ruled that
participant funding will not comply
with the regional or interregional cost
10 Long-Term Firm Transmission Rights in
Organized Electricity Markets, Order No. 681, FERC
Stats. & Regs. ¶ 31,226, order on reh’g, Order No.
681–A, 117 FERC ¶ 61,201 (2006), order on reh’g,
Order No. 681–B, 126 FERC ¶ 61,254 (2009).
11 Order No. 1000–A, 139 FERC ¶ 61,132 at P 171.
12 Id. P 172.
13 Id.
14 Transmission Access Policy Study Group at 12
(quoting Order No. 1000–A, 139 FERC ¶ 61,132 at
P 171).
15 Id. at 13 (quoting Order No. 681, FERC Stats.
& Regs. ¶ 31,226 at P 211 (emphasis added)).
16 Id.
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allocation principles adopted by the
Final Rule.17 Transmission Access
Policy Study Group urges the
Commission to clarify that Order Nos.
1000 and 1000–A do not alter the scope
or applicability of Order No. 681.18 In
the alternative, it argues that Order No.
1000 should be reversed to the extent
that it modifies the load-serving entity
long-term rights preference established
by Order No. 681, by limiting that
preference to ‘‘existing’’ transmission
facilities, rather than extending it to
new transmission that is not participantfunded.19
c. Commission Determination
8. In response to Transmission Access
Policy Study Group, we clarify that
nothing in either Order No. 1000 or
Order No. 1000–A is intended in any
way to undermine or alter the
guidelines the Commission instituted in
Order No. 681. Order No. 1000’s
transmission planning reforms are
distinct from the Commission’s
rulemaking in Order No. 681, as we
explain below.
9. Section 1233(a) of the Energy
Policy Act of 2005 enacted FPA section
217(b)(4), in which the Commission is
directed to exercise its authority under
the FPA in a manner that facilitates the
planning and expansion of transmission
facilities to meet the reasonable needs of
load-serving entities to satisfy the
service obligations of the load-serving
entities, and enables load-serving
entities to secure firm transmission
rights (or equivalent tradable or
financial rights) on a long-term basis for
long-term power supply arrangements
made, or planned, to meet such needs.20
10. Section 1233(b) of the Energy
Policy Act of 2005 further directed the
Commission to promulgate a rule on
long-term transmission rights in
organized markets.21 The Commission
consequently issued Order No. 681,
which adopted guidelines that
independent system operators (ISOs)
and regional transmission organizations
(RTOs) are required to follow regarding
the availability of long-term firm
transmission rights, including a
guideline providing that load-serving
entities ‘‘must have a priority over non17 Id.
load serving entities in the allocation of
long-term firm transmission rights that
are supported by existing capacity.’’ 22
11. As Order No. 1000–A explained,
we do not find any inconsistency
between Order No. 1000 and section
217(b)(4).23 Nor do we find any
inconsistency between Order No. 1000
and Order No. 681. The requirements
adopted by the Commission in Order
Nos. 1000 and 1000–A are focused on
the planning and cost allocation of new
transmission facilities, as defined
therein. The Commission did not intend
its statements in Order No. 1000–A
regarding the planning and cost
allocation of certain new transmission
facilities to alter the requirement in
Order No. 681 that ‘‘when [transmission
upgrades that are rolled into
transmission rates] * * * come into
service, the transmission rights that
result from such investments will be
made available as rights from ‘existing
capacity’ * * * . Prevailing cost
allocation rules will apply.’’ 24 Thus, we
clarify for Transmission Access Policy
Study Group that nothing in Order Nos.
1000 or 1000–A changes the
requirements of Order No. 681,
including the Order No. 681 established
preference for load-serving entities in
the allocation of long-term firm
transmission rights, and that the
Commission did not alter the
application of Order No. 681 to new
transmission facilities that are subject to
the requirements of Order No. 1000.
2. Regional Transmission Planning
Requirements
a. Order No. 1000–A
12. Order No. 1000–A affirmed Order
No. 1000’s conclusion that public utility
transmission providers must revise their
OATTs to provide for a regional
transmission planning process that
produces a regional transmission plan
and satisfies Order No. 890’s
transmission planning principles.25 The
Commission explained that Order No.
1000 requires neither the filing of the
regional transmission plan resulting
from the regional transmission planning
process nor the filing of specific
applications of cost allocation
determinations.26 With respect to this
latter point, Order No. 1000–A stated
18 Id.
19 Id.
20 16
U.S.C. 824q(b)(4) (2006).
21 EPAct 2005, Public Law 109–58, section 1233,
119 Stat. 594, 960 (2005); 16 U.S.C. 824q (2006)).
Section 1233 provides that within 1 year after the
date of enactment of that section and after notice
and an opportunity for comment, the Commission
shall by rule or order, implement section 217(b)(4)
of the Federal Power Act in Transmission
Organizations, as defined by that Act with
organized electricity markets.
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22 Order No. 681, FERC Stats. & Regs. ¶ 31,226 at
P 325.
23 See Order No. 1000–A, 139 FERC ¶ 61,132 at
PP 168–179 (addressing requests for rehearing and
clarification of Order No. 1000 with respect to the
role of section 217(b)(4)).
24 See Order No. 681, FERC Stats. & Regs. ¶
31,226 at P 211.
25 Order No. 1000–A, 139 FERC ¶ 61,132 at PP
263–301.
26 Id. PP 285–286.
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that such a requirement would be
unnecessary to comply with Order No.
1000, noting that Order No. 1000
requires that public utility transmission
providers have an ex ante cost
allocation method on file with and
approved by the Commission. Order No.
1000–A also noted that this cost
allocation method must explain how the
costs of new transmission facilities
selected in a regional transmission plan
for purposes of cost allocation are to be
allocated, consistent with the cost
allocation principles set forth in Order
No. 1000.27 Consequently, customers,
stakeholders, and others will have
‘‘notice’’ at the time the compliance
filings are made, when the Commission
acts on those filings, and as the regional
transmission planning process results in
the selection of a transmission facility in
the regional transmission plan for
purposes of cost allocation.28 However,
consistent with the regional flexibility
provided in Order No. 1000, Order No.
1000–A also concluded that public
utility transmission providers, in
consultation with stakeholders, may
propose OATT revisions requiring the
submission of cost allocations in their
Order No. 1000 compliance filings.29
13. The Commission further stated in
Order No. 1000–A that it will evaluate
compliance filings to ensure that they
comply with Order No. 1000 and that
both stakeholders and the Commission
have the right to initiate actions under
section 206 of the FPA if they believe
that, for example, a Commissionapproved regional transmission
planning process was not followed or if
a cost allocation method was not
followed or produced unjust and
unreasonable results for a particular
new transmission facility or class of
new transmission facilities.30
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b. Request for Rehearing
14. Transmission Access Policy Study
Group argues that the Commission
should not establish a generic rule that,
if transmission providers elect not to
propose a section 205 filing of specific
applications of their regional cost
allocation, the only means to challenge
such applications is under section
206.31 It states that although Order No.
1000–A nowhere uses the term ‘‘formula
rate’’ to describe the rule’s treatment of
regional cost allocation methodologies,
it is creating a filing regimen where the
27 Id.
P 286.
28 Id.
29 Id.
30 Id.
P 287.
31 Transmission Access Policy Study Group at 3.
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cost allocation methodologies will
function as just that.32
15. Therefore, Transmission Access
Policy Study Group contends that the
Commission should require the section
205 filing of project-specific
applications of the regional cost
allocation methodology, or leave it to
the compliance filing process to
determine whether such a filing is
required.33 If cost allocation methods
are treated as formula rates,
Transmission Access Policy Study
Group maintains that the Commission
can have no reasonable assurance that
cost allocation methodologies will be
sufficiently specific, grounded in
objective criteria, and otherwise
adequately constrain utility
discretion.34 It further asserts that
regional cost allocation methodologies,
in combination with the process for
selecting projects for regional cost
allocation, will likely rely on
assumptions and other judgments that
undermine predictability.35
16. Transmission Access Policy Study
Group argues that sole reliance on
section 206 to challenge specific
implementation of a Commissionaccepted Order No. 1000 methodology
when the transmission provider has not
made a section 205 filing is
unjustified.36 It contends that in the
non-RTO context, application of the cost
allocation methodology leaves ample
room for transmission providers to
engage in undue discrimination, and the
Commission cannot reasonably assume
that the cost allocation methodology, by
itself, will in all cases provide
customers with ‘‘notice’’ as to how
regional facilities will be selected, and
their costs allocated, in the future.37 It
also contends that transmission
providers have the enhanced ability to
discriminate, particularly where a cost
allocation methodology is unlikely to
have the specificity and objectivity to
cabin the transmission provider’s
discretion, and where stakeholders only
may have the opportunity to provide
input that the transmission providers
are free to ignore.38 It argues that, in
these cases in particular, treating the
cost allocation methodology as a
formula rate improperly shifts the
burdens imposed by section 205.39
17. Transmission Access Policy Study
Group argues that, at minimum, the
32 Id.
at 4.
at 5.
34 Id. at 6.
35 Id. at 7.
36 Id.
37 Id. at 7–8.
38 Id. at 8.
39 Id.
33 Id.
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Commission should defer making a
generic finding now that section 206 is
the only available recourse to challenge
specific applications of regional cost
allocation methodologies absent
transmission providers electing to
propose section 205 filings of those
specific applications.40 Instead, it
suggests that the Commission should
leave for determination on a case-bycase basis the process of evaluating
Order No. 1000 compliance filings, in
response to requests by transmission
providers or other stakeholders or on its
own motion, whether in a particular
region the filing of specific applications
of the regional cost allocations is
necessary.41 It maintains that deferral
will enable the Commission to consider
the specifics of the proposed regional
cost allocation methodology in
conjunction with the proposed project
selection process and associated
governance and other safeguards (if
any), as well as the views of public
utility transmission providers in that
region and other stakeholders.42
c. Commission Determination
18. We deny rehearing. Transmission
Access Policy Study Group has not
persuaded us that the determination not
to require the filing of specific
applications of the cost allocation
method was in error. Order No. 1000’s
reforms are intended, in part, to
establish an open and transparent
transmission planning process and
require transmission planning regions to
adopt a cost allocation method or
methods that provide ex ante certainty.
Both the Order No. 1000 compliance
process and the resulting Commissionapproved regional transmission
planning process and associated cost
allocation method(s) are required to
have built-in mechanisms to help
ensure that the processes and cost
allocation methods are in fact
transparent and provide the certainty
that Transmission Access Policy Study
Group seeks.
19. First, stakeholders have had the
opportunity to participate fully in
regional stakeholder meetings to
advocate for a cost allocation method
that provides the ex ante certainty that
Order No. 1000 seeks, as well as to
advocate that public utility transmission
providers include a provision requiring
the filing of specific applications of the
cost allocation method. We believe that
this approach accords with the regional
flexibility we provided in Order No.
1000 for public utility transmission
40 Id.
at 9.
41 Id.
42 Id.
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providers and stakeholders in a
transmission planning region to develop
rules that meet the transmission needs
of that region, consistent with the
requirements and principles set forth in
Order Nos. 1000 and 1000–A.
20. Second, the Commission will
carefully consider the Order No. 1000
compliance filings once they are
submitted, as well as any protests filed
by stakeholders, to ensure that
proposals satisfy the requirements that
regional transmission planning
processes be open and transparent and
that the cost allocation method or
methods satisfy the Order No. 1000 cost
allocation principles. If a filing is
deficient, the Commission will require
public utility transmission providers to
file revisions to address those
deficiencies.
21. Third, once the regional
transmission planning process is
approved by the Commission and
becomes effective, the Order No. 890
transmission planning principles, as
incorporated into a regional
transmission planning process in
compliance with Order No. 1000, will
help mitigate concerns about the
transparency of the process and the
application of the cost allocation
method. These principles address,
among other things, stakeholder
participation, information exchange,
and dispute resolution.43 By
incorporating these principles into the
regional transmission planning process,
the Commission’s expectation is that
there will be increased openness and
certainty concerning how beneficiaries
of transmission facilities selected in the
regional transmission plan for purposes
of cost allocation will be determined, as
well as internal processes to resolve any
questions that might arise as part of this
process. And as noted in Order No.
1000–A, in identifying the benefits and
beneficiaries for a new transmission
facility, the regional transmission
planning process must provide entities
who will receive regional or
interregional cost allocation an
understanding of the identified benefits
on which the cost allocation is based, all
of which would occur prior to the
43 Order No. 890 requires transmission providers
to disclose to all customers and other stakeholders
the basic criteria, assumptions, and data that
underlie their transmission system plans. In
addition, transmission providers will be required to
reduce to writing and make available the basic
methodology, criteria, and processes they use to
develop their transmission plans, including how
they treat retail native loads, in order to ensure that
standards are consistently applied. Preventing
Under Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats.
& Regs. ¶ 31,241 at P 471 (2007).
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recovery of such costs through a formula
rate.44
22. Moreover, as we explained in
Order No. 1000–A, stakeholders always
have the option of filing a section 206
complaint if they believe that,
notwithstanding these protections, there
was an incorrect application of the cost
allocation method in a particular
instance.45 Finally, if stakeholders
believe that the previously approved
cost allocation method itself is no longer
just and reasonable, they also have the
option of filing a section 206 complaint
with respect to the cost allocation
method.
23. Transmission Access Policy Study
Group suggests that application of the
ex ante cost allocation to, or in,
particular instance(s) should require a
section 205 filing with the Commission.
Order No. 1000 establishes no new
requirement with respect to this issue.
As we note above, Order No. 1000–A
stated that we would consider proposals
that would require public utility
transmission providers to file specific
applications of the cost allocation
method. Therefore, Order No. 1000
provides flexibility in this regard and
the Commission stated that it will not
prejudge any method before the
compliance filings are filed, so long as
they satisfied the cost allocation
principles articulated in Order No. 1000
(with the exception that participant
funding may not be the regional or
interregional cost allocation method).
We will carefully evaluate compliance
filings to ensure that they satisfy these
principles.
24. Transmission Access Policy Study
Group asserts that if the cost allocation
method is thought of as a formula rate,
it would improperly shift the burdens
under section 205 of the FPA, especially
where a cost allocation method is
unlikely to have specificity or
objectivity to cabin transmission
providers’ discretion and where they
can ignore stakeholder input. We
disagree with this argument. As we
discuss above, Order No. 1000 provides
for ex ante certainty. In Order No. 1000,
the Commission stated that it required
the development of regional and
interregional cost allocation methods to
provide greater certainty as to the cost
allocation implications of a potential
transmission project.46 The Commission
also stated that under the regional
transmission planning and interregional
transmission coordination requirements,
public utility transmission providers
44 Order
No. 1000–A, 139 FERC ¶ 61,132 at P 746.
P 231.
46 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at PP 559, 579.
45 Id.
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with stakeholders will identify,
evaluate, and determine which
transmission facilities meet the region’s
needs, and apply the cost allocation
method or methods associated with
those transmission facilities.47 In Order
No. 1000–A, the Commission clarified
that public utility transmission
providers must consult with
stakeholders in developing both
regional and interregional cost
allocation methods.48 Therefore, the
Commission specifically requires public
utility transmission providers to provide
the opportunity for stakeholder input in
the development of the regional and
interregional cost allocation methods. If
a stakeholder believes that its input is
being ignored, it has the right to raise its
issues with the cost allocation method
or methods when the relevant Order No.
1000 compliance filing is made, or in a
separate section 206 filing.
25. We also disagree with
Transmission Access Policy Study
Group’s argument that the use of a cost
allocation method could result in
burden shifting under section 205.
Order No. 1000–A acknowledged that
stakeholder participation is an
important aspect of the development of
compliance filings to meet the
requirements of Order No. 1000, and
should ensure that the cost allocation
method or methods ultimately agreed
upon is balanced and does not favor any
particular entity.49 Additionally, the
Commission clarified that the
Commission’s cost allocation
requirements do not interfere with
section 205 rights or otherwise impose
an undue burden on parties to
participate in a new and costly process,
but rather build on the reforms to the
transmission planning process required
by Order No. 890, in which all
interested parties should already be
participating.50 As noted above, the
regional transmission planning process
must provide entities who will receive
regional or interregional cost allocation
an understanding of the identified
benefits on which the cost allocation
will be based.51 Compliance proposals
submitted by transmission providers
will be reviewed by the Commission to
ensure they provide the upfront
certainty required by Order No.
1000.52 To the extent that Transmission
47 Id.
P 499.
PP 559, 579.
49 Order No. 1000–A, 139 FERC ¶ 61,132 at P 637.
50 Id. P 649.
51 Id. P 746.
52 As Transmission Access Policy Study Group
also recognizes, not all RTOs make section 205
filings for the application of an existing filed cost
allocation methodology. See Transmission Access
Policy Study Group at n.14. Transmission Access
48 Id.
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Access Policy Study Group is concerned
about cost recovery issues rather than
cost allocation, Order No. 1000
explained that such questions are
beyond the scope of the generic
rulemaking proceeding, and Order No.
1000–A affirmed this, but clarified that
public utility transmission providers, in
consultation with stakeholders, may
choose to address this cost recovery
matter in their compliance filings.53
26. We do not believe that
Transmission Access Policy Study
Group has justified at this time its
position that public utility transmission
providers in non-RTO regions, at least,
should be required to file specific
applications of the cost allocation
method. Again, as discussed above, our
expectation is that the open and
transparent transmission planning
process and principle-based cost
allocation method will provide
stakeholders with clarity as to why and
how costs are being allocated for any
specific transmission facility selected in
the regional transmission plan for
purposes of cost allocation. This is true
regardless of whether or not the
transmission planning region is an ISO/
RTO. As we also discuss above, the
Commission will carefully evaluate
compliance proposals and any resulting
protests to ensure that the proposals
meet the requirements of Order No.
1000.
27. Finally, with respect to
Transmission Access Policy Study
Group’s request that we defer a
determination on using section 206 as
the default mechanism to challenge a
cost allocation proposal, references to
section 206 in Order No. 1000–A were
to remind stakeholders of their right
under that provision to file complaints.
In any event, as we have previously
explained, Order No. 1000–A provides
that public utility transmission
providers in a transmission planning
region, in consultation with
stakeholders, could agree to require the
filing of specific applications of the cost
allocation method. The Commission
will review any such requirement
during the Order No. 1000 compliance
filings process and make a decision
based on the record before us.
Policy Study Group has not justified its position
that this will be an issue in non-ISO/RTO regions
at this time. Again, the Commission will carefully
evaluate compliance filings, as well as protests
thereto, to ensure that they satisfy Order No. 1000’s
requirements, and the Commission will require
changes if they fail to do so.
53 Order No. 1000–A, 139 FERC ¶ 61,132 at P 616.
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3. Consideration of Transmission Needs
Driven by Public Policy Requirements
a. Order No. 1000–A
28. Order No. 1000–A affirmed Order
No. 1000’s requirement that public
utility transmission providers amend
their OATTs to provide for the
consideration of transmission needs
driven by Public Policy Requirements.54
In affirming this requirement, Order No.
1000–A provided clarifications
regarding the definition of the term
‘‘Public Policy Requirements’’ 55 and
what it means to ‘‘consider’’
transmission needs driven by such
requirements.56 Order No. 1000–A
explained that the Commission intends
that public utility transmission
providers consider transmission needs
driven by Public Policy Requirements
just as they consider transmission needs
driven by reliability or economic
concerns.57 Further, the Commission
stated that it does not intend public
utility transmission providers to
substitute their policy judgments for
those of legislatures and regulators.58
Order No. 1000–A also explained that
the Commission does not require that
regional transmission plans support
multiple likely power supply scenarios,
although such a requirement could be
proposed in Order No. 1000 compliance
filings and the Commission would
consider such a proposal.59
b. Request for Clarification
29. AEP requests clarification that an
appropriate method for a region to
consider transmission needs driven by
Public Policy Requirements is to
expressly include consideration of
changes in resources and load driven by
public policies as part of its baseline
projection of changes in resources and
load expected over the planning
horizon, and then conduct reliability
and congestion analyses to determine
what transmission investments are
optimal given those expected changes in
resources and load.60 AEP argues that
54 Order No. 1000–A, 139 FERC ¶ 61,132 at PP
317–339. See also id. PP 203–216 (affirming legal
basis of requirement to consider transmission needs
driven by Public Policy Requirements).
55 Order No. 1000 defined ‘‘Public Policy
Requirements’’ as public policy requirements
established by state or federal laws and regulations.
Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P
2. Order No. 1000–A clarified that this term
included duly enacted laws or regulations passed
by a local governmental entity, such as a municipal
or county government. Order No. 1000–A, 139
FERC ¶ 61,132 at P 319.
56 Order No. 1000–A, 139 FERC ¶ 61,132 at PP
320–325.
57 Id. P 205.
58 Id. PP 326–29.
59 Id. P 331.
60 AEP at 5.
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64895
Public Policy Requirements should not
be considered solely on a stand-alone
basis in the planning process.61 It
contends that generation or load
changes driven by public policies
should be factored into the scenarios,
along with other anticipated resource
and load changes, for which reliability
and economic benefits analyses are
performed.62
30. AEP states that it is concerned that
some transmission providers may seek
to satisfy the Commission’s public
policy requirement by employing only a
stand-alone process or procedures that
are specifically designed to evaluate
transmission needs driven by Public
Policy Requirements.63 It argues that
regional planning processes should
consider reliability, economic, and
policy-driven transmission needs
together.64 In particular, AEP asserts
that a region should consider what
changes in generation resources and
load it expects over the planning
horizon, including consideration of
changes driven by public policies (such
as renewable portfolio standards, new
environmental regulations, and demand
side management programs), and then
conduct reliability and congestion
analyses to determine what
transmission investments are optimal
given these anticipated changes.65 It
contends that this approach enables
transmission providers to build upon
existing planning processes for the
reliability and economic analyses used
to identify baseline reliability and
economic projects.66 AEP argues that
integrated consideration of public
policy-driven requirements can factor
into efficient decisions to accelerate a
needed baseline reliability upgrade or
increase the capacity of a baseline
reliability upgrade or baseline economic
upgrade.67
c. Commission Determination
31. We grant AEP’s request for
clarification to the extent discussed
below. Order No. 1000 requires public
utility transmission providers to revise
their OATTs to provide for the
consideration of transmission needs
driven by Public Policy Requirements.68
In Order No. 1000, the Commission
61 Id.
at 2.
62 Id.
63 Id.
at 4.
64 Id.
65 Id.
66 Id.
67 Id.
68 The requirement to consider transmission
needs driven by Public Policy Requirements is
described in more detail in Order No. 1000, FERC
Stats. & Regs. ¶ 31,323 at PP 203–222 and Order
No. 1000–A, 139 FERC ¶ 61,132 at PP 317–339.
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provides for regional flexibility so that
public utility transmission providers, in
consultation with stakeholders, can
design proposals addressing this
requirement that they believe best meet
the needs of their respective
transmission planning regions, so long
as those proposals satisfy the essential
requirement that public utility
transmission providers, in consultation
with stakeholders, consider
transmission needs driven by Public
Policy Requirements as set forth in
Order No. 1000 and clarified in Order
No. 1000–A.69 The Commission
anticipates that a variety of approaches
could satisfy the Commission’s
requirements and we expect that
stakeholders supporting such proposals
would have the opportunity to advocate
for them in the stakeholder processes
leading to the Order No. 1000
compliance filings. The Commission
will consider any such approaches in
the compliance filings when they are
submitted for review.70
B. Nonincumbent Transmission
Developers
32. In Order No. 1000, the
Commission addressed the removal
from Commission-jurisdictional tariffs
and agreements of provisions that
contain a federal right of first refusal to
construct transmission facilities selected
in a regional transmission plan for
purposes of cost allocation. The
Commission also adopted a framework
that requires the development of
qualification criteria and protocols to
govern the submission and evaluation of
proposals for transmission facilities by
public utility transmission providers in
the regional transmission planning
process. The Commission further
required that a nonincumbent
transmission developer of a
transmission facility selected in the
regional transmission plan for purposes
of cost allocation have an opportunity
comparable to that of an incumbent
transmission developer to allocate the
cost of such transmission facility
through a regional cost allocation
method or methods.71
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69 See,
e.g., Order No. 1000–A, 139 FERC ¶ 61,132
at P 331 (‘‘It may well be the case that evaluating
different power supply scenarios will be an
effective way to identify more efficient or costeffective transmission solutions; however, we will
not prescribe any such requirements here,
consistent with our preference for regional
flexibility in designing regional transmission
planning processes.’’).
70 See id.
71 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 225.
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1. Legal Authority
a. Order No. 1000–A
33. In Order No. 1000–A, the
Commission affirmed its conclusion in
Order No. 1000 that it has the legal
authority under section 206 of the FPA
to require the elimination of federal
rights of first refusal as practices that
have the potential to lead to
Commission-jurisdictional rates that are
unjust and unreasonable or unduly
discriminatory or preferential.72 The
Commission stated that, consistent with
its authority under section 206, the
Commission acted to remedy an unjust
and unreasonable or unduly
discriminatory or preferential practice
by requiring public utility transmission
providers to eliminate a federal right of
first refusal from Commissionjurisdictional tariffs and agreements and
adopt the nonincumbent reforms. The
Commission explained that in Order No.
1000, it had found that a federal right of
first refusal applicable to transmission
facilities selected in a regional
transmission plan for purposes of cost
allocation can lead to rates for
Commission-jurisdictional services that
are unjust and unreasonable or
otherwise result in undue
discrimination by public utility
transmission providers.73
34. Finally, the Commission affirmed
its decision in Order No. 1000 to
address arguments that an individual
contract contains a federal right of first
refusal that is protected by a MobileSierra provision when it reviews the
compliance filings made by public
utility transmission providers.74
Consistent with Order No. 1000, the
Commission explained that a public
utility transmission provider that
considers its contract to be protected by
a Mobile-Sierra provision may present
its arguments as part of its compliance
filing. However, the Commission also
clarified that any such compliance filing
must include the revisions to any
Commission-jurisdictional tariffs and
agreements necessary to comply with
Order No. 1000 as well as the MobileSierra provision arguments.75 The
Commission concluded that this
approach ensures that public utility
transmission providers would not be
required to eliminate a federal right of
first refusal before the Commission
makes a determination regarding
whether an agreement is protected by a
Mobile-Sierra provision and whether the
Commission has met the applicable
72 Order
No. 1000–A, 139 FERC ¶ 61,132 at P 357.
P 360.
74 Id. P 388.
75 Id. P 389.
73 Id.
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standard of review, while at the same
time ensuring that the Order No. 1000
compliance process proceeds
expeditiously and efficiently.
b. Requests for Rehearing and
Clarification
35. Oklahoma Gas and Electric
Company argues that the Commission
failed to support its assertion that
provisions that designate incumbent
utilities to construct new transmission
facilities are unduly discriminatory or
preferential, or cause rates to be
unreasonably high.76 Oklahoma Gas and
Electric Company further argues that the
Commission cannot support a finding
that the current transmission rules in
the Southwest Power Pool result in rates
that are unjust or unreasonable.77
36. Oklahoma Gas and Electric
Company also argues that the
Commission ignores that the MobileSierra standard is a threshold question
and that the Commission cannot shift
the burden of proof to the contracting
parties to propose an alternative until
the Commission has answered.78
Oklahoma Gas and Electric Company
asserts that, under section 206 of the
Federal Power Act, the Commission
must first prove that the existing rates
or practices are unjust, unreasonable,
unduly discriminatory or preferential,
and that courts have repeatedly held
that the Commission has no power to
force public utilities to file particular
rates unless it first finds the existing
filed rates unlawful.79 Oklahoma Gas
and Electric Company asserts that this
two-step process is even more vital in
the context of applying the MobileSierra doctrine because the Commission
must presume that the rate set out in a
freely negotiated wholesale-energy
contract meets the just and reasonable
requirement imposed by law.80
Accordingly, Oklahoma Gas and Electric
Company argues that the Commission
has no power to require parties to
renegotiate and revise existing
agreements unless it finds harm to the
public interest.81
c. Commission Determination
37. We disagree with Oklahoma Gas
and Electric Company that the
76 Oklahoma
Gas and Electric Company at 4.
77 Id.
78 Id.
at 8.
at 8–9 (citing Atlantic City Elec. Co. v.
FERC, 295 F.3d 1, 10 (D.C. Cir. 2002); Complex
Consol. Edison Co. of New York, Inc. v. FERC, 165
F.3d 992, 1001 (D.C. Cir. 1999); Transmission
Access Policy Study Group v. FERC, 225 F.3d 667,
688 (D.C. Cir. 2005)).
80 Id. at 9 (citing NRG Power Marketing, LLC v.
Maine Public Utilities Commission, 130 S. Ct. 693,
700 (2010)).
81 Id. at 9–10.
79 Id.
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Commission failed to support its
determination that a federal right of first
refusal for transmission facilities
selected in a regional transmission plan
for purposes of cost allocation may lead
to Commission-jurisdictional rates that
are unjust and unreasonable or unduly
discriminatory or preferential.
Specifically, the Commission found that
a federal right of first refusal has ‘‘the
potential to undermine the
identification and evaluation of more
efficient or cost-effective solutions to
regional transmission needs, which in
turn can result in rates for Commissionjurisdictional services that are unjust
and unreasonable or otherwise result in
undue discrimination by public utility
transmission providers.’’ 82 The
Commission further explained the direct
effect that a federal right of first refusal
can have on Commission-jurisdictional
rates in Order No. 1000–A, stating that:
the selection of transmission facilities in a
regional transmission plan for purposes of
cost allocation is directly related to costs that
will be allocated to jurisdictional ratepayers.
The ability of an incumbent transmission
provider to discourage or preclude
participation of new transmission developers
through discriminatory rules in a regional
transmission planning process, and in
particular, the inclusion of a federal right of
first refusal, can have the effect of limiting
the identification and evaluation of potential
solutions to regional transmission needs.
This in turn can directly increase the cost of
new transmission development that is
recovered from jurisdictional customers
through rates.83
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38. The Commission put forth several
rationales to support its
determination.84 In particular, the
Commission noted that the Federal
Trade Commission supported the
Commission’s conclusion that a federal
right of first refusal can create a barrier
to entry that discourages nonincumbent
transmission developers from proposing
alternative solutions for consideration at
the regional level.85 In addition, the
Commission stated that it is not in the
economic self-interest of incumbent
transmission providers to permit new
entrants to develop transmission
facilities, even if proposals submitted by
new entrants would result in a more
efficient or cost-effective solution to the
region’s needs.86 Thus, the Commission
concluded that it has a reasonable
82 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 253.
83 Order No. 1000–A, 139 FERC ¶ 61,132 at P 358
(citations omitted).
84 Id. P 76.
85 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 257; see Order No. 1000–A, 139 FERC ¶ 61,132
at P 76.
86 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 256.
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expectation that expanding the universe
of transmission developers offering
potential solutions to regional needs can
lead to the identification and evaluation
of potential solutions that are more
efficient or cost-effective.87
39. Furthermore, as the Commission
explained in the Need for Reform
section of Order No. 1000–A, the
Commission is not required to make
individual findings concerning the rates
of individual public utility transmission
providers when proceeding under FPA
section 206 by means of a generic rule.88
Rather, the Commission can proceed by
identifying a ‘‘theoretical threat’’ that
would materialize and cause rates to be
unjust and unreasonable, or unduly
discriminatory or preferential.89 As
discussed in the preceding paragraph,
the Commission found that a federal
right of first refusal has the potential to
lead to rates for Commissionjurisdictional services that are unjust
and unreasonable or otherwise unduly
discriminatory.
40. In response to Oklahoma Gas and
Electric Company’s arguments regarding
the Mobile-Sierra doctrine, we reiterate
that the Commission is not requiring
public utility transmission providers to
eliminate a federal right of first refusal
before the Commission makes a
determination regarding whether an
agreement is protected by the MobileSierra doctrine and whether the
Commission has met the applicable
standard of review. As the Commission
clarified in Order No. 1000–A, the
Commission will first decide, based on
a more complete record, including
viewpoints of other interested parties,
whether an agreement is protected by
the Mobile-Sierra doctrine, and if so,
whether the Commission has met the
applicable standard of review such that
it can require the modification of the
particular agreement.90 If the
Commission determines based on the
record submitted in the compliance
filing that an agreement is protected by
the Mobile-Sierra doctrine and that it
cannot meet the applicable standard of
review, then the Commission will not
consider whether the revisions to the
Commission-jurisdictional tariffs and
agreements submitted by a public utility
transmission provider that considers its
agreement to be protected by the MobileSierra doctrine comply with Order No.
1000.91
87 Order No. 1000–A, 139 FERC ¶ 61,132 at PP
77, 83.
88 Id. P 56.
89 Id. P 57.
90 Id. P 389.
91 Id.
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64897
2. Requirement To Remove a Federal
Right of First Refusal From
Commission-Jurisdictional Tariffs and
Agreements, and Limits on the
Applicability of That Requirement
a. Order No. 1000–A
41. In Order No. 1000–A, the
Commission affirmed its decision in
Order No. 1000 to require the
elimination of a federal right of first
refusal from Commission-jurisdictional
tariffs and agreements for transmission
facilities selected in a regional
transmission plan for purposes of cost
allocation.92 The Commission also
clarified certain terms used in Order No.
1000. For instance, the Commission
clarified that the term ‘‘selected in a
regional transmission plan for purposes
of cost allocation’’ excludes a new
transmission facility if the costs of that
facility are borne entirely by the public
utility transmission provider in whose
retail distribution service territory or
footprint that new transmission facility
is to be located.93
42. The Commission stated that in
general, any regional cost allocation of
the cost of a new transmission facility
outside a single transmission provider’s
retail distribution service territory or
footprint, including an allocation to a
‘‘zone’’ consisting of more than one
transmission provider, is an application
of the regional cost allocation method
and that new transmission facility is not
a local transmission facility.94 As an
example, the Commission stated that
transmission owning members of an
RTO may not retain a federal right of
first refusal by dividing the RTO into
East and West multi-utility zones and
allocating costs just within one zone
consisting of more than one
transmission provider.95 The
Commission also stated that it will
address whether a cost allocation to a
multi-transmission provider zone is
regional on a case-by-case basis based
on the specific facts presented. The
Commission explained that there may
be a continuum of examples that range
from (i) one small municipality with a
single small transmission facility
located within a transmission provider’s
footprint, to (ii) a ‘‘zone’’ consisting of
many public utility and nonpublic
utility transmission providers.
Accordingly, the Commission stated
that public utility transmission
providers may include specific
situations in their compliance filings
along with the filed regional cost
92 Id.
P 415.
P 423.
94 Id. P 424.
95 Id.
93 Id.
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allocation method or methods.96 The
Commission clarified that if any costs of
a new transmission facility are allocated
regionally or outside of a public utility
transmission provider’s retail
distribution service territory or
footprint, there can be no federal right
of first refusal associated with such
transmission facility, except as provided
in Order Nos. 1000 and 1000–A.97
b. Requests for Rehearing and
Clarification
43. Petitioners seek rehearing of the
Commission’s determination in Order
No. 1000–A that a transmission facility
is considered selected in a regional
transmission plan for purposes of cost
allocation if any of the costs of that
facility are allocated outside of the
public utility transmission provider’s
retail distribution service territory or
footprint.98 MISO Transmission Owners
Group 2 argues that under a reasonable
interpretation of Order No. 1000, a
transmission provider may retain its
right of first refusal if a transmission
facility is not selected in a regional
transmission plan for purposes of cost
allocation as a more efficient or costeffective solution to regional needs but
instead was selected to primarily
address local needs.99 MISO
Transmission Owners Group 2 states
that not all projects included in the
regional transmission plan for which
some costs are allocated outside of an
individual utility’s footprint are ‘‘a more
efficient or cost-effective solution to
regional transmission needs,’’ such as
projects constructed to meet compliance
with state service obligations or where
the most efficient or cost-effective
solution may not be in-service in time
to satisfy reliability criteria and the
decision to include the project in the
plan is made primarily on the basis of
reliability.100
44. MISO Transmission Owners
Group 2 argues, however, that
statements in Order No. 1000–A suggest
that the decision regarding whether a
facility is more efficient or cost-effective
is irrelevant to determining whether the
requirement to remove federal rights of
first refusal would apply.101 MISO
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96 Id.
97 Id. P 430. For example, the Commission does
not require an incumbent transmission provider to
eliminate a federal right of first refusal for upgrades
to its own transmission facilities. Order No. 1000,
FERC Stats. & Regs. ¶ 31,323 at P 319.
98 See, e.g. MISO Transmission Owners Group 2
and Oklahoma Gas and Electric Company.
99 MISO Transmission Owners Group 2 at 12–13.
100 Id. at 14–15 (citing Order No. 1000–A, 139
FERC ¶ 61,132 at P 430).
101 Id. at 13–14 (citing Order No. 1000–A, 139
FERC ¶ 61,132 at P 430 (‘‘if any costs of a new
transmission facility are allocated regionally or
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Transmission Owners Group 2 argues
that the Commission cites no record
evidence or argument in favor of
broadening the definition of
transmission facilities selected in a
regional transmission plan for purposes
of cost allocation.102 Accordingly, MISO
Transmission Owners Group 2 asks for
the Commission to clarify that, in order
for the requirement to eliminate the
federal right of first refusal to apply, the
costs of a transmission facility must not
only be allocated outside of a
transmission owner’s retail distribution
service territory or footprint and the
transmission facility must have been
selected in the regional transmission
plan, but it also must be selected as a
more efficient or cost-effective solution
to regional transmission needs. The
MISO Transmission Owners Group
requests that the Commission clarify
that utilities may retain a right of first
refusal for projects that are selected
which may not be the ‘‘more efficient or
cost-effective solution to regional
transmission needs.’’ 103
45. MISO Transmission Owners
Group 2 also argues that eliminating the
ability of a transmission-owning
member of an RTO to construct and
allocate the costs of a local transmission
facility encourages free ridership by
providing an incentive for transmission
providers to keep cost allocation within
their retail distribution service territory
to retain a right of first refusal for local
transmission facilities, even when
entities outside of the retail distribution
service territory or footprint may receive
some benefit from such facilities despite
their primarily local nature.104
46. Oklahoma Gas and Electric
Company argues that a broader
definition of what constitutes regional
cost allocation prohibits transmission
planning regions from adopting
approaches they believe would
effectively allocate costs and fairly
balance stakeholder interests.105 For
instance, Oklahoma Gas and Electric
Company states that the Southwest
Power Pool allocates costs using a
Highway/Byway Plan.106 Oklahoma Gas
outside of a public utility transmission provider’s
retail distribution service territory or footprint, then
there can be no federal right of first refusal
associated with such transmission facility.’’)).
102 Id. at 18.
103 Id. at 15–19.
104 Id. at 19.
105 Oklahoma Gas and Electric Company at 6.
106 Id. (citing Southwest Power Pool, Inc., 131
FERC ¶ 61,252 (2010), reh’g denied, 137 FERC ¶
61,075 (2011)). Oklahoma Gas and Electric
Company states that the Southwest Power Pool
allocates: (1) 100% of the cost of a facility operating
at 300 kV or above across the region on a postage
stamp basis; (2) one-third of the cost of a facility
operating above 100 kV and below 300 kV on a
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and Electric Company asserts that the
Commission should ensure that the
Southwest Power Pool can retain its
Highway/Byway Plan for cost allocation
by designating lower voltage facilities as
local facilities for purposes of Order No.
1000.107
47. Some petitioners request that the
Commission clarify that projects with
costs allocated to a single zone should
be considered local, even if the zone
consists of more than one public utility
transmission provider, so that the public
utility transmission provider may retain
a federal right of first refusal.108 AEP
contends that the Commission’s
proposal to defer evaluation of multiutility zones until the compliance filing
stage does little to inform ongoing RTO
stakeholder processes tasked with
developing compliance filings.109 MISO
Transmission Owners Group 2 asserts
that the Commission failed to identify
any record evidence or argument for its
conclusion that transmission providers
located in multi-transmission provider
zones automatically lose their federal
rights of first refusal for all transmission
facilities.110
48. MISO Transmission Owners
Group 2 also argues that the
Commission’s stated concern that such
zones might be established to
circumvent Order No. 1000 is
misplaced.111 In support, MISO
Transmission Owners Group 2 asserts
that such zones were established prior
to the issuance of Order No. 1000 and
based on decades of cooperation and
collaboration among transmission
owners.112 In addition, MISO
Transmission Owners Group 2 argues
that the Commission’s distinction
between multi-transmission provider
zones and zones containing only one
transmission provider results in undue
discrimination against transmission
providers that happen to be located in
a multi-transmission provider zone.113
regional postage stamp basis and the remaining
two-thirds of the costs to the zone in which the
facility is located; and, (3) all the costs of a facility
operating at or under 100 kV to the zone in which
the facility is located. Id.
107 Id.
108 See, e.g., AEP and MISO Transmission Owners
Group 2.
109 AEP at 10–11. AEP cites as an example SPP’s
stakeholder process which at the time of AEP’s
request for clarification, was debating the
interpretation of the Commission’s intended
treatment of zones that have long included a single
large, traditional load-serving public utility, as well
as several small municipal or cooperative utilities
that are dependent on the transmission system of
the traditional public utility to serve their
respective loads.
110 MISO Transmission Owners Group 2 at 24.
111 Id. at 22.
112 Id.
113 Id. at 26.
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49. Oklahoma Gas and Electric
Company contends that the Commission
incorrectly claimed in Order No. 1000–
A that the scope of Order No. 1000 will
be limited. It asserts that, in response to
arguments that the requirement to
eliminate the right of first refusal is
beyond the Commission’s authority and
will materially alter the business of
public utilities, the Commission in
Order No. 1000–A emphasized that the
requirement did not extend to local
transmission facilities.114 Oklahoma Gas
and Electric Company asserts that based
on the discussion of zones in Order No.
1000–A, it may not be possible to build
a local facility under the Southwest
Power Pool tariff, making all new
construction subject to Order No.
1000.115 Similarly, MISO Transmission
Owners Group 2 contends that RTO
transmission-owning members lack
individual mechanisms for cost
allocation and recovery, and therefore
would have no ability to build and
recover the costs of local transmission
facilities as they are defined in Order
No. 1000.116
50. Oklahoma Gas and Electric
Company argues that because the
requirement to eliminate provisions that
designate incumbent utilities to
construct new transmission facilities is
not limited in scope, and does
materially alter the businesses of
transmission owning companies, the
Commission should find that there is no
sound basis to require that public utility
transmission providers remove such
provisions.117 In the alternative,
Oklahoma Gas and Electric Company
asserts that the Commission should
allow each region to define the scope of
local transmission projects that will not
be subject to the new rule.118
c. Commission Determination
51. On rehearing of Order No. 1000–
A, petitioners have raised two issues
related to Order No. 1000’s requirement
that public utility transmission
providers remove federal rights of first
refusal from Commission-jurisdictional
tariffs and agreements. First, some
petitioners seek rehearing of Order No.
1000–A’s determination that if any of
the costs of a new transmission facility
are allocated regionally or outside of a
public utility transmission provider’s
retail distribution service territory or
footprint, then there can be no federal
right of first refusal associated with such
transmission facility. Second, on
114 Oklahoma
Gas and Electric Company at 3–5.
at 5–6.
116 MISO Transmission Owners Group 2 at 23.
117 Oklahoma Gas and Electric Company at 7.
118 Id.
115 Id.
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rehearing some petitioners argue that
projects with costs allocated to a single
zone should be considered local, even if
there is more than one public utility
transmission provider located in that
zone, so that the public utility
transmission provider may retain a
federal right of first refusal under those
circumstances. We deny rehearing and
will discuss each of these issues in turn.
52. As noted above, the first issue we
address concerns requests for rehearing
of Order No. 1000–A’s determination
that if any costs of a new transmission
facility are allocated regionally or
outside of a public utility transmission
provider’s retail distribution service
territory or footprint, then there can be
no federal right of first refusal
associated with such transmission
facility, except as provided in Order
Nos. 1000 and 1000–A.119 Order No.
1000 requires that a federal right of first
refusal be removed for new transmission
facilities selected in a regional
transmission plan for purposes of cost
allocation. As noted above, the
Commission stated in Order No. 1000
that in general, if any costs of a new
transmission facility are allocated
regionally or outside a single
transmission provider’s retail
distribution service territory or
footprint, that is an application of the
regional cost allocation method and that
new transmission facility is not a local
transmission facility.120 Therefore, once
a new transmission facility is selected in
the regional transmission plan for
purposes of cost allocation, it is no
longer a local transmission facility
exempt from the requirements of Order
Nos. 1000 and 1000–A regarding the
removal of federal rights of first refusal.
For this reason, we deny rehearing on
this issue.
53. We note that neither Order No.
1000 nor Order No. 1000–A requires
elimination of a federal right of first
refusal in all circumstances.121 We also
note that the Commission recognized
that issuance of Order No. 1000 may
have occurred in the middle of a
transmission planning cycle for a
particular region and, therefore, directed
public utility transmission providers to
explain in their respective compliance
filings how they intend to implement
the requirements of the Final Rule.122
119 Order
No. 1000–A, 139 FERC ¶ 61,132 at P
430.
120 Id.
P 424 (emphasis added).
No. 1000, FERC Stats. & Regs. ¶ 31,323
at PP 318–319.
122 Id. P 162. See also id. P 65 (‘‘Our intent here
is that this Final Rule not delay current studies
being undertaken pursuant to existing regional
transmission planning processes or impede progress
on implementing existing transmission plans. We
121 Order
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Moreover, public utility transmission
providers are required to describe the
circumstances and procedures under
which public utility transmission
providers will reevaluate the regional
transmission plan to determine if delays
in the development of a transmission
facility selected in a regional
transmission plan for purposes of cost
allocation require evaluation of
alternative solutions, including those
proposed by the incumbent
transmission provider, to ensure the
incumbent transmission provider can
meet its reliability needs or service
obligations.123 We will evaluate
proposals related to these requirements
on review of compliance filings.
54. With respect to the second issue
raised by petitioners—whether a project
whose costs are allocated to a single
zone with multiple transmission owners
should be considered local and thus
permit a public utility transmission
provider to retain a federal right of first
refusal under these circumstances—the
Commission recognized in Order No.
1000–A that special consideration is
needed when a small transmission
provider is located within the footprint
of another transmission provider.124 The
Commission acknowledged that there is
a continuum of situations of multitransmission provider zones, but opted
to address such situations on
compliance. This acknowledgement
provides public utility transmission
providers who may have zonal
configurations, such as a zone with a
small municipality and one
transmission provider, or one with
many public utility and non-public
utility transmission providers, an
opportunity to address whether a cost
allocation to a multi-transmission
provider zone is regional on a case-bycase basis based on the specific facts
presented. We consider many of the
arguments related to multi-transmission
provider zones premature because the
Commission did not adopt a generic
rule as to whether a cost allocation
solely to a multi-transmission provider
zone is an application of the regional
cost allocation method for which a
direct public utility transmission providers to
explain in their compliance filings how they will
determine which facilities evaluated in their local
and regional planning processes will be subject to
the requirements of this Final Rule.’’).
123 Order No. 1000–A, FERC Stats. & Regs. ¶
31,132 at P 477. See also Order No. 1000, FERC
Stats. & Regs. ¶ 31,323 at P 329 (‘‘[A]n incumbent
transmission provider must have the ability to
propose solutions that it would implement within
its retail distribution service territory or footprint
that will enable it to meet its reliability needs or
service obligations.’’).
124 Order No. 1000–A, FERC Stats. & Regs. ¶
31,132 at P 424.
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federal right of first refusal must be
eliminated. Petitioners have not
presented evidence that would support
the Commission making a generic
finding or providing additional
guidance for all multi-transmission
provider zones in this rulemaking
proceeding. Therefore, on this second
issue, we find that the Commission’s
determination is a reasonable balance of
competing considerations that enables
the Commission to implement the
requirements of Order No. 1000 in a
manner that will achieve the goal of
improved transmission planning.
55. We therefore agree with
petitioners that the Commission’s
requirements have not entirely
eliminated opportunities for free
ridership. As evidenced by the multiple
comments and petitions the
Commission received in the Order No.
1000 proceedings, the Commission
balanced many competing interests in
determining how to best implement the
requirements of Order No. 1000. Some
presented their views of the advantages
of retaining a federal right of first refusal
for all new transmission facilities while
others presented their views of the
advantages of eliminating a federal right
of first refusal for all new transmission
facilities. The Commission has
considered the arguments raised by
petitioners on rehearing with respect to
both of the above-mentioned issues and
rejects petitioners’ requests for rehearing
as we find that the approach taken in
Order Nos. 1000 and 1000–A provides
the best balance of competing
considerations.
3. Framework To Evaluate Transmission
Projects Submitted for Selection in the
Regional Transmission Plan for
Purposes of Cost Allocation
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a. Evaluation of Proposals for Selection
in the Regional Transmission Plan for
Purposes of Cost Allocation
i. Order No. 1000–A
56. In Order No. 1000–A, the
Commission affirmed its decision in
Order No. 1000 to require each public
utility transmission provider to amend
its OATT to describe a transparent and
not unduly discriminatory process for
evaluating whether to select a proposed
transmission facility in a regional
transmission plan for purposes of cost
allocation.125 The Commission also
reiterated that there are many different
approaches to transmission planning
and that Order No. 1000 requires only
that the transmission planning process
adopted by a transmission planning
125 Order
No. 1000–A, 139 FERC ¶ 61,132 at P
452.
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region satisfy the transmission planning
principles discussed in Order Nos. 1000
and 1000–A. Accordingly, the
Commission declined to rule in the
abstract in advance of the compliance
filings whether any particular
transmission planning process is the
only appropriate process for all regions.
57. The Commission also continued to
emphasize that any qualification criteria
or process for selecting transmission
facilities in a regional transmission plan
for purposes of cost allocation must be
transparent and not unduly
discriminatory.126 Finally, the
Commission affirmed its decision that,
if a proposed transmission facility is
selected in a regional transmission plan
for purposes of cost allocation, then
Order No. 1000 requires that the
transmission developer of that
transmission facility (whether
incumbent or nonincumbent) must be
able to rely on the relevant cost
allocation method or methods within
the region should it move forward with
its transmission project.127 The
Commission also reiterated that it
would not require public utility
transmission providers in a region to
adopt a provision for ongoing
sponsorship rights, and pointed out that
in Order No. 1000, the Commission
concluded that granting transmission
developers an ongoing right to build
sponsored transmission projects could
adversely impact the regional
transmission planning process.128
Accordingly, the Commission in Order
No. 1000–A declined to reverse this
decision on the selection of
transmission developers.129
ii. Requests for Rehearing and
Clarification
58. AEP maintains that some regions
are considering a process in which third
parties (e.g., one or more states) select
the developer for a transmission project
after the regional planning entity has
identified needed transmission projects
in its regional transmission plan.130 AEP
asserts that leaving the selection of a
project developer to an entity other than
the regional planning body threatens to
lead to suboptimal results.131 It argues
that the decision as to which entity is
best suited to build a given transmission
126 Id.
PP 439, 452.
P 456; Order No. 1000, FERC Stats. & Regs.
¶ 31,323 at P 339.
128 Order No. 1000–A, 139 FERC ¶ 61,132 at P
456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 339.
129 Order No. 1000–A, 139 FERC ¶ 61,132 at P
456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 339.
130 AEP at 6.
131 Id. at 2.
127 Id.
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project necessarily relies on developer
qualifications as assessed by the
transmission provider, and on projected
benefits, which will vary among
developers.132 It contends that the
selection of the best transmission
solution for the region cannot be done
effectively without information about
the qualifications and the benefits
offered by the developer for the
project.133 Accordingly, AEP requests
that the Commission provide
clarification to discourage bifurcation of
the planning process.134
iii. Commission Determination
59. We decline to clarify in advance
of the compliance filings whether any
particular approach to the selection of a
transmission developer is a just and
reasonable and not unduly
discriminatory or preferential selection
process. Order No. 1000 requires public
utility transmission providers in a
region to adopt transparent and not
unduly discriminatory criteria for
selecting a new transmission project in
a regional transmission plan for
purposes of cost allocation.135 It also
requires that if a transmission project is
selected in a regional transmission plan
for purposes of cost allocation, the
transmission developer of that
transmission facility must be able to rely
on the relevant cost allocation method
or methods within the region should it
move forward with the transmission
project.136 However, the Commission
declined to otherwise address the
selection of a transmission developer on
a generic basis.137 We continue to
believe that it is not appropriate to
address in advance of the compliance
filings the process for selecting
transmission developers in greater
detail. Instead, we reaffirm the
flexibility that the Commission
provided to the public utility
transmission providers in each
transmission planning region to propose
a process for selecting transmission
developers in accordance with each
transmission planning region’s needs.138
C. Interregional Transmission
Coordination
60. In Order No. 1000, the
Commission required each public utility
132 Id.
at 6.
at 6–7.
134 Id. at 6.
135 E.g., Order No. 1000–A, 139 FERC ¶ 31,132 at
P 455.
136 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at PP 332, 339; see also Order No. 1000–A, 139
FERC ¶ 61,132 at P 456.
137 E.g., Order No. 1000–A, 139 FERC ¶ 61,132 at
P 455.
138 E.g., id.
133 Id.
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transmission provider, through its
regional transmission planning process,
to establish further procedures with
each of its neighboring transmission
planning regions for the purpose of: (1)
Coordinating and sharing the results of
respective regional transmission plans
to identify possible interregional
transmission facilities that could
address transmission needs more
efficiently or cost-effectively than
separate regional transmission facilities;
and (2) jointly evaluating such facilities,
as well as jointly evaluating those
transmission facilities that are proposed
to be located in more than one
transmission planning region.139 The
Commission also required each public
utility transmission provider, through
its regional transmission planning
process, to describe the methods by
which it will identify and evaluate
interregional transmission facilities and
to include a description of the type of
transmission studies that will be
conducted to evaluate conditions on
neighboring systems for the purpose of
determining whether interregional
transmission facilities are more efficient
or cost-effective than regional
facilities.140
1. Implementation of the Interregional
Transmission Coordination
Requirements
a. Procedure for Joint Evaluation
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i. Order No. 1000–A
61. In Order No. 1000–A, the
Commission reaffirmed Order No.
1000’s requirement that an interregional
transmission facility must be selected in
each relevant regional transmission plan
for purposes of cost allocation to be
eligible for cost allocation under the
interregional cost allocation method or
methods.141 The Commission explained
that Order No. 1000 establishes a closer
link between transmission planning and
cost allocation. Additionally, the
Commission stated that Order No. 1000
provides for stakeholder involvement in
the consideration of an interregional
transmission facility primarily through
the regional transmission planning
processes.142 The Commission
concluded that this requirement is
necessary to ensure that stakeholders
have an opportunity to provide
meaningful input with respect to
proposed interregional transmission
139 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 493.
140 Id.
141 Order No. 1000–A, 139 FERC ¶ 61,132 at P
509 (citing Order No. 1000, FERC Stats. & Regs. ¶
31,323 at P 436).
142 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 465; see also id. P 443.
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facilities before such facilities are
selected in each relevant regional
transmission plan for purposes of cost
allocation.143
62. Additionally, the Commission
acknowledged that, under the
interregional transmission coordination
procedures of Order No. 1000, an
interregional transmission facility is
unlikely to be selected for interregional
cost allocation unless each transmission
planning region benefits or the
transmission planning region that
benefits compensates the region that
does not through a separate agreement.
The Commission expressed its
continued belief that, under the regional
transmission planning approach
adopted in Order No. 1000, it is
appropriate for each transmission
planning region to determine for itself
whether to select in its regional
transmission plan for purposes of cost
allocation an interregional transmission
facility that extends partly within its
regional footprint based on the
information gained during the joint
evaluation of an interregional
transmission project.144
ii. Requests for Rehearing and
Clarification
63. AEP requests clarification that the
inclusion of an interregional project in
a regional plan need not be subject to
the same benefits tests that would be
applied to a single-region project, and
that a region may include an
interregional project in its plan if the
benefits to the region compare favorably
to the share of the costs that would be
borne by that region (as distinct from
the total project costs).145 Specifically, it
states that in determining the costs and
benefits of a proposed interregional
transmission project for the purposes of
the selection process, a regional
transmission planning entity should be
permitted to evaluate the benefits
provided to an affected region and
assume that a portion of the costs of the
project will be allocated to the affected
region.146 For example, if a $100 million
interregional project would have $180
million in benefits split evenly between
two adjacent regions, both regions
would find the project beneficial and
would include it in the regional plan, if
they assumed that one-half of the cost
would be borne by each region.147
143 Order
No. 1000–A, 139 FERC ¶ 61,132 at P
509.
144 Id.
P 512.
at 2, 7.
146 Id. at 8.
147 Id.
145 AEP
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iii. Commission Determination
64. Order No. 1000 did not specify
whether or how a regional or
interregional benefit-cost threshold
should be applied when selecting a
project in the regional transmission plan
for purposes of cost allocation, or which
costs should be included when
calculating a benefit-cost threshold to
use in this selection process. This was
to provide the opportunity for each
region to develop an appropriate
calculation, if it chose to use a threshold
at all. Therefore, we decline to clarify in
advance of the compliance filings how
a benefit-cost threshold should be
applied.
III. Cost Allocation
65. In Order No. 1000, the
Commission required that each public
utility transmission provider have in its
OATT a method, or set of methods, for
allocating the costs of new regional
transmission facilities selected in the
regional transmission plan for purposes
of cost allocation (‘‘regional cost
allocation’’); and that each public utility
transmission provider within two (or
more) neighboring transmission
planning regions develop a method, or
set of methods, for allocating the costs
of new interregional transmission
facilities that each of the two (or more)
neighboring transmission planning
regions selected for purposes of cost
allocation because such facilities would
resolve the individual needs of each
region more efficiently or costeffectively (‘‘interregional cost
allocation’’).148 The Commission
required that the OATTs of all public
utility transmission providers in a
region include the same cost allocation
method or methods adopted by the
region.149
66. The Commission also required
that regional and interregional cost
allocation methods each adhere to six
regional and interregional cost
allocation principles: (1) Costs must be
allocated in a way that is roughly
commensurate with benefits; (2) there
must be no involuntary allocation of
costs to non-beneficiaries; (3) a benefit
to cost threshold ratio cannot exceed
1.25; (4) costs must be allocated solely
within the transmission planning region
148 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at P 482. For purposes of Order No. 1000, a regional
transmission facility is a transmission facility
located entirely in one region. An interregional
transmission facility is one that is located in two
or more transmission planning regions. A
transmission facility that is located solely in one
transmission planning region is not an interregional
transmission facility. Id. P 482 n.374.
149 Order No. 1000–A, 139 FERC ¶ 61,132 at P
523.
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or pair of regions unless those outside
the region or pair of regions voluntarily
assume costs; (5) there must be a
transparent method for determining
benefits and identifying beneficiaries;
and (6) there may be different methods
for different types of transmission
facilities.150 The Commission directed
that, subject to these general cost
allocation principles, public utility
transmission providers in consultation
with stakeholders would have the
opportunity to agree on the appropriate
cost allocation methods for their new
regional and interregional transmission
facilities, subject to Commission
approval.151 The Commission also
found that if public utility transmission
providers in a region or pair of regions
could not agree, the Commission would
use the record in the relevant
compliance filing proceeding(s) as a
basis to develop a cost allocation
method or methods that meets the
Commission’s requirements.152 Finally,
the Commission emphasized that its
cost allocation requirements are
designed to work in tandem with its
transmission planning requirements to
identify more appropriately the benefits
and the beneficiaries of new
transmission facilities so that
transmission developers, planners and
stakeholders can take into account in
the transmission planning process who
would bear the costs of transmission
facilities, if constructed.153
1. Cost Allocation Principle 2—No
Involuntary Allocation of Costs to NonBeneficiaries
a. Order Nos. 1000 and 1000–A
67. In Order No. 1000, the
Commission adopted the following Cost
Allocation Principle 2 for both regional
and interregional cost allocation:
Regional Cost Allocation Principle 2:
Those that receive no benefit from
transmission facilities, either at present or in
a likely future scenario, must not be
involuntarily allocated any of the costs of
those transmission facilities.
and
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Interregional Cost Allocation Principle 2: A
transmission planning region that receives no
benefit from an interregional transmission
facility that is located in that region, either
at present or in a likely future scenario, must
not be involuntarily allocated any of the costs
of that transmission facility.154
68. The Commission also required
that every cost allocation method or
150 Order
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b. Requests for Rehearing or
Clarification
71. Organization of MISO States
argues that the Commission erred in
paragraph 690 of Order No. 1000–A
when it concluded that if a project or
group of projects is shown to have
benefits in any one of the transmission
planning scenarios studied by a public
utility transmission provider in its
planning process, then the conditions
for satisfaction of Cost Allocation
Principle 2 will be determined to have
been met. It contends that, in response
to ITC Companies’ request for
clarification, the Commission stated that
a ‘‘likely future scenario’’ that would
justify an allocation of costs for new
transmission facilities includes the
transmission planning scenarios being
used by a transmission provider to
prepare a regional transmission plan.157
155 Id.
No. 1000, FERC Stats. & Regs. ¶ 31,323
at PP 622–693.
151 Id. P 588.
152 Id. P 482.
153 Id. P 483.
154 Id. P 637.
VerDate Mar<15>2010
methods provide for allocation of the
entire prudently incurred cost of a
transmission project to prevent stranded
costs.155
69. On rehearing, the Commission
affirmed Order No. 1000’s adoption of
Regional and Interregional Cost
Allocation Principle 2. The Commission
explained that scenario analysis is a
common feature of electric power
system planning, and that it believed
that public utility transmission
providers are in the best position to
apply it in a way that achieves
appropriate results in their respective
transmission planning regions.156 The
Commission also found that the use of
‘‘likely future scenarios’’ would not
expand the class of customers who
would be identified as beneficiaries
because it is limited to scenarios in
which a beneficiary is identified as such
on the basis of the cost causation
principle.
70. The Commission clarified that
public utility transmission providers
may rely on scenario analyses in the
preparation of a regional transmission
plan and the selection of new
transmission facilities for cost allocation
purposes. If a project or group of
projects is shown to have benefits in one
or more of the transmission planning
scenarios identified by public utility
transmission providers in their
Commission-approved Order No. 1000compliant cost allocation methods,
Principle 2 would be satisfied.
P 640.
156 Id.
157 Organization of MISO States at 2 (quoting
Order No. 1000–A, 139 FERC ¶ 61,132 at P 690 (‘‘If
a project or group of projects is shown to have
benefits in one or more of the transmission
planning scenarios identified by public utility
transmission providers in their Commission-
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Fmt 4700
Sfmt 4700
Organization of MISO States is
concerned that the Commission’s
clarification reads out of Principle 2 the
concept of the likelihood of a future
scenario by suggesting that Principle 2
would be satisfied if benefits are shown
under any scenario studied by the
transmission provider in its planning
process.158 Accordingly, Organization of
MISO States requests that the
Commission clarify that its discussion
in paragraph 690 of Order No. 1000–A
only applies to likely future scenarios as
required by Principle 2.
c. Commission Determination
72. We clarify that in finding that Cost
Allocation Principle 2 would be
satisfied if a project or group of projects
is shown to have benefits in one or more
of the transmission planning scenarios
identified by public utility transmission
providers in their Commissionapproved Order No. 1000-compliant
cost allocation methods, we did not
intend to remove the ‘‘likely future
scenarios’’ concept from transmission
planning. We believe the evaluation of
likely future scenarios can be an
important factor in public utility
transmission providers’ consideration of
transmission projects and in the
identification of beneficiaries consistent
with the cost causation principle.
IV. Information Collection Statement
73. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain information
collection requirements imposed by an
agency.159 The revisions in Order Nos.
1000 and 1000–A to the information
collection requirements were approved
under OMB Control No. 1902–0233.
While this order provides clarification,
it does not modify any information
collection requirements. Accordingly, a
copy of this order will be sent to OMB
for informational purposes only.
V. Document Availability
74. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the Internet through the
Commission’s Home Page (http://
www.ferc.gov) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m.
Eastern time) at 888 First Street NE.,
Room 2A, Washington, DC 20426.
75. From the Commission’s Home
Page on the Internet, this information is
approved Order No. 1000-compliant cost allocation
methods, Principle 2 would be satisfied.’’)).
158 Id.
159 5 CFR 1320.11.
E:\FR\FM\24OCR1.SGM
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Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations
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.
76. User assistance is available for
eLibrary and the Commission’s Web site
during normal business hours from
FERC Online Support at 202–502–6652
(toll free at 1–866–208–3676) or email at
ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. Email the
Public Reference Room at
public.referenceroom@ferc.gov.
VI. Effective Date
77. Changes to Order Nos. 1000 and
1000–A made in this order on rehearing
and clarification will be effective on
November 23, 2012.
64903
By the Commission. Commissioner
LaFleur is dissenting in part with a
separate statement. Commissioner Clark
is not participating.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Note: The following appendices will not be
published in the Code of Federal
Regulations.
APPENDIX A: ABBREVIATED NAMES OF PETITIONERS
Abbreviation
Petitioner names
AEP .............................................
MISO
Transmission
Owners
Group 2.
American Electric Power Service Corporation.
The Midwest ISO Transmission Owners for this filing consist of: Ameren Services Company, as agent for
Union Electric Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois and
Ameren Transmission Company of Illinois; City Water, Light & Power (Springfield, IL); Dairyland Power Cooperative; Great River Energy; Hoosier Energy Rural Electric Cooperative, Inc.; Indianapolis Power & Light
Company; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P);
Montana-Dakota Utilities Co.; Northern Indiana Public Service Company; Northern States Power Company,
a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of
Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Southern Illinois
Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a Vectren Energy Delivery of Indiana);
Southern Minnesota Municipal Power Agency; and Wolverine Power Supply Cooperative, Inc.
Oklahoma Gas and Electric Company.
Oklahoma Gas and Electric Company.
Organization of MISO States ......
Transmission
Access
Study Group.
Policy
Illinois Commerce Commission; Indiana Utility Regulatory Commission; Iowa Utilities Board; Kentucky Public
Service Commission; Michigan Public Service Commission; Minnesota Public Utilities Commission; Missouri Public Service Commission; Wisconsin Public Service Commission; and Montana Public Service
Commission.
Transmission Access Policy Study Group.
TKELLEY on DSK3SPTVN1PROD with RULES
LaFLEUR, Commissioner, dissenting
in part:
As part of today’s order, the Commission
affirms its holding in Order No. 1000–A that
an incumbent transmission provider may not
retain a federal right of first refusal (ROFR)
for a new transmission project—even a local
reliability project—if that project receives
any amount of regional funding.1 After
further consideration, I believe this decision
is premature and denies transmissionplanning regions the flexibility to define
local projects. I am now persuaded that the
Commission should have deferred judgment
on this issue until compliance, where it
could have evaluated—on a case-by casebasis—proposals to define local projects in
light of the principles underlying elimination
of the ROFR and the requirement that costs
must be allocated in a manner that is at least
roughly commensurate with benefits.
Because I would grant rehearing on this
point, and defer the issue to compliance, I
respectfully dissent in part from today’s
order.
In Order No. 1000, the Commission
eliminated the ROFR for projects ‘‘selected in
a regional transmission plan for purposes of
cost allocation’’ but allowed it to continue for
1 Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public
Utilities, Order No. 1000, 76 FR 49842 (Aug. 11,
2011), FERC Stats. & Regs. ¶ 31,323 (2011), order
on reh’g, Order No. 1000–A, 77 FR 32184 (May 31,
2012), 139 FERC ¶ 61,132 at P 430 (2012).
VerDate Mar<15>2010
17:17 Oct 23, 2012
Jkt 229001
local projects.2 In response, certain
petitioners requested guidance as to whether
the requirement to remove the ROFR for
projects ‘‘selected in a regional transmission
plan for purposes of cost allocation’’ required
eliminating it in two specific situations: First,
when costs are allocated only to multiple
transmission providers within a single, local
zone; and second, when local reliability
projects receive some amount of regional
funding as part of a cost allocation
methodology.3 In essence, petitioners
requested clarification as to whether these
specific cost allocation mechanisms
converted otherwise local reliability projects
to regional projects for purposes of
eliminating the ROFR.
With respect to the question about zones,
in Order No. 1000–A the Commission
acknowledged that ‘‘there may be a
continuum of examples’’ that require fact
specific determinations.4 Rather than lay
down a categorical rule, the Commission
opted for flexibility and invited parties to
raise their specific situations on compliance.5
Today’s order affirms this approach.
2 Order No. 1000, FERC Stats. & Regs. ¶ 31,323
at PP 313, 318; see also P 63 (defining local
projects).
3 Order No. 1000–A, 139 FERC ¶ 61,132 at PP
409–410; see also n. 495 (examples of cost
allocation methodologies reflecting distinctions
between regional and local projects that were
previously approved by the Commission.).
4 Id. P 424.
5 Id.
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In contrast, in Order 1000–A the
Commission did reach a definitive
conclusion with respect to whether any
amount of regional funding converts an
otherwise local reliability project in to a
regional project for purposes of the ROFR.
The Commission clarified, without
explanation,6 that the ROFR must be
eliminated if a project receives any amount
of regional funding.7 As a result, a local
reliability project that receives any amount of
regional funding, no matter how small, is no
longer local for purposes of the ROFR.
Today’s order summarily affirms this
decision.
After further consideration, I believe the
Commission acted prematurely in concluding
that any amount of regional funding converts
an otherwise local reliability project to a
regional project for purposes of the ROFR. By
reaching this conclusion in the abstract,
without the benefit of considering
stakeholder-vetted proposals to define local
projects in light of the principles underlying
elimination of the ROFR and the requirement
that costs must be allocated in a manner that
is at least roughly commensurate with
6 For example, the Commission did not explain,
in light of its distinction in Order No, 1000 between
projects in a regional plan and projects ‘‘selected in
a regional transmission plan for purposes of cost
allocation,’’ why eliminating the ROFR for projects
‘‘selected in a regional transmission plan for
purposes of cost allocation’’ requires eliminating it
for local projects that are primarily locally funded.
7 Id. P 430.
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64904
Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations
benefits, the Commission has denied
transmission planning regions the flexibility
it wisely acknowledged to be necessary with
respect to the zone issue. I agree with SPP
and OGE that we should provide that
flexibility.8
In Order No. 1000, the Commission
balanced many competing policy
considerations in an effort to adopt the
reforms necessary to assure just and
reasonable rates.9 This balance may be most
pronounced in the Commission’s efforts to
ensure that the regional planning process is
broad, inclusive, and fair, while at the same
time, mindful of the obligations and
attributes of incumbent transmission
providers. The Commission also went to
great lengths to provide transmissionplanning regions with the flexibility to
negotiate cost allocation methodologies that
allocate costs in a manner that they believe
is at least roughly commensurate with
benefits. Where the mutual achievement of
these objectives raises complex questions, as
it does with respect to whether any amount
of regional funding converts an otherwise
local reliability project in to a regional
project for purposes of the ROFR, the
Commission should decide the issue on
compliance, with a record, rather than by
establishing categorical rules that may
undermine the planning and cost allocation
goals Order No. 1000 was intended to
achieve.10
Accordingly, I respectfully dissent in part.
lllllllllllllllllllll
Cheryl A. LaFleur,
Commissioner.
[FR Doc. 2012–26111 Filed 10–23–12; 8:45 am]
TKELLEY on DSK3SPTVN1PROD with RULES
BILLING CODE 6717–01–P
8 In its request for clarification of Order 1000–A,
SPP seeks guidance on how to reconcile the
definitions and principles underlying Order No.
1000 with the Commission’s summary
determination in Order No. 1000–A that any
amount of regional funding for local reliability
projects requires elimination of the ROFR. See SPP
Request for Clarification at 7–16. Unlike my
colleagues, I believe that SPP’s filing may properly
be characterized as a request for clarification, and
therefore, should be addressed in this order.
However, I would not reach the merits of SPP’s
arguments. Instead, I would grant rehearing on the
grounds that the Commission should have deferred
deciding the issue until compliance and invite SPP
to make its arguments on compliance.
9 Order 1000–B at P 55.
10 See e.g. OGE Request for Rehearing at 6 (‘‘[T]he
broad definition of what constitutes regional cost
allocation would prohibit regional entities such as
SPP from adopting approaches they believe would
effectively allocate costs and fairly balance
stakeholder interests.’’).
VerDate Mar<15>2010
17:17 Oct 23, 2012
Jkt 229001
DEPARTMENT OF HOMELAND
SECURITY
Coast Guard
33 CFR Part 165
[Docket Number USCG–2012–0741]
A. Regulatory History and Information
On August 21, 2012, the Coast Guard
published a Notice of Proposed
Rulemaking (NPRM) (33 FR 50444). We
received no comments on the proposed
rule. No public meeting was requested,
and none was held.
B. Basis and Purpose
RIN 1625–AA00
Safety Zone, Atlantic Intracoastal
Waterway; Carolina Beach, NC
Coast Guard, DHS.
Temporary final rule.
AGENCY:
ACTION:
The Coast Guard is
establishing a temporary safety zone on
the waters of the Atlantic Intracoastal
Waterway at Carolina Beach, North
Carolina. The safety zone is necessary to
provide for the safety of mariners on
navigable waters during maintenance on
the U.S. 421 Fixed Bridge crossing the
Atlantic Intracoastal Waterway, mile
295.6, at Carolina Beach, North
Carolina. The safety zone will
temporarily restrict vessel movement
within the designated area starting on
December 20, 2012, through October 31,
2013.
DATES: This rule is effective from
December 20, 2012, until October 31,
2013.
SUMMARY:
Documents mentioned in
this preamble are part of docket [USCG–
2012–0741]. To view documents
mentioned in this preamble as being
available in the docket, go to http://
www.regulations.gov, type the docket
number in the ‘‘SEARCH’’ box and click
‘‘SEARCH.’’ Click on Open Docket
Folder on the line associated with this
rulemaking. You may also visit the
Docket Management Facility in Room
W12–140 on the ground floor of the
Department of Transportation West
Building, 1200 New Jersey Avenue SE.,
Washington, DC 20590, between 9 a.m.
and 5 p.m., Monday through Friday,
except Federal holidays.
FOR FURTHER INFORMATION CONTACT: If
you have questions on this rule, call or
email CWO4 Joseph M. Edge, U.S. Coast
Guard Sector North Carolina; telephone
252–247–4525, email
Joseph.M.Edge@uscg.mil. If you have
questions on viewing or submitting
material to the docket, call Renee V.
Wright, Program Manager, Docket
Operations, telephone (202) 366–9826.
SUPPLEMENTARY INFORMATION:
ADDRESSES:
Table of Acronyms
DHS Department of Homeland Security
FR Federal Register
NPRM Notice of Proposed Rulemaking
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Fmt 4700
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North Carolina Department of
Transportation has awarded a contract
to American Bridge Company of
Virginia Beach, Virginia to perform
bridge maintenance on the U.S. 421
Fixed Bridge crossing the Atlantic
Intracoastal Waterway, mile 295.6, at
Carolina Beach, North Carolina. The
contract provides for cleaning, painting,
and steel repair to commence on
December 20, 2012 with a completion
date of October 31, 2013. The contractor
will utilize a 40 foot by 60 foot sectional
barge as a work platform and for
equipment staging. This safety zone will
provide a safety buffer to transiting
vessels as bridge repairs present
potential hazards to mariners and
property due to reduction horizontal
clearance. During this period the Coast
Guard will require a one hour
notification to the work supervisor for
passage through the U.S. 421 Fixed
Bridge along the Atlantic Intracoastal
Waterway, mile 295.6, Carolina Beach,
North Carolina. The bridge notification
requirement will apply during the
maintenance period for vessels
requiring a horizontal clearance of
greater than 60 feet.
C. Discussion of Comments, Changes
and the Final Rule
We received no comments on the
proposed rule. No public meeting was
requested, and none was held.
The temporary safety zone will
encompass the waters directly under the
U.S. 421 Fixed Bridge crossing the
Atlantic Intracoastal Waterway, mile
295.6, at Carolina Beach, North Carolina
(34°03′21″ N, 077°53′58″ W). All vessels
transiting this section of the waterway
requiring a horizontal clearance of
greater than 60 feet will be required to
make a one hour advanced notification
to the work supervisor while the safety
zone is in effect. This zone will be in
effect from 8 a.m. December 20, 2012
through 8 p.m. October 31, 2013.
D. Regulatory Analyses
We developed this rule after
considering numerous statutes and
executive orders related to rulemaking.
Below we summarize our analyses
based on these statutes and executive
orders.
E:\FR\FM\24OCR1.SGM
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]]>Agencies
[Federal Register Volume 77, Number 206 (Wednesday, October 24, 2012)]
[Rules and Regulations]
[Pages 64890-64904]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-26111]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM10-23-002; Order No. 1000-B]
Transmission Planning and Cost Allocation by Transmission Owning
and Operating Public Utilities
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Order on rehearing and clarification.
-----------------------------------------------------------------------
SUMMARY: The Federal Energy Regulatory Commission affirms its basic
determinations in Order Nos. 1000 and 1000-A, amending the transmission
planning and cost allocation requirements established in Order No. 890
to ensure that Commission-jurisdictional services are provided at just
and reasonable rates and on a basis that is just and reasonable and not
unduly discriminatory or preferential. This order affirms the Order No.
1000 transmission planning reforms that: Require that each public
utility transmission provider participate in a regional transmission
planning process that produces a regional transmission plan; provide
that local and regional transmission planning processes must provide an
opportunity to identify and evaluate transmission needs driven by
public policy requirements established by state or federal laws or
regulations; improve coordination between neighboring transmission
planning regions for new interregional transmission facilities; and
remove from Commission-approved tariffs and agreements a federal right
of first refusal. This order also affirms the Order No. 1000
requirements that each public utility transmission provider must
participate in a regional transmission planning process that has: A
regional cost allocation method for the cost of new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation and an interregional cost allocation method for the
cost of new transmission facilities that are located in two neighboring
transmission planning regions and are jointly evaluated by the two
regions in the interregional transmission coordination process required
by this Final Rule. Additionally, this order affirms the Order No. 1000
requirement that each cost allocation method must satisfy six cost
allocation principles.
DATES: Effective November 23, 2012.
FOR FURTHER INFORMATION CONTACT:
Melissa Nimit, Federal Energy Regulatory Commission, Office of the
General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502-
6638.
Shiv Mani, Federal Energy Regulatory Commission, Office of Energy
Policy and Innovation, 888 First Street NE., Washington, DC 20426,
(202) 502-8240.
SUPPLEMENTARY INFORMATION:
Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, and Cheryl A. LaFleur.
Issued October 18, 2012
Table of Contents
Paragraph
No.
I. Introduction............................................. 1
II. Transmission Planning................................... 5
A. Regional Transmission Planning....................... 5
1. Role of Section 217(b)(4) of the Federal Power 6
Act................................................
2. Regional Transmission Planning Requirements...... 12
3. Consideration of Transmission Needs Driven by 28
Public Policy Requirements.........................
B. Nonincumbent Transmission Developers................. 32
1. Legal Authority.................................. 33
2. Requirement To Remove a Federal Right of First 41
Refusal from Commission-Jurisdictional Tariffs and
Agreements, and Limits on the Applicability of That
Requirement........................................
3. Framework To Evaluate Transmission Projects 56
Submitted for Selection in the Regional
Transmission Plan for Purposes of Cost Allocation..
C. Interregional Transmission Coordination.............. 60
1. Implementation of the Interregional Transmission 61
Coordination Requirements..........................
III. Cost Allocation........................................ 65
1. Cost Allocation Principle 2--No Involuntary 67
Allocation of Costs to Non-beneficiaries...............
IV. Information Collection Statement........................ 73
V. Document Availability.................................... 74
[[Page 64891]]
VI. Effective Date.......................................... 77
Appendix A: Abbreviated Names of Petitioners ..........
I. Introduction
1. In Order No. 1000,\1\ the Commission amended the transmission
planning and cost allocation requirements established in Order No. 890
\2\ to ensure that the rates, terms and conditions of service provided
by public utility providers are just and reasonable and not unduly
discriminatory or preferential. Order No. 1000's transmission planning
reforms require: (1) Each public utility transmission provider to
participate in a regional transmission planning process that produces a
regional transmission plan; (2) that local and regional transmission
planning processes must provide an opportunity to identify and evaluate
transmission needs driven by public policy requirements established by
state or federal laws or regulations; (3) improved coordination between
neighboring transmission planning regions for new interregional
transmission facilities; and (4) the removal from Commission-approved
tariffs and agreements of a federal right of first refusal.
---------------------------------------------------------------------------
\1\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 76 FR 49842
(Aug. 11, 2011), FERC Stats. & Regs. ] 31,323 (2011), order on
reh'g, Order No. 1000-A, 139 FERC ] 61,132 (2012).
\2\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007),
FERC Stats. & Regs. ] 31,241, order on reh'g, Order No. 890-A, 73 FR
2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261 (2007), order on
reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8,
2008), 123 FERC ] 61,299 (2008), order on reh'g, Order No. 890-C, 74
FR 12540 (Mar. 25, 2009), 126 FERC ] 61,228 (2009), order on
clarification, Order No. 890-D, 74 FR 61511 (Nov. 25 2009), 129 FERC
] 61,126 (2009).
---------------------------------------------------------------------------
2. Order No. 1000 also requires that each public utility
transmission provider must participate in a regional transmission
planning process that has: (1) A regional cost allocation method for
the cost of new transmission facilities selected in a regional
transmission plan for purposes of cost allocation and (2) an
interregional cost allocation method for the cost of new transmission
facilities that are located in two neighboring transmission planning
regions and are jointly evaluated by the two regions in the
interregional transmission coordination process required by this Final
Rule. Order No. 1000 also requires that each cost allocation method
must satisfy six cost allocation principles.
3. In Order No. 1000-A, the Commission largely affirmed the reforms
adopted in Order No. 1000. The Commission concluded that taken
together, the reforms adopted in Order No. 1000 will ensure that
Commission-jurisdictional services are provided at just and reasonable
rates and on a basis that is just and reasonable and not unduly
discriminatory or preferential. The Commission therefore rejected
requests to eliminate, or substantially modify, the various reforms
adopted in Order No. 1000. The Commission did however, make a number of
clarifications.
4. Several petitioners have sought further rehearing and
clarification of the Commission's determinations in Order No. 1000-
A.\3\ The Commission largely affirms the determinations reached in
Order No. 1000-A, making clarifications to address matters raised by
petitioners.
---------------------------------------------------------------------------
\3\ A list of petitioners filing requests for rehearing and/or
clarification is provided in Appendix A. Southwest Power Pool (SPP)
filed a request for clarification and/or reconsideration of Order
No. 1000-A. While SPP denominates its pleading as a request for
clarification, it is, in fact, a late-filed request for rehearing.
Pursuant to section 313(a) of the Federal Power Act (FPA), 16 U.S.C.
825l(a) (2006), an aggrieved party must file a request for rehearing
within thirty days after the issuance of the Commission's order.
Because the 30-day rehearing deadline is statutory, it cannot be
extended, and SPP's request for rehearing must be rejected as
untimely. Moreover, the courts have repeatedly recognized that the
time period within which a party may file an application for
rehearing of a Commission order is statutorily established at 30
days by section 313(a) of the FPA and that the Commission has no
discretion to extend that deadline. See, e.g., City of Campbell v.
FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985); Boston Gas Co. v. FERC,
575 F.2d 975, 977-79 (1st Cir. 1978). Furthermore, we note that the
issues raised by SPP are similar to those raised by other
petitioners, which are summarized and addressed below in section
II.B.2 of this order.
---------------------------------------------------------------------------
II. Transmission Planning
A. Regional Transmission Planning
5. Order No. 1000 built on the reforms adopted in Order No. 890 to
improve regional transmission planning. First, Order No. 1000 required
each public utility transmission provider to participate in a regional
transmission planning process that produces a regional transmission
plan and complies with existing Order No. 890 transmission planning
principles.\4\ Second, Order No. 1000 adopted reforms under which
transmission needs driven by Public Policy Requirements are considered
in local and regional transmission planning processes.\5\ The
Commission explained that these reforms work together to ensure that
public utility transmission providers in every transmission planning
region, in consultation with stakeholders, evaluate proposed
alternative solutions at the regional level that may resolve the
region's needs more efficiently or cost-effectively than solutions
identified in the local transmission plans of individual public utility
transmission providers.\6\ The Commission noted that, as in Order No.
890, the transmission planning requirements in Order No. 1000 do not
address or dictate which transmission facilities should be either in
the regional transmission plan or actually constructed, and that such
decisions are left in the first instance to the judgment of public
utility transmission providers, in consultation with stakeholders
participating in the regional transmission planning process.\7\
---------------------------------------------------------------------------
\4\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 68.
\5\ Id. The Commission explained that Public Policy Requirements
are those established by state or federal laws or regulations,
meaning enacted statutes (i.e., passed by the legislature and signed
by the executive) and regulations promulgated by a relevant
jurisdiction, whether within a state or at the federal level. Id. P
2. Order No. 1000-A clarified that this included transmission needs
driven by local laws or regulations. Order No. 1000-A, 139 FERC ]
61,132 at P 319.
\6\ Id.
\7\ Id. P 68 n.57.
---------------------------------------------------------------------------
1. Role of Section 217(b)(4) of the Federal Power Act
a. Order No. 1000-A
6. In Order No. 1000-A, the Commission affirmed Order No. 1000's
conclusion that the Commission has ample legal authority under the
Federal Power Act (FPA) to undertake its regional transmission planning
reforms. Among other things, Order No. 1000-A rejected arguments that
FPA section 217(b)(4) \8\ prohibits or otherwise limits the
Commission's ability to undertake these reforms.\9\ Order No. 1000-A
---------------------------------------------------------------------------
\8\ 16 U.S.C. 824s (2006).
\9\ Order No. 1000-A, 139 FERC ] 61,132 at PP 168-179.
---------------------------------------------------------------------------
[[Page 64892]]
acknowledged claims by some petitioners that Order No. 681,\10\ which
requires transmission organizations that are public utilities with
organized electricity markets to make available long-term firm
transmission rights that satisfy certain guidelines, expressly notes a
preference for load-serving entities.\11\ Order No. 1000-A found that
Order No. 681's priority for load-serving entities in the allocation of
long-term firm transmission rights supported by existing transmission
capacity is not inconsistent with Order No. 1000, which addresses
planning and cost allocation for new transmission.\12\ Order No. 1000-A
also found that the transmission planning reforms will aid, and not
hinder, load-serving entities in meeting their reasonable transmission
needs.\13\
---------------------------------------------------------------------------
\10\ Long-Term Firm Transmission Rights in Organized Electricity
Markets, Order No. 681, FERC Stats. & Regs. ] 31,226, order on
reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006), order on reh'g,
Order No. 681-B, 126 FERC ] 61,254 (2009).
\11\ Order No. 1000-A, 139 FERC ] 61,132 at P 171.
\12\ Id. P 172.
\13\ Id.
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b. Request for Rehearing
7. Transmission Access Policy Study Group argues that in Order No.
1000-A, the Commission suggested for the first time that the preference
for load-serving entity long-term rights established in Order No. 681
applies only to existing transmission capacity ``but not in the broader
context of planning new transmission capacity.'' \14\ Transmission
Access Policy Study Group contends that the Commission erred in
suggesting that Order No. 681 does not apply to new transmission
facilities, contending that Order No. 681 extended the preference to be
afforded load-serving entities to long-term rights from existing
capacity to new capacity by providing that ``[w]hen * * * transmission
upgrades [that are rolled into transmission rates] come into service,
the transmission rights that result from such investments will be made
available as rights from `existing capacity.' '' \15\ Transmission
Access Policy Study Group states that this provision had one limited
exception--where a transmission upgrade is participant-funded.\16\ It
contends that this exception is inapplicable to the new transmission
facilities at issue in this proceeding, as Order No. 1000 specifically
ruled that participant funding will not comply with the regional or
interregional cost allocation principles adopted by the Final Rule.\17\
Transmission Access Policy Study Group urges the Commission to clarify
that Order Nos. 1000 and 1000-A do not alter the scope or applicability
of Order No. 681.\18\ In the alternative, it argues that Order No. 1000
should be reversed to the extent that it modifies the load-serving
entity long-term rights preference established by Order No. 681, by
limiting that preference to ``existing'' transmission facilities,
rather than extending it to new transmission that is not participant-
funded.\19\
---------------------------------------------------------------------------
\14\ Transmission Access Policy Study Group at 12 (quoting Order
No. 1000-A, 139 FERC ] 61,132 at P 171).
\15\ Id. at 13 (quoting Order No. 681, FERC Stats. & Regs. ]
31,226 at P 211 (emphasis added)).
\16\ Id.
\17\ Id.
\18\ Id.
\19\ Id.
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c. Commission Determination
8. In response to Transmission Access Policy Study Group, we
clarify that nothing in either Order No. 1000 or Order No. 1000-A is
intended in any way to undermine or alter the guidelines the Commission
instituted in Order No. 681. Order No. 1000's transmission planning
reforms are distinct from the Commission's rulemaking in Order No. 681,
as we explain below.
9. Section 1233(a) of the Energy Policy Act of 2005 enacted FPA
section 217(b)(4), in which the Commission is directed to exercise its
authority under the FPA in a manner that facilitates the planning and
expansion of transmission facilities to meet the reasonable needs of
load-serving entities to satisfy the service obligations of the load-
serving entities, and enables load-serving entities to secure firm
transmission rights (or equivalent tradable or financial rights) on a
long-term basis for long-term power supply arrangements made, or
planned, to meet such needs.\20\
---------------------------------------------------------------------------
\20\ 16 U.S.C. 824q(b)(4) (2006).
---------------------------------------------------------------------------
10. Section 1233(b) of the Energy Policy Act of 2005 further
directed the Commission to promulgate a rule on long-term transmission
rights in organized markets.\21\ The Commission consequently issued
Order No. 681, which adopted guidelines that independent system
operators (ISOs) and regional transmission organizations (RTOs) are
required to follow regarding the availability of long-term firm
transmission rights, including a guideline providing that load-serving
entities ``must have a priority over non-load serving entities in the
allocation of long-term firm transmission rights that are supported by
existing capacity.'' \22\
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\21\ EPAct 2005, Public Law 109-58, section 1233, 119 Stat. 594,
960 (2005); 16 U.S.C. 824q (2006)). Section 1233 provides that
within 1 year after the date of enactment of that section and after
notice and an opportunity for comment, the Commission shall by rule
or order, implement section 217(b)(4) of the Federal Power Act in
Transmission Organizations, as defined by that Act with organized
electricity markets.
\22\ Order No. 681, FERC Stats. & Regs. ] 31,226 at P 325.
---------------------------------------------------------------------------
11. As Order No. 1000-A explained, we do not find any inconsistency
between Order No. 1000 and section 217(b)(4).\23\ Nor do we find any
inconsistency between Order No. 1000 and Order No. 681. The
requirements adopted by the Commission in Order Nos. 1000 and 1000-A
are focused on the planning and cost allocation of new transmission
facilities, as defined therein. The Commission did not intend its
statements in Order No. 1000-A regarding the planning and cost
allocation of certain new transmission facilities to alter the
requirement in Order No. 681 that ``when [transmission upgrades that
are rolled into transmission rates] * * * come into service, the
transmission rights that result from such investments will be made
available as rights from `existing capacity' * * * . Prevailing cost
allocation rules will apply.'' \24\ Thus, we clarify for Transmission
Access Policy Study Group that nothing in Order Nos. 1000 or 1000-A
changes the requirements of Order No. 681, including the Order No. 681
established preference for load-serving entities in the allocation of
long-term firm transmission rights, and that the Commission did not
alter the application of Order No. 681 to new transmission facilities
that are subject to the requirements of Order No. 1000.
---------------------------------------------------------------------------
\23\ See Order No. 1000-A, 139 FERC ] 61,132 at PP 168-179
(addressing requests for rehearing and clarification of Order No.
1000 with respect to the role of section 217(b)(4)).
\24\ See Order No. 681, FERC Stats. & Regs. ] 31,226 at P 211.
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2. Regional Transmission Planning Requirements
a. Order No. 1000-A
12. Order No. 1000-A affirmed Order No. 1000's conclusion that
public utility transmission providers must revise their OATTs to
provide for a regional transmission planning process that produces a
regional transmission plan and satisfies Order No. 890's transmission
planning principles.\25\ The Commission explained that Order No. 1000
requires neither the filing of the regional transmission plan resulting
from the regional transmission planning process nor the filing of
specific applications of cost allocation determinations.\26\ With
respect to this latter point, Order No. 1000-A stated
[[Page 64893]]
that such a requirement would be unnecessary to comply with Order No.
1000, noting that Order No. 1000 requires that public utility
transmission providers have an ex ante cost allocation method on file
with and approved by the Commission. Order No. 1000-A also noted that
this cost allocation method must explain how the costs of new
transmission facilities selected in a regional transmission plan for
purposes of cost allocation are to be allocated, consistent with the
cost allocation principles set forth in Order No. 1000.\27\
Consequently, customers, stakeholders, and others will have ``notice''
at the time the compliance filings are made, when the Commission acts
on those filings, and as the regional transmission planning process
results in the selection of a transmission facility in the regional
transmission plan for purposes of cost allocation.\28\ However,
consistent with the regional flexibility provided in Order No. 1000,
Order No. 1000-A also concluded that public utility transmission
providers, in consultation with stakeholders, may propose OATT
revisions requiring the submission of cost allocations in their Order
No. 1000 compliance filings.\29\
---------------------------------------------------------------------------
\25\ Order No. 1000-A, 139 FERC ] 61,132 at PP 263-301.
\26\ Id. PP 285-286.
\27\ Id. P 286.
\28\ Id.
\29\ Id.
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13. The Commission further stated in Order No. 1000-A that it will
evaluate compliance filings to ensure that they comply with Order No.
1000 and that both stakeholders and the Commission have the right to
initiate actions under section 206 of the FPA if they believe that, for
example, a Commission-approved regional transmission planning process
was not followed or if a cost allocation method was not followed or
produced unjust and unreasonable results for a particular new
transmission facility or class of new transmission facilities.\30\
---------------------------------------------------------------------------
\30\ Id. P 287.
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b. Request for Rehearing
14. Transmission Access Policy Study Group argues that the
Commission should not establish a generic rule that, if transmission
providers elect not to propose a section 205 filing of specific
applications of their regional cost allocation, the only means to
challenge such applications is under section 206.\31\ It states that
although Order No. 1000-A nowhere uses the term ``formula rate'' to
describe the rule's treatment of regional cost allocation
methodologies, it is creating a filing regimen where the cost
allocation methodologies will function as just that.\32\
---------------------------------------------------------------------------
\31\ Transmission Access Policy Study Group at 3.
\32\ Id. at 4.
---------------------------------------------------------------------------
15. Therefore, Transmission Access Policy Study Group contends that
the Commission should require the section 205 filing of project-
specific applications of the regional cost allocation methodology, or
leave it to the compliance filing process to determine whether such a
filing is required.\33\ If cost allocation methods are treated as
formula rates, Transmission Access Policy Study Group maintains that
the Commission can have no reasonable assurance that cost allocation
methodologies will be sufficiently specific, grounded in objective
criteria, and otherwise adequately constrain utility discretion.\34\ It
further asserts that regional cost allocation methodologies, in
combination with the process for selecting projects for regional cost
allocation, will likely rely on assumptions and other judgments that
undermine predictability.\35\
---------------------------------------------------------------------------
\33\ Id. at 5.
\34\ Id. at 6.
\35\ Id. at 7.
---------------------------------------------------------------------------
16. Transmission Access Policy Study Group argues that sole
reliance on section 206 to challenge specific implementation of a
Commission-accepted Order No. 1000 methodology when the transmission
provider has not made a section 205 filing is unjustified.\36\ It
contends that in the non-RTO context, application of the cost
allocation methodology leaves ample room for transmission providers to
engage in undue discrimination, and the Commission cannot reasonably
assume that the cost allocation methodology, by itself, will in all
cases provide customers with ``notice'' as to how regional facilities
will be selected, and their costs allocated, in the future.\37\ It also
contends that transmission providers have the enhanced ability to
discriminate, particularly where a cost allocation methodology is
unlikely to have the specificity and objectivity to cabin the
transmission provider's discretion, and where stakeholders only may
have the opportunity to provide input that the transmission providers
are free to ignore.\38\ It argues that, in these cases in particular,
treating the cost allocation methodology as a formula rate improperly
shifts the burdens imposed by section 205.\39\
---------------------------------------------------------------------------
\36\ Id.
\37\ Id. at 7-8.
\38\ Id. at 8.
\39\ Id.
---------------------------------------------------------------------------
17. Transmission Access Policy Study Group argues that, at minimum,
the Commission should defer making a generic finding now that section
206 is the only available recourse to challenge specific applications
of regional cost allocation methodologies absent transmission providers
electing to propose section 205 filings of those specific
applications.\40\ Instead, it suggests that the Commission should leave
for determination on a case-by-case basis the process of evaluating
Order No. 1000 compliance filings, in response to requests by
transmission providers or other stakeholders or on its own motion,
whether in a particular region the filing of specific applications of
the regional cost allocations is necessary.\41\ It maintains that
deferral will enable the Commission to consider the specifics of the
proposed regional cost allocation methodology in conjunction with the
proposed project selection process and associated governance and other
safeguards (if any), as well as the views of public utility
transmission providers in that region and other stakeholders.\42\
---------------------------------------------------------------------------
\40\ Id. at 9.
\41\ Id.
\42\ Id. at 10.
---------------------------------------------------------------------------
c. Commission Determination
18. We deny rehearing. Transmission Access Policy Study Group has
not persuaded us that the determination not to require the filing of
specific applications of the cost allocation method was in error. Order
No. 1000's reforms are intended, in part, to establish an open and
transparent transmission planning process and require transmission
planning regions to adopt a cost allocation method or methods that
provide ex ante certainty. Both the Order No. 1000 compliance process
and the resulting Commission-approved regional transmission planning
process and associated cost allocation method(s) are required to have
built-in mechanisms to help ensure that the processes and cost
allocation methods are in fact transparent and provide the certainty
that Transmission Access Policy Study Group seeks.
19. First, stakeholders have had the opportunity to participate
fully in regional stakeholder meetings to advocate for a cost
allocation method that provides the ex ante certainty that Order No.
1000 seeks, as well as to advocate that public utility transmission
providers include a provision requiring the filing of specific
applications of the cost allocation method. We believe that this
approach accords with the regional flexibility we provided in Order No.
1000 for public utility transmission
[[Page 64894]]
providers and stakeholders in a transmission planning region to develop
rules that meet the transmission needs of that region, consistent with
the requirements and principles set forth in Order Nos. 1000 and 1000-
A.
20. Second, the Commission will carefully consider the Order No.
1000 compliance filings once they are submitted, as well as any
protests filed by stakeholders, to ensure that proposals satisfy the
requirements that regional transmission planning processes be open and
transparent and that the cost allocation method or methods satisfy the
Order No. 1000 cost allocation principles. If a filing is deficient,
the Commission will require public utility transmission providers to
file revisions to address those deficiencies.
21. Third, once the regional transmission planning process is
approved by the Commission and becomes effective, the Order No. 890
transmission planning principles, as incorporated into a regional
transmission planning process in compliance with Order No. 1000, will
help mitigate concerns about the transparency of the process and the
application of the cost allocation method. These principles address,
among other things, stakeholder participation, information exchange,
and dispute resolution.\43\ By incorporating these principles into the
regional transmission planning process, the Commission's expectation is
that there will be increased openness and certainty concerning how
beneficiaries of transmission facilities selected in the regional
transmission plan for purposes of cost allocation will be determined,
as well as internal processes to resolve any questions that might arise
as part of this process. And as noted in Order No. 1000-A, in
identifying the benefits and beneficiaries for a new transmission
facility, the regional transmission planning process must provide
entities who will receive regional or interregional cost allocation an
understanding of the identified benefits on which the cost allocation
is based, all of which would occur prior to the recovery of such costs
through a formula rate.\44\
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\43\ Order No. 890 requires transmission providers to disclose
to all customers and other stakeholders the basic criteria,
assumptions, and data that underlie their transmission system plans.
In addition, transmission providers will be required to reduce to
writing and make available the basic methodology, criteria, and
processes they use to develop their transmission plans, including
how they treat retail native loads, in order to ensure that
standards are consistently applied. Preventing Under Discrimination
and Preference in Transmission Service, Order No. 890, FERC Stats. &
Regs. ] 31,241 at P 471 (2007).
\44\ Order No. 1000-A, 139 FERC ] 61,132 at P 746.
---------------------------------------------------------------------------
22. Moreover, as we explained in Order No. 1000-A, stakeholders
always have the option of filing a section 206 complaint if they
believe that, notwithstanding these protections, there was an incorrect
application of the cost allocation method in a particular instance.\45\
Finally, if stakeholders believe that the previously approved cost
allocation method itself is no longer just and reasonable, they also
have the option of filing a section 206 complaint with respect to the
cost allocation method.
---------------------------------------------------------------------------
\45\ Id. P 231.
---------------------------------------------------------------------------
23. Transmission Access Policy Study Group suggests that
application of the ex ante cost allocation to, or in, particular
instance(s) should require a section 205 filing with the Commission.
Order No. 1000 establishes no new requirement with respect to this
issue. As we note above, Order No. 1000-A stated that we would consider
proposals that would require public utility transmission providers to
file specific applications of the cost allocation method. Therefore,
Order No. 1000 provides flexibility in this regard and the Commission
stated that it will not prejudge any method before the compliance
filings are filed, so long as they satisfied the cost allocation
principles articulated in Order No. 1000 (with the exception that
participant funding may not be the regional or interregional cost
allocation method). We will carefully evaluate compliance filings to
ensure that they satisfy these principles.
24. Transmission Access Policy Study Group asserts that if the cost
allocation method is thought of as a formula rate, it would improperly
shift the burdens under section 205 of the FPA, especially where a cost
allocation method is unlikely to have specificity or objectivity to
cabin transmission providers' discretion and where they can ignore
stakeholder input. We disagree with this argument. As we discuss above,
Order No. 1000 provides for ex ante certainty. In Order No. 1000, the
Commission stated that it required the development of regional and
interregional cost allocation methods to provide greater certainty as
to the cost allocation implications of a potential transmission
project.\46\ The Commission also stated that under the regional
transmission planning and interregional transmission coordination
requirements, public utility transmission providers with stakeholders
will identify, evaluate, and determine which transmission facilities
meet the region's needs, and apply the cost allocation method or
methods associated with those transmission facilities.\47\ In Order No.
1000-A, the Commission clarified that public utility transmission
providers must consult with stakeholders in developing both regional
and interregional cost allocation methods.\48\ Therefore, the
Commission specifically requires public utility transmission providers
to provide the opportunity for stakeholder input in the development of
the regional and interregional cost allocation methods. If a
stakeholder believes that its input is being ignored, it has the right
to raise its issues with the cost allocation method or methods when the
relevant Order No. 1000 compliance filing is made, or in a separate
section 206 filing.
---------------------------------------------------------------------------
\46\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 559,
579.
\47\ Id. P 499.
\48\ Id. PP 559, 579.
---------------------------------------------------------------------------
25. We also disagree with Transmission Access Policy Study Group's
argument that the use of a cost allocation method could result in
burden shifting under section 205. Order No. 1000-A acknowledged that
stakeholder participation is an important aspect of the development of
compliance filings to meet the requirements of Order No. 1000, and
should ensure that the cost allocation method or methods ultimately
agreed upon is balanced and does not favor any particular entity.\49\
Additionally, the Commission clarified that the Commission's cost
allocation requirements do not interfere with section 205 rights or
otherwise impose an undue burden on parties to participate in a new and
costly process, but rather build on the reforms to the transmission
planning process required by Order No. 890, in which all interested
parties should already be participating.\50\ As noted above, the
regional transmission planning process must provide entities who will
receive regional or interregional cost allocation an understanding of
the identified benefits on which the cost allocation will be based.\51\
Compliance proposals submitted by transmission providers will be
reviewed by the Commission to ensure they provide the upfront certainty
required by Order No. 1000.\52\
[[Page 64895]]
To the extent that Transmission Access Policy Study Group is concerned
about cost recovery issues rather than cost allocation, Order No. 1000
explained that such questions are beyond the scope of the generic
rulemaking proceeding, and Order No. 1000-A affirmed this, but
clarified that public utility transmission providers, in consultation
with stakeholders, may choose to address this cost recovery matter in
their compliance filings.\53\
---------------------------------------------------------------------------
\49\ Order No. 1000-A, 139 FERC ] 61,132 at P 637.
\50\ Id. P 649.
\51\ Id. P 746.
\52\ As Transmission Access Policy Study Group also recognizes,
not all RTOs make section 205 filings for the application of an
existing filed cost allocation methodology. See Transmission Access
Policy Study Group at n.14. Transmission Access Policy Study Group
has not justified its position that this will be an issue in non-
ISO/RTO regions at this time. Again, the Commission will carefully
evaluate compliance filings, as well as protests thereto, to ensure
that they satisfy Order No. 1000's requirements, and the Commission
will require changes if they fail to do so.
\53\ Order No. 1000-A, 139 FERC ] 61,132 at P 616.
---------------------------------------------------------------------------
26. We do not believe that Transmission Access Policy Study Group
has justified at this time its position that public utility
transmission providers in non-RTO regions, at least, should be required
to file specific applications of the cost allocation method. Again, as
discussed above, our expectation is that the open and transparent
transmission planning process and principle-based cost allocation
method will provide stakeholders with clarity as to why and how costs
are being allocated for any specific transmission facility selected in
the regional transmission plan for purposes of cost allocation. This is
true regardless of whether or not the transmission planning region is
an ISO/RTO. As we also discuss above, the Commission will carefully
evaluate compliance proposals and any resulting protests to ensure that
the proposals meet the requirements of Order No. 1000.
27. Finally, with respect to Transmission Access Policy Study
Group's request that we defer a determination on using section 206 as
the default mechanism to challenge a cost allocation proposal,
references to section 206 in Order No. 1000-A were to remind
stakeholders of their right under that provision to file complaints. In
any event, as we have previously explained, Order No. 1000-A provides
that public utility transmission providers in a transmission planning
region, in consultation with stakeholders, could agree to require the
filing of specific applications of the cost allocation method. The
Commission will review any such requirement during the Order No. 1000
compliance filings process and make a decision based on the record
before us.
3. Consideration of Transmission Needs Driven by Public Policy
Requirements
a. Order No. 1000-A
28. Order No. 1000-A affirmed Order No. 1000's requirement that
public utility transmission providers amend their OATTs to provide for
the consideration of transmission needs driven by Public Policy
Requirements.\54\ In affirming this requirement, Order No. 1000-A
provided clarifications regarding the definition of the term ``Public
Policy Requirements'' \55\ and what it means to ``consider''
transmission needs driven by such requirements.\56\ Order No. 1000-A
explained that the Commission intends that public utility transmission
providers consider transmission needs driven by Public Policy
Requirements just as they consider transmission needs driven by
reliability or economic concerns.\57\ Further, the Commission stated
that it does not intend public utility transmission providers to
substitute their policy judgments for those of legislatures and
regulators.\58\ Order No. 1000-A also explained that the Commission
does not require that regional transmission plans support multiple
likely power supply scenarios, although such a requirement could be
proposed in Order No. 1000 compliance filings and the Commission would
consider such a proposal.\59\
---------------------------------------------------------------------------
\54\ Order No. 1000-A, 139 FERC ] 61,132 at PP 317-339. See also
id. PP 203-216 (affirming legal basis of requirement to consider
transmission needs driven by Public Policy Requirements).
\55\ Order No. 1000 defined ``Public Policy Requirements'' as
public policy requirements established by state or federal laws and
regulations. Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 2.
Order No. 1000-A clarified that this term included duly enacted laws
or regulations passed by a local governmental entity, such as a
municipal or county government. Order No. 1000-A, 139 FERC ] 61,132
at P 319.
\56\ Order No. 1000-A, 139 FERC ] 61,132 at PP 320-325.
\57\ Id. P 205.
\58\ Id. PP 326-29.
\59\ Id. P 331.
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b. Request for Clarification
29. AEP requests clarification that an appropriate method for a
region to consider transmission needs driven by Public Policy
Requirements is to expressly include consideration of changes in
resources and load driven by public policies as part of its baseline
projection of changes in resources and load expected over the planning
horizon, and then conduct reliability and congestion analyses to
determine what transmission investments are optimal given those
expected changes in resources and load.\60\ AEP argues that Public
Policy Requirements should not be considered solely on a stand-alone
basis in the planning process.\61\ It contends that generation or load
changes driven by public policies should be factored into the
scenarios, along with other anticipated resource and load changes, for
which reliability and economic benefits analyses are performed.\62\
---------------------------------------------------------------------------
\60\ AEP at 5.
\61\ Id. at 2.
\62\ Id.
---------------------------------------------------------------------------
30. AEP states that it is concerned that some transmission
providers may seek to satisfy the Commission's public policy
requirement by employing only a stand-alone process or procedures that
are specifically designed to evaluate transmission needs driven by
Public Policy Requirements.\63\ It argues that regional planning
processes should consider reliability, economic, and policy-driven
transmission needs together.\64\ In particular, AEP asserts that a
region should consider what changes in generation resources and load it
expects over the planning horizon, including consideration of changes
driven by public policies (such as renewable portfolio standards, new
environmental regulations, and demand side management programs), and
then conduct reliability and congestion analyses to determine what
transmission investments are optimal given these anticipated
changes.\65\ It contends that this approach enables transmission
providers to build upon existing planning processes for the reliability
and economic analyses used to identify baseline reliability and
economic projects.\66\ AEP argues that integrated consideration of
public policy-driven requirements can factor into efficient decisions
to accelerate a needed baseline reliability upgrade or increase the
capacity of a baseline reliability upgrade or baseline economic
upgrade.\67\
---------------------------------------------------------------------------
\63\ Id. at 4.
\64\ Id.
\65\ Id.
\66\ Id.
\67\ Id.
---------------------------------------------------------------------------
c. Commission Determination
31. We grant AEP's request for clarification to the extent
discussed below. Order No. 1000 requires public utility transmission
providers to revise their OATTs to provide for the consideration of
transmission needs driven by Public Policy Requirements.\68\ In Order
No. 1000, the Commission
[[Page 64896]]
provides for regional flexibility so that public utility transmission
providers, in consultation with stakeholders, can design proposals
addressing this requirement that they believe best meet the needs of
their respective transmission planning regions, so long as those
proposals satisfy the essential requirement that public utility
transmission providers, in consultation with stakeholders, consider
transmission needs driven by Public Policy Requirements as set forth in
Order No. 1000 and clarified in Order No. 1000-A.\69\ The Commission
anticipates that a variety of approaches could satisfy the Commission's
requirements and we expect that stakeholders supporting such proposals
would have the opportunity to advocate for them in the stakeholder
processes leading to the Order No. 1000 compliance filings. The
Commission will consider any such approaches in the compliance filings
when they are submitted for review.\70\
---------------------------------------------------------------------------
\68\ The requirement to consider transmission needs driven by
Public Policy Requirements is described in more detail in Order No.
1000, FERC Stats. & Regs. ] 31,323 at PP 203-222 and Order No. 1000-
A, 139 FERC ] 61,132 at PP 317-339.
\69\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 331
(``It may well be the case that evaluating different power supply
scenarios will be an effective way to identify more efficient or
cost-effective transmission solutions; however, we will not
prescribe any such requirements here, consistent with our preference
for regional flexibility in designing regional transmission planning
processes.'').
\70\ See id.
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B. Nonincumbent Transmission Developers
32. In Order No. 1000, the Commission addressed the removal from
Commission-jurisdictional tariffs and agreements of provisions that
contain a federal right of first refusal to construct transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. The Commission also adopted a framework that requires
the development of qualification criteria and protocols to govern the
submission and evaluation of proposals for transmission facilities by
public utility transmission providers in the regional transmission
planning process. The Commission further required that a nonincumbent
transmission developer of a transmission facility selected in the
regional transmission plan for purposes of cost allocation have an
opportunity comparable to that of an incumbent transmission developer
to allocate the cost of such transmission facility through a regional
cost allocation method or methods.\71\
---------------------------------------------------------------------------
\71\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 225.
---------------------------------------------------------------------------
1. Legal Authority
a. Order No. 1000-A
33. In Order No. 1000-A, the Commission affirmed its conclusion in
Order No. 1000 that it has the legal authority under section 206 of the
FPA to require the elimination of federal rights of first refusal as
practices that have the potential to lead to Commission-jurisdictional
rates that are unjust and unreasonable or unduly discriminatory or
preferential.\72\ The Commission stated that, consistent with its
authority under section 206, the Commission acted to remedy an unjust
and unreasonable or unduly discriminatory or preferential practice by
requiring public utility transmission providers to eliminate a federal
right of first refusal from Commission-jurisdictional tariffs and
agreements and adopt the nonincumbent reforms. The Commission explained
that in Order No. 1000, it had found that a federal right of first
refusal applicable to transmission facilities selected in a regional
transmission plan for purposes of cost allocation can lead to rates for
Commission-jurisdictional services that are unjust and unreasonable or
otherwise result in undue discrimination by public utility transmission
providers.\73\
---------------------------------------------------------------------------
\72\ Order No. 1000-A, 139 FERC ] 61,132 at P 357.
\73\ Id. P 360.
---------------------------------------------------------------------------
34. Finally, the Commission affirmed its decision in Order No. 1000
to address arguments that an individual contract contains a federal
right of first refusal that is protected by a Mobile-Sierra provision
when it reviews the compliance filings made by public utility
transmission providers.\74\ Consistent with Order No. 1000, the
Commission explained that a public utility transmission provider that
considers its contract to be protected by a Mobile-Sierra provision may
present its arguments as part of its compliance filing. However, the
Commission also clarified that any such compliance filing must include
the revisions to any Commission-jurisdictional tariffs and agreements
necessary to comply with Order No. 1000 as well as the Mobile-Sierra
provision arguments.\75\ The Commission concluded that this approach
ensures that public utility transmission providers would not be
required to eliminate a federal right of first refusal before the
Commission makes a determination regarding whether an agreement is
protected by a Mobile-Sierra provision and whether the Commission has
met the applicable standard of review, while at the same time ensuring
that the Order No. 1000 compliance process proceeds expeditiously and
efficiently.
---------------------------------------------------------------------------
\74\ Id. P 388.
\75\ Id. P 389.
---------------------------------------------------------------------------
b. Requests for Rehearing and Clarification
35. Oklahoma Gas and Electric Company argues that the Commission
failed to support its assertion that provisions that designate
incumbent utilities to construct new transmission facilities are unduly
discriminatory or preferential, or cause rates to be unreasonably
high.\76\ Oklahoma Gas and Electric Company further argues that the
Commission cannot support a finding that the current transmission rules
in the Southwest Power Pool result in rates that are unjust or
unreasonable.\77\
---------------------------------------------------------------------------
\76\ Oklahoma Gas and Electric Company at 4.
\77\ Id.
---------------------------------------------------------------------------
36. Oklahoma Gas and Electric Company also argues that the
Commission ignores that the Mobile-Sierra standard is a threshold
question and that the Commission cannot shift the burden of proof to
the contracting parties to propose an alternative until the Commission
has answered.\78\ Oklahoma Gas and Electric Company asserts that, under
section 206 of the Federal Power Act, the Commission must first prove
that the existing rates or practices are unjust, unreasonable, unduly
discriminatory or preferential, and that courts have repeatedly held
that the Commission has no power to force public utilities to file
particular rates unless it first finds the existing filed rates
unlawful.\79\ Oklahoma Gas and Electric Company asserts that this two-
step process is even more vital in the context of applying the Mobile-
Sierra doctrine because the Commission must presume that the rate set
out in a freely negotiated wholesale-energy contract meets the just and
reasonable requirement imposed by law.\80\ Accordingly, Oklahoma Gas
and Electric Company argues that the Commission has no power to require
parties to renegotiate and revise existing agreements unless it finds
harm to the public interest.\81\
---------------------------------------------------------------------------
\78\ Id. at 8.
\79\ Id. at 8-9 (citing Atlantic City Elec. Co. v. FERC, 295
F.3d 1, 10 (D.C. Cir. 2002); Complex Consol. Edison Co. of New York,
Inc. v. FERC, 165 F.3d 992, 1001 (D.C. Cir. 1999); Transmission
Access Policy Study Group v. FERC, 225 F.3d 667, 688 (D.C. Cir.
2005)).
\80\ Id. at 9 (citing NRG Power Marketing, LLC v. Maine Public
Utilities Commission, 130 S. Ct. 693, 700 (2010)).
\81\ Id. at 9-10.
---------------------------------------------------------------------------
c. Commission Determination
37. We disagree with Oklahoma Gas and Electric Company that the
[[Page 64897]]
Commission failed to support its determination that a federal right of
first refusal for transmission facilities selected in a regional
transmission plan for purposes of cost allocation may lead to
Commission-jurisdictional rates that are unjust and unreasonable or
unduly discriminatory or preferential. Specifically, the Commission
found that a federal right of first refusal has ``the potential to
undermine the identification and evaluation of more efficient or cost-
effective solutions to regional transmission needs, which in turn can
result in rates for Commission-jurisdictional services that are unjust
and unreasonable or otherwise result in undue discrimination by public
utility transmission providers.'' \82\ The Commission further explained
the direct effect that a federal right of first refusal can have on
Commission-jurisdictional rates in Order No. 1000-A, stating that:
---------------------------------------------------------------------------
\82\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 253.
the selection of transmission facilities in a regional transmission
plan for purposes of cost allocation is directly related to costs
that will be allocated to jurisdictional ratepayers. The ability of
an incumbent transmission provider to discourage or preclude
participation of new transmission developers through discriminatory
rules in a regional transmission planning process, and in
particular, the inclusion of a federal right of first refusal, can
have the effect of limiting the identification and evaluation of
potential solutions to regional transmission needs. This in turn can
directly increase the cost of new transmission development that is
---------------------------------------------------------------------------
recovered from jurisdictional customers through rates.\83\
\83\ Order No. 1000-A, 139 FERC ] 61,132 at P 358 (citations
omitted).
38. The Commission put forth several rationales to support its
determination.\84\ In particular, the Commission noted that the Federal
Trade Commission supported the Commission's conclusion that a federal
right of first refusal can create a barrier to entry that discourages
nonincumbent transmission developers from proposing alternative
solutions for consideration at the regional level.\85\ In addition, the
Commission stated that it is not in the economic self-interest of
incumbent transmission providers to permit new entrants to develop
transmission facilities, even if proposals submitted by new entrants
would result in a more efficient or cost-effective solution to the
region's needs.\86\ Thus, the Commission concluded that it has a
reasonable expectation that expanding the universe of transmission
developers offering potential solutions to regional needs can lead to
the identification and evaluation of potential solutions that are more
efficient or cost-effective.\87\
---------------------------------------------------------------------------
\84\ Id. P 76.
\85\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 257; see
Order No. 1000-A, 139 FERC ] 61,132 at P 76.
\86\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 256.
\87\ Order No. 1000-A, 139 FERC ] 61,132 at PP 77, 83.
---------------------------------------------------------------------------
39. Furthermore, as the Commission explained in the Need for Reform
section of Order No. 1000-A, the Commission is not required to make
individual findings concerning the rates of individual public utility
transmission providers when proceeding under FPA section 206 by means
of a generic rule.\88\ Rather, the Commission can proceed by
identifying a ``theoretical threat'' that would materialize and cause
rates to be unjust and unreasonable, or unduly discriminatory or
preferential.\89\ As discussed in the preceding paragraph, the
Commission found that a federal right of first refusal has the
potential to lead to rates for Commission-jurisdictional services that
are unjust and unreasonable or otherwise unduly discriminatory.
---------------------------------------------------------------------------
\88\ Id. P 56.
\89\ Id. P 57.
---------------------------------------------------------------------------
40. In response to Oklahoma Gas and Electric Company's arguments
regarding the Mobile-Sierra doctrine, we reiterate that the Commission
is not requiring public utility transmission providers to eliminate a
federal right of first refusal before the Commission makes a
determination regarding whether an agreement is protected by the
Mobile-Sierra doctrine and whether the Commission has met the
applicable standard of review. As the Commission clarified in Order No.
1000-A, the Commission will first decide, based on a more complete
record, including viewpoints of other interested parties, whether an
agreement is protected by the Mobile-Sierra doctrine, and if so,
whether the Commission has met the applicable standard of review such
that it can require the modification of the particular agreement.\90\
If the Commission determines based on the record submitted in the
compliance filing that an agreement is protected by the Mobile-Sierra
doctrine and that it cannot meet the applicable standard of review,
then the Commission will not consider whether the revisions to the
Commission-jurisdictional tariffs and agreements submitted by a public
utility transmission provider that considers its agreement to be
protected by the Mobile-Sierra doctrine comply with Order No. 1000.\91\
---------------------------------------------------------------------------
\90\ Id. P 389.
\91\ Id.
---------------------------------------------------------------------------
2. Requirement To Remove a Federal Right of First Refusal From
Commission-Jurisdictional Tariffs and Agreements, and Limits on the
Applicability of That Requirement
a. Order No. 1000-A
41. In Order No. 1000-A, the Commission affirmed its decision in
Order No. 1000 to require the elimination of a federal right of first
refusal from Commission-jurisdictional tariffs and agreements for
transmission facilities selected in a regional transmission plan for
purposes of cost allocation.\92\ The Commission also clarified certain
terms used in Order No. 1000. For instance, the Commission clarified
that the term ``selected in a regional transmission plan for purposes
of cost allocation'' excludes a new transmission facility if the costs
of that facility are borne entirely by the public utility transmission
provider in whose retail distribution service territory or footprint
that new transmission facility is to be located.\93\
---------------------------------------------------------------------------
\92\ Id. P 415.
\93\ Id. P 423.
---------------------------------------------------------------------------
42. The Commission stated that in general, any regional cost
allocation of the cost of a new transmission facility outside a single
transmission provider's retail distribution service territory or
footprint, including an allocation to a ``zone'' consisting of more
than one transmission provider, is an application of the regional cost
allocation method and that new transmission facility is not a local
transmission facility.\94\ As an example, the Commission stated that
transmission owning members of an RTO may not retain a federal right of
first refusal by dividing the RTO into East and West multi-utility
zones and allocating costs just within one zone consisting of more than
one transmission provider.\95\ The Commission also stated that it will
address whether a cost allocation to a multi-transmission provider zone
is regional on a case-by-case basis based on the specific facts
presented. The Commission explained that there may be a continuum of
examples that range from (i) one small municipality with a single small
transmission facility located within a transmission provider's
footprint, to (ii) a ``zone'' consisting of many public utility and
nonpublic utility transmission providers. Accordingly, the Commission
stated that public utility transmission providers may include specific
situations in their compliance filings along with the filed regional
cost
[[Page 64898]]
allocation method or methods.\96\ The Commission clarified that if any
costs of a new transmission facility are allocated regionally or
outside of a public utility transmission provider's retail distribution
service territory or footprint, there can be no federal right of first
refusal associated with such transmission facility, except as provided
in Order Nos. 1000 and 1000-A.\97\
---------------------------------------------------------------------------
\94\ Id. P 424.
\95\ Id.
\96\ Id.
\97\ Id. P 430. For example, the Commission does not require an
incumbent transmission provider to eliminate a federal right of
first refusal for upgrades to its own transmission facilities. Order
No. 1000, FERC Stats. & Regs. ] 31,323 at P 319.
---------------------------------------------------------------------------
b. Requests for Rehearing and Clarification
43. Petitioners seek rehearing of the Commission's determination in
Order No. 1000-A that a transmission facility is considered selected in
a regional transmission plan for purposes of cost allocation if any of
the costs of that facility are allocated outside of the public utility
transmission provider's retail distribution service territory or
footprint.\98\ MISO Transmission Owners Group 2 argues that under a
reasonable interpretation of Order No. 1000, a transmission provider
may retain its right of first refusal if a transmission facility is not
selected in a regional transmission plan for purposes of cost
allocation as a more efficient or cost-effective solution to regional
needs but instead was selected to primarily address local needs.\99\
MISO Transmission Owners Group 2 states that not all projects included
in the regional transmission plan for which some costs are allocated
outside of an individual utility's footprint are ``a more efficient or
cost-effective solution to regional transmission needs,'' such as
projects constructed to meet compliance with state service obligations
or where the most efficient or cost-effective solution may not be in-
service in time to satisfy reliability criteria and the decision to
include the project in the plan is made primarily on the basis of
reliability.\100\
---------------------------------------------------------------------------
\98\ See, e.g. MISO Transmission Owners Group 2 and Oklahoma Gas
and Electric Company.
\99\ MISO Transmission Owners Group 2 at 12-13.
\100\ Id. at 14-15 (citing Order No. 1000-A, 139 FERC ] 61,132
at P 430).
---------------------------------------------------------------------------
44. MISO Transmission Owners Group 2 argues, however, that
statements in Order No. 1000-A suggest that the decision regarding
whether a facility is more efficient or cost-effective is irrelevant to
determining whether the requirement to remove federal rights of first
refusal would apply.\101\ MISO Transmission Owners Group 2 argues that
the Commission cites no record evidence or argument in favor of
broadening the definition of transmission facilities selected in a
regional transmission plan for purposes of cost allocation.\102\
Accordingly, MISO Transmission Owners Group 2 asks for the Commission
to clarify that, in order for the requirement to eliminate the federal
right of first refusal to apply, the costs of a transmission facility
must not only be allocated outside of a transmission owner's retail
distribution service territory or footprint and the transmission
facility must have been selected in the regional transmission plan, but
it also must be selected as a more efficient or cost-effective solution
to regional transmission needs. The MISO Transmission Owners Group
requests that the Commission clarify that utilities may retain a right
of first refusal for projects that are selected which may not be the
``more efficient or cost-effective solution to regional transmission
needs.'' \103\
---------------------------------------------------------------------------
\101\ Id. at 13-14 (citing Order No. 1000-A, 139 FERC ] 61,132
at P 430 (``if any costs of a new transmission facility are
allocated regionally or outside of a public utility transmission
provider's retail distribution service territory or footprint, then
there can be no federal right of first refusal associated with such
transmission facility.'')).
\102\ Id. at 18.
\103\ Id. at 15-19.
---------------------------------------------------------------------------
45. MISO Transmission Owners Group 2 also argues that eliminating
the ability of a transmission-owning member of an RTO to construct and
allocate the costs of a local transmission facility encourages free
ridership by providing an incentive for transmission providers to keep
cost allocation within their retail distribution service territory to
retain a right of first refusal for local transmission facilities, even
when entities outside of the retail distribution service territory or
footprint may receive some benefit from such facilities despite their
primarily local nature.\104\
---------------------------------------------------------------------------
\104\ Id. at 19.
---------------------------------------------------------------------------
46. Oklahoma Gas and Electric Company argues that a broader
definition of what constitutes regional cost allocation prohibits
transmission planning regions from adopting approaches they believe
would effectively allocate costs and fairly balance stakeholder
interests.\105\ For instance, Oklahoma Gas and Electric Company states
that the Southwest Power Pool allocates costs using a Highway/Byway
Plan.\106\ Oklahoma Gas and Electric Company asserts that the
Commission should ensure that the Southwest Power Pool can retain its
Highway/Byway Plan for cost allocation by designating lower voltage
facilities as local facilities for purposes of Order No. 1000.\107\
---------------------------------------------------------------------------
\105\ Oklahoma Gas and Electric Company at 6.
\106\ Id. (citing Southwest Power Pool, Inc., 131 FERC ] 61,252
(2010), reh'g denied, 137 FERC ] 61,075 (2011)). Oklahoma Gas and
Electric Company states that the Southwest Power Pool allocates: (1)
100% of the cost of a facility operating at 300 kV or above across
the region on a postage stamp basis; (2) one-third of the cost of a
facility operating above 100 kV and below 300 kV on a regional
postage stamp basis and the remaining two-thirds of the costs to the
zone in which the facility is located; and, (3) all the costs of a
facility operating at or under 100 kV to the zone in which the
facility is located. Id.
\107\ Id.
---------------------------------------------------------------------------
47. Some petitioners request that the Commission clarify that
projects with costs allocated to a single zone should be considered
local, even if the zone consists of more than one public utility
transmission provider, so that the public utility transmission provider
may retain a federal right of first refusal.\108\ AEP contends that the
Commission's proposal to defer evaluation of multi-utility zones until
the compliance filing stage does little to inform ongoing RTO
stakeholder processes tasked with developing compliance filings.\109\
MISO Transmission Owners Group 2 asserts that the Commission failed to
identify any record evidence or argument for its conclusion that
transmission providers located in multi-transmission provider zones
automatically lose their federal rights of first refusal for all
transmission facilities.\110\
---------------------------------------------------------------------------
\108\ See, e.g., AEP and MISO Transmission Owners Group 2.
\109\ AEP at 10-11. AEP cites as an example SPP's stakeholder
process which at the time of AEP's request for clarification, was
debating the interpretation of the Commission's intended treatment
of zones that have long included a single large, traditional load-
serving public utility, as well as several small municipal or
cooperative utilities that are dependent on the transmission system
of the traditional public utility to serve their respective loads.
\110\ MISO Transmission Owners Group 2 at 24.
---------------------------------------------------------------------------
48. MISO Transmission Owners Group 2 also argues that the
Commission's stated concern that such zones might be established to
circumvent Order No. 1000 is misplaced.\111\ In support, MISO
Transmission Owners Group 2 asserts that such zones were established
prior to the issuance of Order No. 1000 and based on decades of
cooperation and collaboration among transmission owners.\112\ In
addition, MISO Transmission Owners Group 2 argues that the Commission's
distinction between multi-transmission provider zones and zones
containing only one transmission provider results in undue
discrimination against transmission providers that happen to be located
in a multi-transmission provider zone.\113\
---------------------------------------------------------------------------
\111\ Id. at 22.
\112\ Id.
\113\ Id. at 26.
---------------------------------------------------------------------------
[[Page 64899]]
49. Oklahoma Gas and Electric Company contends that the Commission
incorrectly claimed in Order No. 1000-A that the scope of Order No.
1000 will be limited. It asserts that, in response to arguments that
the requirement to eliminate the right of first refusal is beyond the
Commission's authority and will materially alter the business of public
utilities, the Commission in Order No. 1000-A emphasized that the
requirement did not extend to local transmission facilities.\114\
Oklahoma Gas and Electric Company asserts that based on the discussion
of zones in Order No. 1000-A, it may not be possible to build a local
facility under the Southwest Power Pool tariff, making all new
construction subject to Order No. 1000.\115\ Similarly, MISO
Transmission Owners Group 2 contends that RTO transmission-owning
members lack individual mechanisms for cost allocation and recovery,
and therefore would have no ability to build and recover the costs of
local transmission facilities as they are defined in Order No.
1000.\116\
---------------------------------------------------------------------------
\114\ Oklahoma Gas and Electric Company at 3-5.
\115\ Id. at 5-6.
\116\ MISO Transmission Owners Group 2 at 23.
---------------------------------------------------------------------------
50. Oklahoma Gas and Electric Company argues that because the
requirement to eliminate provisions that designate incumbent utilities
to construct new transmission facilities is not limited in scope, and
does materially alter the businesses of transmission owning companies,
the Commission should find that there is no sound basis to require that
public utility transmission providers remove such provisions.\117\ In
the alternative, Oklahoma Gas and Electric Company asserts that the
Commission should allow each region to define the scope of local
transmission projects that will not be subject to the new rule.\118\
---------------------------------------------------------------------------
\117\ Oklahoma Gas and Electric Company at 7.
\118\ Id.
---------------------------------------------------------------------------
c. Commission Determination
51. On rehearing of Order No. 1000-A, petitioners have raised two
issues related to Order No. 1000's requirement that public utility
transmission providers remove federal rights of first refusal from
Commission-jurisdictional tariffs and agreements. First, some
petitioners seek rehearing of Order No. 1000-A's determination that if
any of the costs of a new transmission facility are allocated
regionally or outside of a public utility transmission provider's
retail distribution service territory or footprint, then there can be
no federal right of first refusal associated with such transmission
facility. Second, on rehearing some petitioners argue that projects
with costs allocated to a single zone should be considered local, even
if there is more than one public utility transmission provider located
in that zone, so that the public utility transmission provider may
retain a federal right of first refusal under those circumstances. We
deny rehearing and will discuss each of these issues in turn.
52. As noted above, the first issue we address concerns requests
for rehearing of Order No. 1000-A's determination that if any costs of
a new transmission facility are allocated regionally or outside of a
public utility transmission provider's retail distribution service
territory or footprint, then there can be no federal right of first
refusal associated with such transmission facility, except as provided
in Order Nos. 1000 and 1000-A.\119\ Order No. 1000 requires that a
federal right of first refusal be removed for new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. As noted above, the Commission stated in Order No.
1000 that in general, if any costs of a new transmission facility are
allocated regionally or outside a single transmission provider's retail
distribution service territory or footprint, that is an application of
the regional cost allocation method and that new transmission facility
is not a local transmission facility.\120\ Therefore, once a new
transmission facility is selected in the regional transmission plan for
purposes of cost allocation, it is no longer a local transmission
facility exempt from the requirements of Order Nos. 1000 and 1000-A
regarding the removal of federal rights of first refusal. For this
reason, we deny rehearing on this issue.
---------------------------------------------------------------------------
\119\ Order No. 1000-A, 139 FERC ] 61,132 at P 430.
\120\ Id. P 424 (emphasis added).
---------------------------------------------------------------------------
53. We note that neither Order No. 1000 nor Order No. 1000-A
requires elimination of a federal right of first refusal in all
circumstances.\121\ We also note that the Commission recognized that
issuance of Order No. 1000 may have occurred in the middle of a
transmission planning cycle for a particular region and, therefore,
directed public utility transmission providers to explain in their
respective compliance filings how they intend to implement the
requirements of the Final Rule.\122\ Moreover, public utility
transmission providers are required to describe the circumstances and
procedures under which public utility transmission providers will
reevaluate the regional transmission plan to determine if delays in the
development of a transmission facility selected in a regional
transmission plan for purposes of cost allocation require evaluation of
alternative solutions, including those proposed by the incumbent
transmission provider, to ensure the incumbent transmission provider
can meet its reliability needs or service obligations.\123\ We will
evaluate proposals related to these requirements on review of
compliance filings.
---------------------------------------------------------------------------
\121\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 318-
319.
\122\ Id. P 162. See also id. P 65 (``Our intent here is that
this Final Rule not delay current studies being undertaken pursuant
to existing regional transmission planning processes or impede
progress on implementing existing transmission plans. We direct
public utility transmission providers to explain in their compliance
filings how they will determine which facilities evaluated in their
local and regional planning processes will be subject to the
requirements of this Final Rule.'').
\123\ Order No. 1000-A, FERC Stats. & Regs. ] 31,132 at P 477.
See also Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 329
(``[A]n incumbent transmission provider must have the ability to
propose solutions that it would implement within its retail
distribution service territory or footprint that will enable it to
meet its reliability needs or service obligations.'').
---------------------------------------------------------------------------
54. With respect to the second issue raised by petitioners--whether
a project whose costs are allocated to a single zone with multiple
transmission owners should be considered local and thus permit a public
utility transmission provider to retain a federal right of first
refusal under these circumstances--the Commission recognized in Order
No. 1000-A that special consideration is needed when a small
transmission provider is located within the footprint of another
transmission provider.\124\ The Commission acknowledged that there is a
continuum of situations of multi-transmission provider zones, but opted
to address such situations on compliance. This acknowledgement provides
public utility transmission providers who may have zonal
configurations, such as a zone with a small municipality and one
transmission provider, or one with many public utility and non-public
utility transmission providers, an opportunity to address whether a
cost allocation to a multi-transmission provider zone is regional on a
case-by-case basis based on the specific facts presented. We consider
many of the arguments related to multi-transmission provider zones
premature because the Commission did not adopt a generic rule as to
whether a cost allocation solely to a multi-transmission provider zone
is an application of the regional cost allocation method for which a
[[Page 64900]]
federal right of first refusal must be eliminated. Petitioners have not
presented evidence that would support the Commission making a generic
finding or providing additional guidance for all multi-transmission
provider zones in this rulemaking proceeding. Therefore, on this second
issue, we find that the Commission's determination is a reasonable
balance of competing considerations that enables the Commission to
implement the requirements of Order No. 1000 in a manner that will
achieve the goal of improved transmission planning.
---------------------------------------------------------------------------
\124\ Order No. 1000-A, FERC Stats. & Regs. ] 31,132 at P 424.
---------------------------------------------------------------------------
55. We therefore agree with petitioners that the Commission's
requirements have not entirely eliminated opportunities for free
ridership. As evidenced by the multiple comments and petitions the
Commission received in the Order No. 1000 proceedings, the Commission
balanced many competing interests in determining how to best implement
the requirements of Order No. 1000. Some presented their views of the
advantages of retaining a federal right of first refusal for all new
transmission facilities while others presented their views of the
advantages of eliminating a federal right of first refusal for all new
transmission facilities. The Commission has considered the arguments
raised by petitioners on rehearing with respect to both of the above-
mentioned issues and rejects petitioners' requests for rehearing as we
find that the approach taken in Order Nos. 1000 and 1000-A provides the
best balance of competing considerations.
3. Framework To Evaluate Transmission Projects Submitted for Selection
in the Regional Transmission Plan for Purposes of Cost Allocation
a. Evaluation of Proposals for Selection in the Regional Transmission
Plan for Purposes of Cost Allocation
i. Order No. 1000-A
56. In Order No. 1000-A, the Commission affirmed its decision in
Order No. 1000 to require each public utility transmission provider to
amend its OATT to describe a transparent and not unduly discriminatory
process for evaluating whether to select a proposed transmission
facility in a regional transmission plan for purposes of cost
allocation.\125\ The Commission also reiterated that there are many
different approaches to transmission planning and that Order No. 1000
requires only that the transmission planning process adopted by a
transmission planning region satisfy the transmission planning
principles discussed in Order Nos. 1000 and 1000-A. Accordingly, the
Commission declined to rule in the abstract in advance of the
compliance filings whether any particular transmission planning process
is the only appropriate process for all regions.
---------------------------------------------------------------------------
\125\ Order No. 1000-A, 139 FERC ] 61,132 at P 452.
---------------------------------------------------------------------------
57. The Commission also continued to emphasize that any
qualification criteria or process for selecting transmission facilities
in a regional transmission plan for purposes of cost allocation must be
transparent and not unduly discriminatory.\126\ Finally, the Commission
affirmed its decision that, if a proposed transmission facility is
selected in a regional transmission plan for purposes of cost
allocation, then Order No. 1000 requires that the transmission
developer of that transmission facility (whether incumbent or
nonincumbent) must be able to rely on the relevant cost allocation
method or methods within the region should it move forward with its
transmission project.\127\ The Commission also reiterated that it would
not require public utility transmission providers in a region to adopt
a provision for ongoing sponsorship rights, and pointed out that in
Order No. 1000, the Commission concluded that granting transmission
developers an ongoing right to build sponsored transmission projects
could adversely impact the regional transmission planning process.\128\
Accordingly, the Commission in Order No. 1000-A declined to reverse
this decision on the selection of transmission developers.\129\
---------------------------------------------------------------------------
\126\ Id. PP 439, 452.
\127\ Id. P 456; Order No. 1000, FERC Stats. & Regs. ] 31,323 at
P 339.
\128\ Order No. 1000-A, 139 FERC ] 61,132 at P 456; Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 339.
\129\ Order No. 1000-A, 139 FERC ] 61,132 at P 456; Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 339.
---------------------------------------------------------------------------
ii. Requests for Rehearing and Clarification
58. AEP maintains that some regions are considering a process in
which third parties (e.g., one or more states) select the developer for
a transmission project after the regional planning entity has
identified needed transmission projects in its regional transmission
plan.\130\ AEP asserts that leaving the selection of a project
developer to an entity other than the regional planning body threatens
to lead to suboptimal results.\131\ It argues that the decision as to
which entity is best suited to build a given transmission project
necessarily relies on developer qualifications as assessed by the
transmission provider, and on projected benefits, which will vary among
developers.\132\ It contends that the selection of the best
transmission solution for the region cannot be done effectively without
information about the qualifications and the benefits offered by the
developer for the project.\133\ Accordingly, AEP requests that the
Commission provide clarification to discourage bifurcation of the
planning process.\134\
---------------------------------------------------------------------------
\130\ AEP at 6.
\131\ Id. at 2.
\132\ Id. at 6.
\133\ Id. at 6-7.
\134\ Id. at 6.
---------------------------------------------------------------------------
iii. Commission Determination
59. We decline to clarify in advance of the compliance filings
whether any particular approach to the selection of a transmission
developer is a just and reasonable and not unduly discriminatory or
preferential selection process. Order No. 1000 requires public utility
transmission providers in a region to adopt transparent and not unduly
discriminatory criteria for selecting a new transmission project in a
regional transmission plan for purposes of cost allocation.\135\ It
also requires that if a transmission project is selected in a regional
transmission plan for purposes of cost allocation, the transmission
developer of that transmission facility must be able to rely on the
relevant cost allocation method or methods within the region should it
move forward with the transmission project.\136\ However, the
Commission declined to otherwise address the selection of a
transmission developer on a generic basis.\137\ We continue to believe
that it is not appropriate to address in advance of the compliance
filings the process for selecting transmission developers in greater
detail. Instead, we reaffirm the flexibility that the Commission
provided to the public utility transmission providers in each
transmission planning region to propose a process for selecting
transmission developers in accordance with each transmission planning
region's needs.\138\
---------------------------------------------------------------------------
\135\ E.g., Order No. 1000-A, 139 FERC ] 31,132 at P 455.
\136\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 332,
339; see also Order No. 1000-A, 139 FERC ] 61,132 at P 456.
\137\ E.g., Order No. 1000-A, 139 FERC ] 61,132 at P 455.
\138\ E.g., id.
---------------------------------------------------------------------------
C. Interregional Transmission Coordination
60. In Order No. 1000, the Commission required each public utility
[[Page 64901]]
transmission provider, through its regional transmission planning
process, to establish further procedures with each of its neighboring
transmission planning regions for the purpose of: (1) Coordinating and
sharing the results of respective regional transmission plans to
identify possible interregional transmission facilities that could
address transmission needs more efficiently or cost-effectively than
separate regional transmission facilities; and (2) jointly evaluating
such facilities, as well as jointly evaluating those transmission
facilities that are proposed to be located in more than one
transmission planning region.\139\ The Commission also required each
public utility transmission provider, through its regional transmission
planning process, to describe the methods by which it will identify and
evaluate interregional transmission facilities and to include a
description of the type of transmission studies that will be conducted
to evaluate conditions on neighboring systems for the purpose of
determining whether interregional transmission facilities are more
efficient or cost-effective than regional facilities.\140\
---------------------------------------------------------------------------
\139\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 493.
\140\ Id.
---------------------------------------------------------------------------
1. Implementation of the Interregional Transmission Coordination
Requirements
a. Procedure for Joint Evaluation
i. Order No. 1000-A
61. In Order No. 1000-A, the Commission reaffirmed Order No. 1000's
requirement that an interregional transmission facility must be
selected in each relevant regional transmission plan for purposes of
cost allocation to be eligible for cost allocation under the
interregional cost allocation method or methods.\141\ The Commission
explained that Order No. 1000 establishes a closer link between
transmission planning and cost allocation. Additionally, the Commission
stated that Order No. 1000 provides for stakeholder involvement in the
consideration of an interregional transmission facility primarily
through the regional transmission planning processes.\142\ The
Commission concluded that this requirement is necessary to ensure that
stakeholders have an opportunity to provide meaningful input with
respect to proposed interregional transmission facilities before such
facilities are selected in each relevant regional transmission plan for
purposes of cost allocation.\143\
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\141\ Order No. 1000-A, 139 FERC ] 61,132 at P 509 (citing Order
No. 1000, FERC Stats. & Regs. ] 31,323 at P 436).
\142\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 465; see
also id. P 443.
\143\ Order No. 1000-A, 139 FERC ] 61,132 at P 509.
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62. Additionally, the Commission acknowledged that, under the
interregional transmission coordination procedures of Order No. 1000,
an interregional transmission facility is unlikely to be selected for
interregional cost allocation unless each transmission planning region
benefits or the transmission planning region that benefits compensates
the region that does not through a separate agreement. The Commission
expressed its continued belief that, under the regional transmission
planning approach adopted in Order No. 1000, it is appropriate for each
transmission planning region to determine for itself whether to select
in its regional transmission plan for purposes of cost allocation an
interregional transmission facility that extends partly within its
regional footprint based on the information gained during the joint
evaluation of an interregional transmission project.\144\
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\144\ Id. P 512.
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ii. Requests for Rehearing and Clarification
63. AEP requests clarification that the inclusion of an
interregional project in a regional plan need not be subject to the
same benefits tests that would be applied to a single-region project,
and that a region may include an interregional project in its plan if
the benefits to the region compare favorably to the share of the costs
that would be borne by that region (as distinct from the total project
costs).\145\ Specifically, it states that in determining the costs and
benefits of a proposed interregional transmission project for the
purposes of the selection process, a regional transmission planning
entity should be permitted to evaluate the benefits provided to an
affected region and assume that a portion of the costs of the project
will be allocated to the affected region.\146\ For example, if a $100
million interregional project would have $180 million in benefits split
evenly between two adjacent regions, both regions would find the
project beneficial and would include it in the regional plan, if they
assumed that one-half of the cost would be borne by each region.\147\
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\145\ AEP at 2, 7.
\146\ Id. at 8.
\147\ Id.
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iii. Commission Determination
64. Order No. 1000 did not specify whether or how a regional or
interregional benefit-cost threshold should be applied when selecting a
project in the regional transmission plan for purposes of cost
allocation, or which costs should be included when calculating a
benefit-cost threshold to use in this selection process. This was to
provide the opportunity for each region to develop an appropriate
calculation, if it chose to use a threshold at all. Therefore, we
decline to clarify in advance of the compliance filings how a benefit-
cost threshold should be applied.
III. Cost Allocation
65. In Order No. 1000, the Commission required that each public
utility transmission provider have in its OATT a method, or set of
methods, for allocating the costs of new regional transmission
facilities selected in the regional transmission plan for purposes of
cost allocation (``regional cost allocation''); and that each public
utility transmission provider within two (or more) neighboring
transmission planning regions develop a method, or set of methods, for
allocating the costs of new interregional transmission facilities that
each of the two (or more) neighboring transmission planning regions
selected for purposes of cost allocation because such facilities would
resolve the individual needs of each region more efficiently or cost-
effectively (``interregional cost allocation'').\148\ The Commission
required that the OATTs of all public utility transmission providers in
a region include the same cost allocation method or methods adopted by
the region.\149\
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\148\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 482. For
purposes of Order No. 1000, a regional transmission facility is a
transmission facility located entirely in one region. An
interregional transmission facility is one that is located in two or
more transmission planning regions. A transmission facility that is
located solely in one transmission planning region is not an
interregional transmission facility. Id. P 482 n.374.
\149\ Order No. 1000-A, 139 FERC ] 61,132 at P 523.
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66. The Commission also required that regional and interregional
cost allocation methods each adhere to six regional and interregional
cost allocation principles: (1) Costs must be allocated in a way that
is roughly commensurate with benefits; (2) there must be no involuntary
allocation of costs to non-beneficiaries; (3) a benefit to cost
threshold ratio cannot exceed 1.25; (4) costs must be allocated solely
within the transmission planning region
[[Page 64902]]
or pair of regions unless those outside the region or pair of regions
voluntarily assume costs; (5) there must be a transparent method for
determining benefits and identifying beneficiaries; and (6) there may
be different methods for different types of transmission
facilities.\150\ The Commission directed that, subject to these general
cost allocation principles, public utility transmission providers in
consultation with stakeholders would have the opportunity to agree on
the appropriate cost allocation methods for their new regional and
interregional transmission facilities, subject to Commission
approval.\151\ The Commission also found that if public utility
transmission providers in a region or pair of regions could not agree,
the Commission would use the record in the relevant compliance filing
proceeding(s) as a basis to develop a cost allocation method or methods
that meets the Commission's requirements.\152\ Finally, the Commission
emphasized that its cost allocation requirements are designed to work
in tandem with its transmission planning requirements to identify more
appropriately the benefits and the beneficiaries of new transmission
facilities so that transmission developers, planners and stakeholders
can take into account in the transmission planning process who would
bear the costs of transmission facilities, if constructed.\153\
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\150\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 622-
693.
\151\ Id. P 588.
\152\ Id. P 482.
\153\ Id. P 483.
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1. Cost Allocation Principle 2--No Involuntary Allocation of Costs to
Non-Beneficiaries
a. Order Nos. 1000 and 1000-A
67. In Order No. 1000, the Commission adopted the following Cost
Allocation Principle 2 for both regional and interregional cost
allocation:
Regional Cost Allocation Principle 2: Those that receive no
benefit from transmission facilities, either at present or in a
likely future scenario, must not be involuntarily allocated any of
the costs of those transmission facilities.
and
Interregional Cost Allocation Principle 2: A transmission
planning region that receives no benefit from an interregional
transmission facility that is located in that region, either at
present or in a likely future scenario, must not be involuntarily
allocated any of the costs of that transmission facility.\154\
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\154\ Id. P 637.
68. The Commission also required that every cost allocation method
or methods provide for allocation of the entire prudently incurred cost
of a transmission project to prevent stranded costs.\155\
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\155\ Id. P 640.
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69. On rehearing, the Commission affirmed Order No. 1000's adoption
of Regional and Interregional Cost Allocation Principle 2. The
Commission explained that scenario analysis is a common feature of
electric power system planning, and that it believed that public
utility transmission providers are in the best position to apply it in
a way that achieves appropriate results in their respective
transmission planning regions.\156\ The Commission also found that the
use of ``likely future scenarios'' would not expand the class of
customers who would be identified as beneficiaries because it is
limited to scenarios in which a beneficiary is identified as such on
the basis of the cost causation principle.
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\156\ Id.
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70. The Commission clarified that public utility transmission
providers may rely on scenario analyses in the preparation of a
regional transmission plan and the selection of new transmission
facilities for cost allocation purposes. If a project or group of
projects is shown to have benefits in one or more of the transmission
planning scenarios identified by public utility transmission providers
in their Commission-approved Order No. 1000-compliant cost allocation
methods, Principle 2 would be satisfied.
b. Requests for Rehearing or Clarification
71. Organization of MISO States argues that the Commission erred in
paragraph 690 of Order No. 1000-A when it concluded that if a project
or group of projects is shown to have benefits in any one of the
transmission planning scenarios studied by a public utility
transmission provider in its planning process, then the conditions for
satisfaction of Cost Allocation Principle 2 will be determined to have
been met. It contends that, in response to ITC Companies' request for
clarification, the Commission stated that a ``likely future scenario''
that would justify an allocation of costs for new transmission
facilities includes the transmission planning scenarios being used by a
transmission provider to prepare a regional transmission plan.\157\
Organization of MISO States is concerned that the Commission's
clarification reads out of Principle 2 the concept of the likelihood of
a future scenario by suggesting that Principle 2 would be satisfied if
benefits are shown under any scenario studied by the transmission
provider in its planning process.\158\ Accordingly, Organization of
MISO States requests that the Commission clarify that its discussion in
paragraph 690 of Order No. 1000-A only applies to likely future
scenarios as required by Principle 2.
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\157\ Organization of MISO States at 2 (quoting Order No. 1000-
A, 139 FERC ] 61,132 at P 690 (``If a project or group of projects
is shown to have benefits in one or more of the transmission
planning scenarios identified by public utility transmission
providers in their Commission-approved Order No. 1000-compliant cost
allocation methods, Principle 2 would be satisfied.'')).
\158\ Id.
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c. Commission Determination
72. We clarify that in finding that Cost Allocation Principle 2
would be satisfied if a project or group of projects is shown to have
benefits in one or more of the transmission planning scenarios
identified by public utility transmission providers in their
Commission-approved Order No. 1000-compliant cost allocation methods,
we did not intend to remove the ``likely future scenarios'' concept
from transmission planning. We believe the evaluation of likely future
scenarios can be an important factor in public utility transmission
providers' consideration of transmission projects and in the
identification of beneficiaries consistent with the cost causation
principle.
IV. Information Collection Statement
73. The Office of Management and Budget (OMB) regulations require
that OMB approve certain information collection requirements imposed by
an agency.\159\ The revisions in Order Nos. 1000 and 1000-A to the
information collection requirements were approved under OMB Control No.
1902-0233. While this order provides clarification, it does not modify
any information collection requirements. Accordingly, a copy of this
order will be sent to OMB for informational purposes only.
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\159\ 5 CFR 1320.11.
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V. Document Availability
74. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
75. From the Commission's Home Page on the Internet, this
information is
[[Page 64903]]
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.
76. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from FERC Online Support at 202-
502-6652 (toll free at 1-866-208-3676) or email at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
VI. Effective Date
77. Changes to Order Nos. 1000 and 1000-A made in this order on
rehearing and clarification will be effective on November 23, 2012.
By the Commission. Commissioner LaFleur is dissenting in part with
a separate statement. Commissioner Clark is not participating.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Note: The following appendices will not be published in the
Code of Federal Regulations.
Appendix A: Abbreviated Names of Petitioners
------------------------------------------------------------------------
Abbreviation Petitioner names
------------------------------------------------------------------------
AEP.......................................... American Electric Power
Service Corporation.
MISO Transmission Owners Group 2............. The Midwest ISO
Transmission Owners for
this filing consist of:
Ameren Services Company,
as agent for Union
Electric Company d/b/a
Ameren Missouri, Ameren
Illinois Company d/b/a
Ameren Illinois and
Ameren Transmission
Company of Illinois;
City Water, Light &
Power (Springfield, IL);
Dairyland Power
Cooperative; Great River
Energy; Hoosier Energy
Rural Electric
Cooperative, Inc.;
Indianapolis Power &
Light Company;
MidAmerican Energy
Company; Minnesota Power
(and its subsidiary
Superior Water, L&P);
Montana-Dakota Utilities
Co.; Northern Indiana
Public Service Company;
Northern States Power
Company, a Minnesota
corporation, and
Northern States Power
Company, a Wisconsin
corporation,
subsidiaries of Xcel
Energy Inc.;
Northwestern Wisconsin
Electric Company; Otter
Tail Power Company;
Southern Illinois Power
Cooperative; Southern
Indiana Gas & Electric
Company (d/b/a Vectren
Energy Delivery of
Indiana); Southern
Minnesota Municipal
Power Agency; and
Wolverine Power Supply
Cooperative, Inc.
Oklahoma Gas and Electric Company............ Oklahoma Gas and Electric
Company.
Organization of MISO States.................. Illinois Commerce
Commission; Indiana
Utility Regulatory
Commission; Iowa
Utilities Board;
Kentucky Public Service
Commission; Michigan
Public Service
Commission; Minnesota
Public Utilities
Commission; Missouri
Public Service
Commission; Wisconsin
Public Service
Commission; and Montana
Public Service
Commission.
Transmission Access Policy Study Group....... Transmission Access
Policy Study Group.
------------------------------------------------------------------------
LaFLEUR, Commissioner, dissenting in part:
As part of today's order, the Commission affirms its holding in
Order No. 1000-A that an incumbent transmission provider may not
retain a federal right of first refusal (ROFR) for a new
transmission project--even a local reliability project--if that
project receives any amount of regional funding.\1\ After further
consideration, I believe this decision is premature and denies
transmission-planning regions the flexibility to define local
projects. I am now persuaded that the Commission should have
deferred judgment on this issue until compliance, where it could
have evaluated--on a case-by case-basis--proposals to define local
projects in light of the principles underlying elimination of the
ROFR and the requirement that costs must be allocated in a manner
that is at least roughly commensurate with benefits. Because I would
grant rehearing on this point, and defer the issue to compliance, I
respectfully dissent in part from today's order.
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\1\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 76 FR 49842
(Aug. 11, 2011), FERC Stats. & Regs. ] 31,323 (2011), order on
reh'g, Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ]
61,132 at P 430 (2012).
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In Order No. 1000, the Commission eliminated the ROFR for
projects ``selected in a regional transmission plan for purposes of
cost allocation'' but allowed it to continue for local projects.\2\
In response, certain petitioners requested guidance as to whether
the requirement to remove the ROFR for projects ``selected in a
regional transmission plan for purposes of cost allocation''
required eliminating it in two specific situations: First, when
costs are allocated only to multiple transmission providers within a
single, local zone; and second, when local reliability projects
receive some amount of regional funding as part of a cost allocation
methodology.\3\ In essence, petitioners requested clarification as
to whether these specific cost allocation mechanisms converted
otherwise local reliability projects to regional projects for
purposes of eliminating the ROFR.
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\2\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 313, 318;
see also P 63 (defining local projects).
\3\ Order No. 1000-A, 139 FERC ] 61,132 at PP 409-410; see also
n. 495 (examples of cost allocation methodologies reflecting
distinctions between regional and local projects that were
previously approved by the Commission.).
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With respect to the question about zones, in Order No. 1000-A
the Commission acknowledged that ``there may be a continuum of
examples'' that require fact specific determinations.\4\ Rather than
lay down a categorical rule, the Commission opted for flexibility
and invited parties to raise their specific situations on
compliance.\5\ Today's order affirms this approach.
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\4\ Id. P 424.
\5\ Id.
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In contrast, in Order 1000-A the Commission did reach a
definitive conclusion with respect to whether any amount of regional
funding converts an otherwise local reliability project in to a
regional project for purposes of the ROFR. The Commission clarified,
without explanation,\6\ that the ROFR must be eliminated if a
project receives any amount of regional funding.\7\ As a result, a
local reliability project that receives any amount of regional
funding, no matter how small, is no longer local for purposes of the
ROFR. Today's order summarily affirms this decision.
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\6\ For example, the Commission did not explain, in light of its
distinction in Order No, 1000 between projects in a regional plan
and projects ``selected in a regional transmission plan for purposes
of cost allocation,'' why eliminating the ROFR for projects
``selected in a regional transmission plan for purposes of cost
allocation'' requires eliminating it for local projects that are
primarily locally funded.
\7\ Id. P 430.
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After further consideration, I believe the Commission acted
prematurely in concluding that any amount of regional funding
converts an otherwise local reliability project to a regional
project for purposes of the ROFR. By reaching this conclusion in the
abstract, without the benefit of considering stakeholder-vetted
proposals to define local projects in light of the principles
underlying elimination of the ROFR and the requirement that costs
must be allocated in a manner that is at least roughly commensurate
with
[[Page 64904]]
benefits, the Commission has denied transmission planning regions
the flexibility it wisely acknowledged to be necessary with respect
to the zone issue. I agree with SPP and OGE that we should provide
that flexibility.\8\
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\8\ In its request for clarification of Order 1000-A, SPP seeks
guidance on how to reconcile the definitions and principles
underlying Order No. 1000 with the Commission's summary
determination in Order No. 1000-A that any amount of regional
funding for local reliability projects requires elimination of the
ROFR. See SPP Request for Clarification at 7-16. Unlike my
colleagues, I believe that SPP's filing may properly be
characterized as a request for clarification, and therefore, should
be addressed in this order. However, I would not reach the merits of
SPP's arguments. Instead, I would grant rehearing on the grounds
that the Commission should have deferred deciding the issue until
compliance and invite SPP to make its arguments on compliance.
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In Order No. 1000, the Commission balanced many competing policy
considerations in an effort to adopt the reforms necessary to assure
just and reasonable rates.\9\ This balance may be most pronounced in
the Commission's efforts to ensure that the regional planning
process is broad, inclusive, and fair, while at the same time,
mindful of the obligations and attributes of incumbent transmission
providers. The Commission also went to great lengths to provide
transmission-planning regions with the flexibility to negotiate cost
allocation methodologies that allocate costs in a manner that they
believe is at least roughly commensurate with benefits. Where the
mutual achievement of these objectives raises complex questions, as
it does with respect to whether any amount of regional funding
converts an otherwise local reliability project in to a regional
project for purposes of the ROFR, the Commission should decide the
issue on compliance, with a record, rather than by establishing
categorical rules that may undermine the planning and cost
allocation goals Order No. 1000 was intended to achieve.\10\
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\9\ Order 1000-B at P 55.
\10\ See e.g. OGE Request for Rehearing at 6 (``[T]he broad
definition of what constitutes regional cost allocation would
prohibit regional entities such as SPP from adopting approaches they
believe would effectively allocate costs and fairly balance
stakeholder interests.'').
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Accordingly, I respectfully dissent in part.
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Cheryl A. LaFleur,
Commissioner.
[FR Doc. 2012-26111 Filed 10-23-12; 8:45 am]
BILLING CODE 6717-01-P
