[Federal Register Volume 77, Number 105 (Thursday, May 31, 2012)]
[Rules and Regulations]
[Pages 32183-32306]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-12418]
[[Page 32183]]
Vol. 77
Thursday,
No. 105
May 31, 2012
Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Transmission Planning and Cost Allocation by Transmission Owning and
Operating Public Utilities; Final Rule
Federal Register / Vol. 77 , No. 105 / Thursday, May 31, 2012 / Rules
and Regulations
[[Page 32184]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM10-23-001; Order No. 1000-A]
Transmission Planning and Cost Allocation by Transmission Owning
and Operating Public Utilities
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Order on rehearing and clarification.
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SUMMARY: The Federal Energy Regulatory Commission affirms its basic
determinations in Order No. 1000, 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: This order on rehearing and clarification will be effective on
July 2, 2012.
FOR FURTHER INFORMATION CONTACT:
John Cohen, Federal Energy Regulatory Commission, Office of the General
Counsel, 888 First Street NE., Washington, DC 20426, (202) 502-8705.
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.
Order No. 1000-A
Order On Rehearing and Clarification
Issued May 17, 2012
Table of Contents
Paragraph
No.
I. Introduction............................................. 1
II. The Need for Reform..................................... 4
A. Final Rule........................................... 4
B. Requests for Rehearing and Clarification............. 13
1. Arguments Regarding Whether the Commission 13
Provided Substantial Evidence for the Transmission
Planning and Cost Allocation Reforms...............
C. Commission Determination............................. 50
III. Transmission Planning.................................. 102
A. Regional Transmission Planning Process............... 102
1. Legal Authority for Order No. 1000's Transmission 103
Planning Reforms...................................
a. Final Rule................................... 103
b. Order No. 1000's Interpretation of FPA 108
Section 202(a).................................
i. Requests for Rehearing and Clarification. 108
ii. Commission Determination................ 121
c. Role of FPA Section 217(b)(4)................ 159
i. Requests for Rehearing and Clarification. 159
ii. Commission Determination................ 168
d. Effect on Integrated Resource Planning and 180
State Authority Over Transmission Siting,
Permitting, and Construction...................
i. Requests for Rehearing and Clarification. 180
ii. Commission Determination................ 186
e. Legal Authority Related to Consideration of 195
Transmission Needs Driven by Public Policy
Requirements...................................
i. Requests for Rehearing and Clarification. 195
ii. Commission Determination................ 203
f. Legal Issues Related to Order No. 1000's 217
Interregional Transmission Coordination Reforms
i. Requests for Rehearing and Clarification. 217
ii. Commission Determination................ 222
g. Other Legal Issues Related to Regional 228
Transmission Planning Requirements.............
i. Requests for Rehearing and Clarification. 228
ii. Commission Determination................ 230
2. Regional Transmission Planning Requirements...... 232
a. Final Rule................................... 232
b. Requests for Rehearing and Clarification..... 235
c. Commission Determination..................... 263
3. Consideration of Transmission Needs Driven by 302
Public Policy Requirements.........................
a. Final Rule................................... 302
b. Requests for Rehearing and Clarification..... 304
c. Commission Determination..................... 317
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B. Nonincumbent Transmission Developers................. 340
1. Legal Authority.................................. 341
a. Final Rule................................... 341
b. Requests for Rehearing and Clarification..... 345
i. Arguments That the Commission Does Not 345
Have the Authority To Eliminate a Federal
Right of First Refusal.....................
1(a) Commission Determination............................... 357
ii. Arguments That the Commission Is 371
Inappropriately Regulating the Construction
of Transmission............................
1(a) Commission Determination............................... 377
iii. Arguments That the Commission Must Meet 383
the Mobile-Sierra Public Interest Standard
Before Requiring Federal Rights of First
Refusal To Be Removed From Agreements......
1(a) Commission Determination............................... 388
2. Requirement To Remove a Federal Right of First 392
Refusal from Commission-Jurisdictional Tariffs and
Agreements, and Limits on the Applicability of That
Requirement........................................
a. Final Rule................................... 392
b. Requests for Rehearing and Clarification..... 395
c. Commission Determination..................... 415
3. Framework To Evaluate Transmission Projects 431
Submitted for Selection in the Regional Plan for
Purposes of Cost Allocation........................
a. Qualification Criteria To Submit a 432
Transmission Project for Selection in the
Regional Transmission Plan for Purposes of Cost
Allocation.....................................
i. Final Rule............................... 432
ii. Requests for Rehearing and Clarification 433
iii. Commission Determination............... 439
b. Evaluation of Proposals for Selection in the 445
Regional Transmission Plan for Purposes of Cost
Allocation.....................................
i. Final Rule............................... 445
ii. Requests for Rehearing and Clarification 446
iii. Commission Determination............... 452
c. Reevaluation of Regional Transmission Plans 457
When There Is a Project Delay and Reliability
Compliance Obligations of Transmission
Developers.....................................
i. Final Rule............................... 457
ii. Requests for Rehearing and Clarification 460
iii. Commission Determination............... 477
d. Recovery of Abandoned Plant Costs and 484
Backstop Authority.............................
i. Final Rule............................... 484
ii. Requests for Rehearing.................. 485
iii. Commission Determination............... 489
C. Interregional Transmission Coordination.............. 493
1. Interregional Transmission Coordination 493
Requirements.......................................
a. Interregional Transmission Coordination 493
Procedures and Geographical Scope..............
i. Final Rule............................... 493
ii. Requests for Rehearing and Clarification 495
iii. Commission Determination............... 500
2. Implementation of the Interregional Transmission 506
Coordination Requirements..........................
a. Procedure for Joint Evaluation............... 506
i. Final Rule............................... 506
ii. Requests for Rehearing and Clarification 507
iii. Commission Determination............... 509
b. Stakeholder Participation.................... 513
i. Final Rule............................... 513
ii. Requests for Rehearing and Clarification 514
iii. Commission Determination............... 518
IV. Cost Allocation......................................... 523
A. Legal Authority for Cost Allocation Reforms.......... 525
1. Final Rule....................................... 525
2. Requests for Rehearing or Clarification.......... 530
a. Petitioners' Arguments That The FPA Requires 530
a Contract Before Costs Are Allocated..........
b. Arguments That Order No. 1000's Cost 548
Allocation Reforms Are Inconsistent With the
Cost Causation Principle.......................
c. Arguments That The Commission Did Not Show 551
That Existing Rates Are Unjust and Unreasonable
3. Commission Determination......................... 555
B. Cost Allocation Method for Regional Transmission 593
Facilities.............................................
1. Final Rule....................................... 593
2. Requests for Rehearing and Clarification......... 597
3. Commission Determination......................... 613
C. Cost Allocation Method for Interregional Transmission 626
Facilities.............................................
1. Final Rule....................................... 626
2. Requests for Rehearing or Clarification.......... 631
3. Commission Determination......................... 634
D. Principles for Regional and Interregional Cost 638
Allocation.............................................
1. Use of a Principles-Based Approach............... 638
a. Arguments That Principles-Based Cost 640
Allocation Methods Are Unfair and Arguments
Related to Commission Determination of Cost
Allocation Method Pursuant to the Compliance
Process........................................
i. Commission Determination................. 647
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2. Cost Allocation Principle 1--Costs Allocated in a 654
Way That Is Roughly Commensurate With Benefits.....
a. Requests for Rehearing or Clarification...... 658
i. Commission Determination................. 674
3. Cost Allocation Principle 2--No Involuntary 684
Allocation of Costs to Non-Beneficiaries...........
a. Final Rule................................... 684
b. Requests for Rehearing or Clarification...... 686
c. Commission Determination..................... 689
4. Cost Allocation Principle 3--Benefit To Cost 692
Threshold Ratio....................................
a. Final Rule................................... 692
b. Request for Rehearing or Clarification....... 694
c. Commission Determination..................... 695
5. Cost Allocation Principle 4--Allocation To Be 696
Solely Within Transmission Planning Region(s)
Unless Those Outside Voluntarily Assume Costs......
a. Final Rule................................... 696
b. Requests for Rehearing or Clarification...... 697
c. Commission Determination..................... 707
6. Whether To Establish Other Cost Allocation 715
Principles.........................................
a. Final Rule................................... 715
b. Requests for Rehearing....................... 716
c. Commission Determination..................... 717
E. Application of Cost Allocation Principles............ 718
1. Participant Funding.............................. 718
a. Final Rule................................... 718
b. Requests for Rehearing or Clarification...... 719
c. Commission Determination..................... 726
F. Other Cost Allocation Issues......................... 738
1. Final Rule....................................... 738
2. Requests for Rehearing or Clarification.......... 739
3. Commission Determination......................... 745
V. Compliance and Reciprocity............................... 748
A. Compliance........................................... 748
1. Final Rule....................................... 748
2. Requests for Rehearing or Clarification.......... 749
3. Commission Determination......................... 751
B. Reciprocity.......................................... 754
1. Final Rule....................................... 754
2. Requests for Rehearing or Clarification.......... 755
3. Commission Determination......................... 771
VI. Information Collection Statement........................ 779
VII. Document Availability.................................. 784
VIII. Effective Date and Congressional Notification......... 787
Appendix A: Abbreviated Names of Petitioners
Appendix B: Pro Forma Open Access Transmission Tariff
Attachment K
I. Introduction
1. In Order No. 1000, the Commission amended 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. 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 allocation method
must satisfy six cost allocation principles.
3. 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 rejects
requests to eliminate, or substantially modify, the various reforms
adopted in Order No. 1000; however, we do make a number of
clarifications.\1\ We address each of the arguments made by petitioners
in turn.\2\
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\1\ No changes are being made to the regulatory text previously
adopted, because any reference to Order No. 1000 (as well as to
Order Nos. 888 and 890) in the existing regulatory text is meant to
include any clarifications or changes made in subsequent orders on
rehearing or clarification (e.g., Order Nos. 888-A, 890-A, and the
instant Order No. 1000-A, etc.). The Commission has chosen this
convention to help promote readability of the regulatory text.
\2\ A list of petitioners filing requests for rehearing and/or
clarification is provided in Appendix A. An untimely request for
rehearing was filed by the New Jersey Board of Public Utilities (New
Jersey BPU). Pursuant to section 313(a) of the Federal Power Act
(FPA), 16 U.S.C. 8251(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 New Jersey BPU'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).
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[[Page 32187]]
II. The Need for Reform
A. Final Rule
4. In Order No. 1000, the Commission concluded that it was
appropriate to adopt the package of reforms addressing transmission
planning and cost allocation set forth in the order, stating that its
review of the record, as well as recent studies, indicated that the
transmission planning and cost allocation requirements of Order No. 890
\3\ were an inadequate foundation for public utility transmission
providers to address challenges they currently face or will face in the
near future.\4\ The Commission found that the record was adequate to
support its conclusion that the existing requirements of Order No. 890
are too narrowly focused geographically and fail to provide for
adequate analysis of the benefits associated with interregional
transmission facilities traversing neighboring transmission planning
regions.\5\
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\3\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008),
order on reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009), order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
\4\ Id. P 42.
\5\ Id. P 373.
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5. The Commission found that recent increases in transmission
investment in fact support the need to ensure that transmission
planning and cost allocation requirements are adequate to support more
efficient and cost-effective investment decisions.\6\ It noted that
this increase appears to be only the beginning of a longer-term period
of investment in new transmission facilities, which is being driven, in
part, by changes in the generation mix. Specifically, the Commission
explained that existing and potential environmental regulation and
state renewable portfolio standards are driving significant changes in
the mix of resources, resulting in the early retirement of some coal-
fired generation, increased reliance on natural gas for electricity
generation, and large-scale integration of renewable generation.\7\ The
Commission stated that these shifts in the generation fleet increase
the need for new transmission and that the existing transmission grids
were not built to accommodate them.\8\ It stated that the increased
focus on investment in new transmission projects makes it even more
critical to implement the reforms to ensure that the more efficient or
cost-effective projects come to fruition. In short, the Commission
stated that the record in this proceeding and the cited reports confirm
that additional, and potentially significant, investment in new
transmission facilities will be required in the future to meet
reliability needs and integrate new sources of generation. The
Commission concluded that it was, therefore, critical that it act now
to address deficiencies to ensure that more efficient or cost-effective
investments are made as the industry addresses these challenges.
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\6\ Id. P 44.
\7\ Id. P 45.
\8\ Id.
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6. The Commission then stated that it would not wait for systemic
problems to undermine transmission planning before action is taken.
Rather, the Commission concluded that it must act promptly to establish
the rules and processes necessary to allow public utility transmission
providers to ensure planning of and investment in the right
transmission facilities as the industry moves forward to address the
many challenges it faces. The Commission noted that such planning is a
complex process that requires consideration of a broad range of factors
and an assessment of their significance over a period that can extend
decades into the future, and that the development of transmission
facilities can involve long lead times and complex problems related to
design, siting, permitting, and financing.\9\ Given the need to deal
with these matters over a long time horizon, the Commission concluded
that it is appropriate and prudent to act at this time rather than
allowing the problems in transmission planning and cost allocation to
continue or to increase.
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\9\ Id. P 50.
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7. The Commission concluded that its actions are consistent with
the D.C. Circuit's opinions in National Fuel and Associated Gas
Distributors.\10\ Consistent with National Fuel, the Commission found
that the problem it seeks to resolve, i.e., the narrow focus of current
planning requirements and the shortcomings of current cost allocation
practices, represents a significant ``theoretical threat'' that
justifies Order No. 1000's requirements and is not one that the
Commission can address adequately or efficiently through the
adjudication of individual complaints.\11\ The Commission explained
that the actual experiences cited in the record provide additional
support for action but are not necessary to justify the remedy, and
that the remedy is justified by the theoretical threat identified
therein.\12\
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\10\ Id. P 51 (citing National Fuel Gas Supply Corp. v. FERC,
468 F.3d 831 (D.C. Cir. 2006) (National Fuel); Associated Gas
Distrib. v. FERC, 824 F.2d 981 (D.C. Cir. 1985) (Associated Gas
Distributors)).
\11\ Id. P 52.
\12\ Id. P 53.
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8. The Commission also explained that the facts and findings of
Associated Gas Distributors are in no way comparable to the matters
involved in this proceeding.\13\ It disagreed that its reforms will
have an impact on the industry that is comparable to the impact at
issue in Associated Gas Distributors. The Commission pointed out that
compliance with Order No. 1000 will involve the adoption and
implementation of additional processes and procedures, and that many
public utility transmission providers already engage in processes and
procedures of this type, even if some public utility transmission
providers may need to do more than others to comply.\14\
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\13\ Id. P 54-55.
\14\ Id. P 56-57.
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9. The Commission disagreed with assertions that it relied on
unsubstantiated allegations of discriminatory conduct or that the
current Order No. 890 processes have not been in place long enough to
justify the reforms.\15\ It stated that it need not make specific
factual findings of discrimination to promulgate a generic rule to
ensure just and reasonable rates or eliminate undue discrimination.
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\15\ Id. P 58.
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10. The Commission disagreed with claims that any concerns with
current transmission planning and cost allocation processes are better
dealt with on a case-specific basis rather than through a generic
rule.\16\ The Commission stated that while the concerns it has with
existing planning and cost allocation processes may not affect each
region of the country equally, it nonetheless remained concerned that
the existing processes are inadequate to ensure the development of more
efficient and cost-effective transmission. It noted that it is well-
established that the choice between rulemaking and case-by-case
adjudication lies primarily in the informed discretion of the
administrative agency. It also noted that
[[Page 32188]]
each transmission planning region has unique characteristics, and Order
No. 1000 provided significant flexibility to transmission planning
regions to accommodate regional differences.\17\
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\16\ Id. P 60.
\17\ Id. P 61.
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11. On the specific issue of nonincumbent transmission developers,
the Commission found that there was sufficient justification in the
record to implement the elimination of federal rights of first refusal
contained in Commission-jurisdictional tariffs or agreements. It noted
that although it previously accepted in some cases, and rejected in
others, a federal right of first refusal, it found its reasoning in the
cases rejecting the federal right of first refusal to be more
persuasive. In particular, the Commission stated that it rejected a
federal right of first refusal based on an expectation that ``[t]he
presence of multiple transmission developers would lower costs to
customers.'' \18\ The Commission explained 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 a region's needs.\19\ In addition, the Commission
required all public utility transmission providers to adopt a framework
that requires, among other things, the development of qualification
criteria and protocols for the submission and evaluation of proposed
transmission projects.\20\
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\18\ Cleco Power LLC, 101 FERC ] 61,008 at P 117 (2002), order
terminating proceedings, 112 FERC ] 61,069 (2005); see also Carolina
Power and Light Co., 94 FERC ] 61,273 at 62,010, order on reh'g, 95
FERC ] 61,282 at 61,995 (2001) (finding that a federal right of
first refusal would unduly limit the planning authority and present
the possibility of discrimination by self-interested transmission
owners, potentially reduce reliability, and possibly precluding
lower cost or superior transmission facilities or upgrades by third
parties from being planned and constructed).
\19\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 256.
\20\ Id. P 7.
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12. Regarding its cost allocation reforms, the Commission concluded
in Order No. 1000 that considering the changes within the industry and
the implementation of other reforms in Order No. 1000, the requirements
of Order No. 890 were no longer adequate to ensure rates, terms and
conditions of jurisdictional service are just and reasonable and not
unduly discriminatory or preferential.\21\ It found that the challenges
associated with allocating the cost of transmission appear to have
become more acute as the need for transmission infrastructure has
grown.\22\ The Commission explained that within RTO or ISO regions,
particularly those that encompass several states, the allocation of
transmission costs is often contentious and prone to litigation.\23\ It
also noted that in other regions, few rate structures are currently in
place that reflect an analysis of the beneficiaries of a transmission
facility and provide for the corresponding cost allocation of the
transmission facility's cost.\24\ Similarly, the Commission noted that
there are few rate structures in place today that provide for the
allocation of costs of interregional transmission facilities.\25\
Finally, the Commission found that the lack of clear ex ante cost
allocation methods that identify beneficiaries of proposed regional and
interregional transmission facilities may be impairing the ability of
public utility transmission providers to implement more efficient or
cost-effective transmission solutions identified during the
transmission planning process.\26\
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\21\ Id. P 497.
\22\ Id. P 498.
\23\ Id. P 498.
\24\ Id. P 498.
\25\ Id. P 498.
\26\ Id. P 499.
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B. Requests for Rehearing and Clarification
1. Arguments Regarding Whether the Commission Provided Substantial
Evidence for the Transmission Planning and Cost Allocation Reforms
13. While several petitioners seeking rehearing or clarification
express general support for Order No. 1000,\27\ others argue that the
Commission failed to provide adequate justification under FPA section
206 for adopting its reforms.\28\ Coalition for Fair Transmission
Policy acknowledges that the circumstances against which the Commission
must fulfill its statutory responsibilities change with developments in
the electric industry, including changes with respect to demands on the
transmission grid; however, it argues that Order No. 1000 takes the
principle several steps beyond the Commission's existing statutory
authority. Coalition for Fair Transmission Policy contends that the
Commission makes a number of statements about problems facing the
industry that are remarkable in their ambiguity, and the existence of
problems does not empower the Commission to address every policy
problem that arises from such developments or to commandeer regional
transmission planning. Coalition for Fair Transmission Policy asserts
that, if this was the case, section 216 of the FPA, which gives the
Commission limited authority to site transmission facilities in
national interest electric transmission corridors, would not have been
necessary.
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\27\ See, e.g., AEP; WIRES; AWEA; and Energy Future Coalition
Group.
\28\ See, e.g., Large Public Power Council; Alabama PSC; Xcel;
Georgia PSC; Ad Hoc Coalition of Southeastern Utilities; and PPL
Companies.
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14. PPL Companies argue that the Commission failed to show that
existing rates, terms and conditions are unjust and unreasonable or
unduly discriminatory absent Order No. 1000.\29\ They also contend that
Order No. 1000 not only fails to identify who is being discriminated
against and who is discriminating, but never addresses whether
discrimination has actually materialized in the three years since the
Commission's last major rulemaking in this area. PPL Companies assert
that, although the Commission is empowered to act against undue
discrimination before it occurs, it must at least identify the
discrimination it seeks to remedy.\30\ They also maintain that the
Commission did not specify which rate it has found to be unjust and
unreasonable or what substantial evidence it relies upon to draw that
conclusion.
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\29\ PPL Companies at 6 (citing 16 U.S.C. 825l(b)).
\30\ PPL Companies at 6 (citing Associated Gas Distributors, 824
F.2d 981 at 1008).
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15. Similarly, California ISO asserts that the Commission failed to
identify any instance in which an existing rate is unjust,
unreasonable, or unduly discriminatory or preferential because it does
not include provisions for interregional coordination. Instead,
California ISO asserts that the Commission only offers an unsupported
hypothesis that planning between or among regions will enhance the
Commission's ability to perform its mission.
16. Oklahoma Gas and Electric Company argues that Order No. 1000
provides no evidence that existing tariff provisions that address the
construction and ownership of transmission facilities in any way result
in unjust and unreasonable rates, or in undue discrimination against
any customers. It asserts that the evidence the Commission cited is far
weaker than the evidence it relied upon to support its expansion of the
Standards of Conduct in Order No. 2004, where the court stated that
``citing no evidence demonstrating that there is in fact an industry
problem is not reasoned decision-making.'' \31\
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\31\ Oklahoma Gas and Electric Company at 14 (citing National
Fuel, 468 F.3d at 844).
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[[Page 32189]]
17. Oklahoma Gas and Electric Company also claims that Order No.
1000 is devoid of support for the conclusion that existing tariff
provisions interfere with transmission planning. It argues that there
is no evidence, anecdotal or otherwise, that current RTO transmission
planning processes generate an unreasonably limited range of options,
and that there is no evidence that projects are delayed because they
are being constructed by incumbent transmission owners. Specifically,
Oklahoma Gas and Electric Company argues that the Commission cannot
support a finding that the current transmission rules in SPP result in
rates that are unjust and unreasonable.\32\
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\32\ Oklahoma Gas & Electric Company also states that SPP's
transmission planning process is robust and almost all of the
projects are being completed within designated timeframes. It
contends that where appropriate, the process permits nonincumbent
developers to collaborate with incumbent transmission owners to
address system needs. It also asserts that the 90-day time limit for
incumbent transmission owners to agree to build a designated project
prevents a transmission provider from blocking or delaying the
construction of projects and ensures that the process is open and
transparent.
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18. Georgia PSC argues that the Commission should recognize ongoing
transmission processes that utilities are participating in and allow
them to work before inserting another process that will strain
resources.
19. Ad Hoc Coalition of Southeastern Utilities and Large Public
Power Council assert that the Commission misread National Fuel, arguing
that the court faulted the Commission for failing to support its
decision with record evidence, and was non-committal on whether a
decision might be supported by theory alone.\33\ They state that it is
incumbent on an agency to ``examine the relevant data and articulate a
satisfactory explanation for its action including a rational connection
between the facts found and the choice made.'' \34\ They further note
that National Fuel commented that ``[p]rofessing that an order
ameliorates a real industry problem but then citing no evidence
demonstrating that there is in fact an industry problem is not reasoned
decision-making.'' \35\
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\33\ Ad Hoc Coalition of Southeastern Utilities at 16 (quoting
National Fuel, 468 F.3d at 844 (``[W]e express no view here whether
a theoretical threat alone would be sufficient to justify an order
extending the Standards to non-marketing affiliates.'')).
\34\ Id. at 16 (quoting Motor Vehicles Mfrs. Ass'n of U.S. v.
State Farm Mut. Auto Ins. Co., 463 U.S. 29, 43 (1983) (State Farm)).
\35\ Ad Hoc Coalition of Southeastern Utilities at 16 (quoting
National Fuel, 468 F.3d at 843).
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20. Several petitioners take issue with the Commission's conclusion
that it may act by citing to a ``theoretical threat'' rather than
providing concrete evidence that the reforms are necessary.\36\ For
example, petitioners argue that the Commission failed to set forth
substantial evidence, or any evidence, of undue discrimination to
support its reforms.\37\ Xcel adds that the Commission appears to
concede that it lacks actual evidence of undue discrimination. Ad Hoc
Coalition of Southeastern Utilities and Large Public Power Council
argue that it is reasonable to conclude that the Commission has
effectively conceded that there is no evidence justifying Order No.
1000 and that the Commission is relying on theory alone.\38\
---------------------------------------------------------------------------
\36\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Large Public Power Council; North Carolina Agencies; and Southern
Companies.
\37\ See, e.g., FirstEnergy Service Company; PSEG Companies at
25-32 (citing the APA, as well as National Fuel Gas Supply Corp. v.
FERC, 468 F.3d 831, 838 (D.C. Cir. 2006) and Florida Gas
Transmission Co. v. FERC, 604 F.3d 636, 645 (D.C. Cir. 2010)); Xcel;
PSEG Companies; Sponsoring PJM Transmission Owners; Baltimore Gas &
Electric at 15 (citing Order No. 1000, FERC Stats. & Regs. ] 31,323
at P 229); Ad Hoc Coalition of Southeastern Utilities at 55 (quoting
in part Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 253);
Large Public Power Council; and MISO Transmission Owners Group 2.
\38\ Large Public Power Council also claims that the D.C.
Circuit has taken judicial notice of the efficiencies derived from
vertical integration. According to Large Public Power Council, this
means that the court is effectively insisting that the Commission
offer evidence that decisions to disaggregate utility operations
planning must overcome a presumption that the efficiencies derived
from vertical integration are not in the public interest. Large
Public Power Council at n.38 (citing National Fuel, 468 F.3d at 840
(citing Tenneco Gas v. FERC, 969 F.2d 1187, 1197 (D.C. Cir. 1992))).
---------------------------------------------------------------------------
21. Ad Hoc Coalition of Southeastern Utilities and Large Public
Power Council, as well as North Carolina Agencies, argue that the flaw
in the Commission's decision is that both the problem it aims to solve
and the solution are theoretical. Ad Hoc Coalition of Southeastern
Utilities contends that reasoned decision-making calls for
substantially more than a hypothesis that existing planning and cost
allocation mechanisms may be suboptimal, and speculation that the
mechanisms discussed in the order will result in the development of
more efficient transmission. Southern Companies also argue that the
Commission's explanation of the need for the transmission planning and
cost allocation reforms in Order No. 1000 is built entirely on
speculation.\39\ Given this, Southern Companies contend that Order No.
1000 fails to represent lawful, reasoned agency decision-making by
depending on a speculative theoretical threat to support the required
reforms rather than providing the required assessment.\40\
---------------------------------------------------------------------------
\39\ Southern Companies at 89-90 (citing Algonquin Gas
Transmission Co. v. FERC, 948 F.2d 1305 (D.C. Cir. 1991)).
\40\ Southern Companies at 91 (citing State Farm, 463 U.S. 29,
43 (1983)).
---------------------------------------------------------------------------
22. Southern Companies and Ad Hoc Coalition of Southeastern
Utilities state that Order No. 1000's reliance on an alleged
theoretical threat misinterprets precedent that agencies need to prove
theories beyond mere hypothesis or conjecture.\41\ They argue that
courts have historically allowed agencies to support orders by theory
alone when the theory itself is well supported and represents a highly
developed prediction of what actually happens in the real world.
Southern Companies, Ad Hoc Coalition of Southeastern Utilities, and
Large Public Power Council cite to Business Roundtable v. SEC, \42\
where the court concluded that the Securities and Exchange Commission
(SEC) had not adequately considered the effects of a proposed rule on
efficiency, competition and capital formation. They maintain that the
case deals with matters that are similar to the present proceeding.
---------------------------------------------------------------------------
\41\ Southern Companies at 14 (citing National Fuel; Electricity
Consumer Resource Council v. FERC, 747 F.2d 1511, 1517 (D.C. Cir.
1984) (ELCON)); Ad Hoc Coalition of Southeastern Utilities at 22-23
(citing same).
\42\ Business Roundtable v. SEC, 647 F.3d 1144 (D.C. Cir. 2011).
---------------------------------------------------------------------------
23. With respect to federal rights of first refusal, Sponsoring PJM
Transmission Owners state that Order No. 1000's hypothetical
discrimination stands in marked contrast to the concrete findings in
Order No. 888 justifying the implementation of open transmission access
and assert the Commission offers no evidentiary support for its
findings. Baltimore Gas & Electric argues that the Commission is taking
away a tariff-sanctioned right with nothing more than a ``concern''
that a right of first refusal may be leading towards rates that may
become too high. It states that if the Commission believes that the
problem is that rates will become too high, it should deal with the
problem directly by lowering them, rather than by eliminating rights of
first refusal.\43\
---------------------------------------------------------------------------
\43\ Baltimore Gas & Electric at 18 (quoting National Fuel Gas
Supply Corp. v. FERC, 468 F.3d 831, 844 (D.C. Cir. 2006)).
---------------------------------------------------------------------------
24. FirstEnergy Service Company takes issue with the Commission's
reliance on National Fuel and asserts that a tenuous application of
theory cannot support a rulemaking.\44\
[[Page 32190]]
According to FirstEnergy Service Company, while the court in National
Fuel acknowledged the possibility of an agency proceeding on theory
alone to support a rulemaking, it also cautioned that such reliance
required a substantial showing of the need in order to proceed.\45\
California ISO makes a similar argument. Both FirstEnergy Service
Company and California ISO assert that the Commission has not made any
showing similar to that described in National Fuel to justify its sole
reliance on theory.
---------------------------------------------------------------------------
\44\ FirstEnergy Service Company at 15 (citing National Fuel
Supply Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006) (National
Fuel)).
\45\ FirstEnergy Service Company at 15 (quoting National Fuel,
468 F.3d 831 at 844-45).
---------------------------------------------------------------------------
25. On the issue of the Commission's nonincumbent transmission
developer reforms, Southern Companies assert that they do not have a
federal right of first refusal and that there are no restrictions on a
nonincumbent developer's ability to pursue transmission projects in the
SERTP planning process. Southern Companies argue the Commission has
failed to articulate a legal basis for imposing its nonincumbent
requirements upon Southern Companies, when it has no right of first
refusal. Furthermore, Southern Companies argue that the reason for the
lack of nonincumbents in the Southeast is because the incumbent
transmission owners have developed a robust transmission grid and are
adequately investing in transmission. Southern Companies also assert
that there have been no significant merchant transmission projects
within their footprint because there is no congestion and generation is
not remotely located. Thus, Southern Companies argue that Order No.
1000's generic findings of undue discrimination against nonincumbents
are counter to record evidence and that to date no nonincumbents have
proposed alternative transmission projects in the SERTP. In addition,
Southern Companies state that the Commission does not have the
authority to impose nonincumbent-related development rights sua sponte
generically upon the industry.
26. Petitioners also argue that the Commission failed to identify
any established theoretical principles in support of its reforms.\46\
Southern Companies maintain that the Commission's reasoning does not
meet the scientific standards of a ``good theory,'' which it defines as
satisfying two conditions: ``[i]t must accurately describe a large
class of observations on the basis of a model that contains only a few
arbitrary elements, and it must make definite predictions about the
results of future observations.'' \47\ Xcel argues that if the
Commission intends to rely only on theoretical evidence, it must
satisfy the requirements of National Fuel by explaining why the
individual complaint procedure provided an insufficient remedy.\48\
MISO Transmission Owners Group 2 asserts that National Fuel did not
authorize the Commission to issue a rulemaking solely on the basis of a
``theoretical threat'' but indicated that if the Commission attempted
to do so, it would be required to provide a substantial explanation. It
argues that the Commission provides no such analysis, but rather
summarily indicates that the threat of abuse ``is not one that can be
addressed adequately or efficiently through the adjudication of
individual complaints.'' \49\ MISO Transmission Owners Group 2 contends
that a case-by-case analysis would be particularly appropriate in this
instance given the dearth of empirical evidence demonstrating harm,
compared to the actual examples of nonincumbent transmission developer
participation in transmission planning processes in MISO and elsewhere.
---------------------------------------------------------------------------
\46\ See, e.g., FirstEnergy Service Company; Xcel; Sponsoring
PJM Transmission Owners; PSEG Companies; and Xcel.
\47\ Southern Companies at 15 (quoting Stephen Hawking & Leonard
Mlodinow, A Briefer History of Time 13-14 (2005)).
\48\ Xcel at 13-14 (citing Nat'l Fuel, 468 F.3d 831, 834, 844
(D.C. Cir. 2006)).
\49\ MISO Transmission Owners Group 2 at 15 (quoting Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 52).
---------------------------------------------------------------------------
27. Other petitioners add that the reforms are unnecessary because
there is evidence that transmission expansion has increased
significantly over the past several years.\50\ Large Public Power
Council states that Order No. 1000 does not rely on any finding
regarding the need to increase transmission development. Some
petitioners also point to existing processes in the Southeast as
undercutting the predicate for Order No. 1000.\51\ North Carolina
Agencies assert that there is error in the Commission's unwillingness
to consider the highly developed planning processes in the region as a
relevant factor in ascertaining the need for new rules. They also claim
that although the anticipated demand for significant interregional
transmission projects to transfer large amounts of remotely located
renewable energy to fulfill public policy mandates is a major factual
predicate for the proposals articulated, this is simply not present in
the Southeast due to its resource base. They note that the Southeast
already has a robust transmission system, as recognized in DOE's 2009
Transmission Congestion Study. North Carolina Agencies state that
utilities in the Southeast remain vertically integrated and provide
bundled retail service; the bulk of the resulting transmission cost is
included in, and recovered through, state approved bundled retail
rates. Thus, they argue that the evidence demonstrates that needed
transmission investment is not lacking with respect to the utilities in
the Southeast.
---------------------------------------------------------------------------
\50\ See, e.g., PSEG Companies.
\51\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
North Carolina Agencies; and Southern Companies.
---------------------------------------------------------------------------
28. Southern Companies raise similar arguments with respect to
existing regional transmission planning, interregional transmission
coordination, and cost allocation processes in the Southeast, claiming
that the new planning processes will not be associated with any
previously unidentified new load growth, supply or demand side
resource, or transmission service request because all of those elements
are already addressed in the bottom-up planning processes. Southern
Companies further argue that because Order No. 1000 lacks a process to
identify new solutions, it will only serve to potentially optimize
existing upgrades, which is already occurring due to extensive
coordination with neighboring utilities in the Southeast. Ad Hoc
Coalition of Southeastern Utilities raise similar arguments, and add
that Order No. 1000's concern that some regional transmission planning
processes permitted by Order No. 890 are only a forum to confirm
simultaneous feasibility does not apply to planning processes in the
Southeast.
29. Southern Companies explain that their Order No. 890 Attachment
K compliance filing was accepted as of July 2010, and none of the
changed circumstances cited in Order No. 1000 has occurred since then.
Southern Companies assert that the Commission ignored evidence
addressing their existing transmission planning processes and
explaining how those processes assure consideration of better regional
solutions and support just and reasonable rates. Southern Companies
assert that unless detailed facts show existing cost allocation methods
are impairing the proposal and consideration of better regional
solutions, Order No. 1000 may not lawfully determine they are causing
Southern Companies' rates, terms, and conditions for transmission
service to be unjust and unreasonable. They also argue that, although
the Commission is permitted in certain circumstances to make generic
findings in support of its rulemaking, specific findings for specific
entities are required when the
[[Page 32191]]
actual facts applicable to those entities run counter to generic
principles.\52\ They add that, on rehearing, the Commission must
address substantial evidence that supports the justness and
reasonableness of Southern Companies' existing processes in determining
whether the reforms of Order No. 1000 should be applied to supplant
such processes, or exclude Southern Companies from Order No. 1000's
generic findings.
---------------------------------------------------------------------------
\52\ Southern Companies at 92 (citing National Fuel, 468 F. 3d
at 839).
---------------------------------------------------------------------------
30. Ad Hoc Coalition of Southeastern Utilities add that there are
no planning gaps that need to be filled in the Southeast by the
Commission's interregional coordination requirements. Ad Hoc Coalition
of Southeastern Utilities and Southern Companies assert that the
Southeastern utilities already share on an interregional basis data
containing all of the information needed to make informed and efficient
planning decisions. Ad Hoc Coalition of Southeastern Utilities further
argues that the implication that additional interregional coordination
will identify whether interregional transmission facilities are more
efficient or cost-effective than regional transmission facilities is
unfounded, and involves integrated resource planning analysis and
`optimatization' analyses along the seams/interfaces that already occur
in the Southeast. Ad Hoc Coalition of Southeastern Utilities concludes
that the Commission's holdings regarding its interregional coordination
requirements are unfounded and counter to the record evidence.
31. Moreover, Ad Hoc Coalition of Southeastern Utilities and
Southern Companies assert that the factual record in this rulemaking
demonstrates that the required interregional coordination reforms are
likely to do more harm than good. For instance, Ad Hoc Coalition of
Southeastern Utilities and Southern Companies state that it is costly
to negotiate many coordination agreements and parallel OATT language
with many different entities and to prospectively implement multiple
bureaucratic requirements.
32. Sacramento Municipal Utility District argues that a generic
rule is arbitrary and inappropriate to address a problem that exists,
if at all, only in isolated pockets.\53\ It also argues that the
Commission cannot defend its actions on purely theoretical grounds
unless it abandons its unsubstantiated claim that an actual problem
exists.\54\ Sacramento Municipal Utility District states that to the
extent the Commission's rule was adopted to address a theoretical
problem, it has failed to meet its burden of establishing that the
burdens and costs imposed by the rule are justified by the threat to be
addressed.\55\ With respect to transmission planning in particular,
Sacramento Municipal Utility District contends that the assertion that
regional planning taking place under Order No. 890 is insufficient and
producing unjust and unreasonable rates is premised on the existence of
an actual, not theoretical, problem. It states that there is no
evidence to support this assertion, and no evidence that the alleged
problem affects more than a few isolated regions of the country.
Sacramento Municipal Utility District adds that Order No. 1000 scarcely
acknowledges comments documenting the success of various regional
planning efforts, but instead refers to generalized statements of
concern about potential problems in unidentified regions of the country
involving unidentified utilities. It states that this is not the type
of evidence upon which a rule purporting to address a national problem
can be sustained and this is the same problem that resulted in the
remand in National Fuel.\56\ It argues that the Commission failed to
establish that the burdens imposed by Order No. 1000 are justified by
the threat addressed,\57\ and that Order No. 1000 fails the test of
reasoned decision-making, citing the fact that Order No. 1000 failed to
take into account whether imposition of its mandatory cost allocation
provisions will discourage rather than facilitate regional planning.
Alabama PSC likewise contends that the speculative benefits identified
in Order No. 1000 are not legally sufficient to justify the rule's
burdens and disruptions and, as such, Order No. 1000 is not justified
under the Commission's authority under section 206. Alabama PSC
encourages the Commission to consider a regional or case-by-case
approach if the Commission continues to believe that it should move
forward with this initiative.
---------------------------------------------------------------------------
\53\ Sacramento Municipal Utility District at 4 (citing
Associated Gas Distributors, 824 F.2d 981 at 1019).
\54\ Sacramento Municipal Utility District at 5 (citing National
Fuel, 468 F.3d at 839).
\55\ Sacramento Municipal Utility District at 5 (citing National
Fuel, 468 F.3d at 844).
\56\ Sacramento Municipal Utility District at 32 (citing Nat'l
Fuel Gas Supply Corp. v. FERC, 468 F.3d 831, 844 (D.C. Cir. 2006)).
\57\ Sacramento Municipal Utility District at 33 (citing Nat'l
Fuel Gas Supply Corp. v. FERC, 468 F.3d 831, 844 (D.C. Cir. 2006)).
---------------------------------------------------------------------------
33. Similarly, Ad Hoc Coalition of Southeastern Utilities contends
that Order No. 1000 violates the guidance provided by National Fuel
regarding what may be permissible by an order solely based upon a
theory, arguing that the record demonstrates that there will be little
benefit, and possible harm, if the interregional transmission
coordination requirements are implemented. Additionally, Ad Hoc
Coalition of Southeastern Utilities contend that these reforms would be
burdensome to implement, because public utility transmission providers
would have to negotiate a number of coordination agreements and
parallel OATT language with many different entities and then
prospectively implement a number of bureaucratic requirements.\58\
Southern Companies agree.
---------------------------------------------------------------------------
\58\ Ad Hoc Coalition of Southeastern Utilities at 66 (quoting
National Fuel, 468 F.3d at 844 (arguing that the Commission must
explain how the ``potential danger * * * unsupported by a record of
abuse, justifies such costly prophylactic rules.'')).
---------------------------------------------------------------------------
34. NARUC argues that Order No. 1000 does not identify actual
concerns or problems or rely on any factual record, but relies entirely
on the conclusory statement that planning and cost allocation may be
impeding the development of beneficial transmission lines. It also
argues that efforts to sort through the ambiguities and comply with
Order No. 1000 may stall existing local, regional, and DOE-funded
interconnectionwide planning processes, creating uncertainty and
requiring limited resources to be reallocated to compliance filings
rather than to finalizing plans. NARUC further asserts that Order No.
1000 is premature because the results of the interconnectionwide
planning process may eliminate the need for reform or indicate a need
for different reforms.
35. Some petitioners also take issue with the Commission's efforts
to distinguish Order No. 1000 from Associated Gas Distributors.\59\
Large Public Power Council argues that the Commission is in error in
attempting to minimize the exacting evidentiary standard for generic
rulemaking called for in Associated Gas Distributors on the ground that
the impact of the decision here is not ``comparable.'' \60\ It argues
that while the Commission states in Order No. 1000 that compliance
``will involve implementation of additional processes and procedures''
and many public utility transmission providers
[[Page 32192]]
``already engage in processes and procedures of this type,'' the goal
of Order No. 1000 is to remedy unjust and unreasonable rates on a
national basis by implementing new planning and cost recovery
procedures.\61\ Large Public Power Council asserts that even if this is
not the case, the implications of Order No. 1000 involve cost shifting
for the recovery of potentially hundreds of billions of dollars in
transmission investment. Ad Hoc Coalition of Southeastern Utilities
raises similar concerns, explaining that the attempt to distinguish
Associated Gas Distributors ``gives short shrift to the Commission's
ambitions in promulgating Order No. 1000, which is to implement new
planning and cost recovery procedures.'' \62\
---------------------------------------------------------------------------
\59\ See, e.g., Large Public Power Council; Ad Hoc Coalition of
Southeastern Utilities; MISO Transmission Owners Group 2; Southern
Companies; and Sacramento Municipal Utility District.
\60\ Large Public Power Council at 17 (quoting Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 56).
\61\ Large Public Power Council at 17-18 (quoting Order No.
1000, FERC Stats. & Regs. ] 31,323 at 56).
\62\ Ad Hoc Coalition of Southeastern Utilities at 18.
---------------------------------------------------------------------------
36. MISO Transmission Owners Group 2 maintains that, while the
Commission argued that Associated Gas Distributors states that it need
not provide empirical data for every proposition upon which it depends,
the Commission has a duty to ``respond meaningfully'' to the objections
raised by opponents of its proposal, which it failed to do.\63\
Southern Companies argue that the Commission did not squarely address
comments asserting that there was no need for an industrywide solution
when the problem applies only to a limited portion of the industry.
---------------------------------------------------------------------------
\63\ MISO Transmission Owners Group 2 at 13.
---------------------------------------------------------------------------
37. Similarly, California ISO argues that the Commission cannot
find support in Associated Gas Distributors for acting based on a
theoretical threat.\64\ In contrast to Associated Gas Distributors,
California ISO asserts that the Commission is not relying on an
economic theory to determine the means for achieving its goal, but
rather is attempting to rely on theory to establish the statutory
predicate for action.\65\ Furthermore, California ISO argues that the
Commission's hypothesis that, in a regulated market, the absence of an
ex ante cost allocation method will cause rates to be unjust or
unreasonable is not based on an established economic theory. California
ISO asserts that there is no empirical evidence for this hypothesis,
and that the Commission has not cited any peer-reviewed or other
economic analysis supporting its conclusion. As such, California ISO
concludes that such a hypothesis cannot support action under section
206.
---------------------------------------------------------------------------
\64\ California ISO at 16 (citing Associated Gas, 824 F.2d 981
at 1008-09).
\65\ California ISO at 17 (citing Associated Gas, 824 F.2d 981
at 1008-09).
---------------------------------------------------------------------------
38. In addition, California ISO argues that the Commission has not
identified any evidence to support a causal connection between a cost
allocation methodology and improved cost-effectiveness. California ISO
acknowledges two commenters that provided concrete examples that
uncertainty about cost allocation was preventing some projects from
going forward, but argues that these examples do not support the
Commission's finding.
39. MISO Transmission Owners Group 2 asserts that the Commission
relies on general suppositions to support its mandate that all rights
of first refusal be removed from Commission-jurisdictional tariffs and
contracts. For example, it states that Order No. 1000 states that
nonincumbent transmission developers seeking to invest in transmission
can be discouraged from doing so, but the Commission never identifies a
single instance of a nonincumbent transmission developer foregoing an
opportunity to invest in a transmission facility because of any
existing federal right of first refusal. MISO Transmission Owners Group
2 maintains that the Commission ignored examples it and others gave of
nonincumbent transmission developer involvement in regional planning
processes, such as the CapX2020 Transmission Capacity Expansion
Initiative, in which eleven entities, including MISO Transmission
Owners, nonincumbent transmission developers, and transmission
dependent utilities are engaged in a collaborative effort to construct
nearly 700 miles of new extra-high voltage transmission facilities from
the Dakotas to Wisconsin.
40. Similarly, MISO argues that while its existing regional
planning processes have resulted in significant transmission expansion
in the past and will result in even greater transmission construction
in the future, Order No. 1000 does not identify any evidence that
transmission planning, expansion and/or cost allocation have been
hindered or harmed by the Transmission Owners Agreement provisions
relating to the obligation to build, including any associated rights
whose nature and effects may resemble rights of first refusal. It
asserts that the Commission cannot use any evidence that may involve
other RTO, ISOs, or public utilities to draw conclusions about any
unjustness and unreasonableness of provisions in MISO's Transmission
Owners Agreement, and to require the removal or modification of such
provisions.
41. Baltimore Gas & Electric states that the Commission's rationale
for eliminating the right of first refusal has no applicability to it
and other transmission owner members of PJM since they have all
relinquished transmission planning decisions to PJM. According to
Baltimore Gas & Electric, it does not matter that transmission owners
have an economic incentive to be unduly discriminatory in transmission
planning once they have transferred that role to an RTO. Baltimore Gas
& Electric asserts that PJM's Order No. 890 compliance filing ensures
an open, transparent, and stakeholder-participatory transmission
planning process that no transmission owner member has the ability to
manipulate for anticompetitive purposes. In any event, Baltimore Gas &
Electric states that the opportunity for undue discrimination existed
in the abstract when federal right of first refusal rights were
initially approved by the Commission, and that nothing has changed to
warrant their removal now. Baltimore Gas & Electric adds that there are
opportunities for any lawfully sanctioned activity to be misused. Thus,
Baltimore Gas & Electric concludes that speculation as to how some bad
actors may misuse rights is not a rational basis for eliminating the
rights for all actors.
42. Similarly, Sunflower, Mid-Kansas, and Western Farmers dispute
Order No. 1000's conclusion that it is not in the economic self-
interest of public utility transmission providers, at least in the SPP
region, to expand the grid to permit access to competing sources of
supply to serve their customers.\66\ They note that no state in the SPP
region has enacted retail competition and, consequently, those states
would not stand for anticompetitive behavior by incumbent transmission
owners that would result in higher rates to consumers.\67\
---------------------------------------------------------------------------
\66\ Sunflower, Mid-Kansas, and Western Farmers at 3 (citing
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 254).
\67\ Sunflower, Mid-Kansas, and Western Farmers argue that this
is borne out by activity in SPP of at least two independent
transmission developers (ITC Great Plains, LLC and Prairie Wind
Transmission, LLC).
---------------------------------------------------------------------------
43. Petitioners also disagree with the Commission's conclusion that
it can rely on the benefits of competition to support the rule without
a ground for a reasonable expectation that competition may have some
beneficial impact.\68\ These petitioners disagree with the Commission's
interpretation of, and
[[Page 32193]]
citation to, Wisconsin Gas.\69\ Ad Hoc Coalition of Southeastern
Utilities and Large Public Power Council argue that Wisconsin Gas dealt
with the benefits of competition associated with promoting competitive
sales of natural gas, which Congress made a national policy. In
contrast, they argue that there is no indication that Congress has
endorsed promoting competition for the development of transmission
infrastructure. Large Public Power Council quotes the language from
Wisconsin Gas where the court stated that ``unsupported or abstract
allegations of benefits that will accrue from increased competition
cannot substitute for a conscientious effort to take into account what
is known as to past experience and what is reasonably predictable about
the future.'' \70\ Large Public Power Council asserts that here, the
Commission not only lacks any legitimate basis for a presumption that
competition in the transmission development business serves the public
interest, but fails to amass any evidence for its view.
---------------------------------------------------------------------------
\68\ See, e.g., PSEG Companies; Ad Hoc Coalition of Southeastern
Utilities at 55 (quoting Order No. 1000, FERC Stats. & Regs. ]
31,323 at P 268); and Large Public Power Council.
\69\ See, e.g., PSEG Companies; Ad Hoc Coalition of Southeastern
Utilities at 56 (citing Order No. 1000, FERC Stats. & Regs. ] 31,323
at P 268, n.243); and Large Public Power Council.
\70\ Large Public Power Council at 28 (quoting Wisconsin Gas,
770 F.2d 1144 at 1158).
---------------------------------------------------------------------------
44. A number of petitioners question the Commission's assertion
that adding more transmission developers may lead to the identification
of more efficient alternatives.\71\ Oklahoma Gas and Electric Company
asserts that the Commission has not supported the assumption that
competition between potential developers in the process of evaluating
and selecting proposed projects will result in more cost-effective
transmission service rates. Sponsoring PJM Transmission Owners argue
that precedent does not support the Commission's conclusion that the
mere invocation of general beneficial impacts of competition suffices
to support modifying rates pursuant to section 206. Sponsoring PJM
Transmission Owners also assert the real issue is not competition
between transmission providers, but rather which entity will be the
monopoly owner of a transmission line. Oklahoma Gas and Electric
Company states that nothing in Order No. 1000 will result in head-to-
head competition between service providers, or between competing lines.
It elaborates that the market will not be choosing who constructs new
projects, but rather the stakeholder process will be used to make a
choice based on uncertain estimates and inputs.
---------------------------------------------------------------------------
\71\ See, e.g., Southern Companies; Sponsoring PJM Transmission
Owners at 16, 20 (citing Williston Basin Interstate Pipeline Co. v.
FERC, 358 F.3d 45, 50 (D.C. Cir. 2004)); Ad Hoc Coalition of
Southeastern Utilities at 57 (quoting Washington Gas, 770 F.2d at
1158).
---------------------------------------------------------------------------
45. Sponsoring PJM Transmission Owners argue the Commission has not
explained or demonstrated how competition among transmission developers
would reduce the cost of transmission construction and consequently
transmission service. For instance, Sponsoring PJM Transmission Owners
state that even if a nonincumbent submits a proposal that it projects
will have the lowest cost, the Commission has produced no evidence that
its actual costs of construction will be lower than the cost the
incumbent would incur. Instead, they argue that the incumbent is far
more likely to have existing rights of way and more experience with
construction and logistical issues that may arise in its area, and thus
is better positioned politically to overcome local objections to
siting. Baltimore Gas & Electric notes that the Commission has
recognized that incumbents have certain advantages, such as a unique
knowledge of their own systems and other matters, and that the
Commission has stated that such factors can be highlighted in the
decisional process leading to project selection. Baltimore Gas &
Electric states that it is thus unclear to why the Commission would
require that the existing federal right of first refusal provision
should be eliminated if the same result can be achieved in the
decisional process by taking into account that the incumbent is better
placed to construct and own a project.
46. Sponsoring PJM Transmission Owners argue the Commission has not
explained how any reduction in construction costs--assuming it could be
achieved--would translate into lower rates, after taking into account
differing corporate structures, rates of return, and Commission-granted
incentives. Ad Hoc Coalition of Southeastern Utilities and Large Public
Power Council argue that the efficiencies that the Commission presumes
will be associated with its decisions, and that it assumes will
overcome added costs and risks, are not a matter that the Commission is
entitled to presume. Xcel argues that the Commission's rationale to
increase competition does not apply to reliability projects, which have
the narrow function of ensuring reliable service to customers.\72\
---------------------------------------------------------------------------
\72\ Xcel at 12-13 (citing Order No. 1000, FERC Stats. & Regs. ]
31,323 at P 284-85).
---------------------------------------------------------------------------
47. Some petitioners argue that the mixed record does not justify
the Commissions ruling.\73\ For instance, petitioners argue that the
Commission must, as a matter of law, take notice of efficiencies lost
and reliability problems created by the Commission's decision.\74\
Specifically, Large Public Power Council argues that planning engineers
will spend time addressing stakeholder and competitors' concerns in
Commission-sponsored planning forums rather than working to meet the
needs of their native loads. Additionally, it states that countless
hours will be needed to perform studies, reengineer systems, and
coordinate third-party construction schedules and priorities. Ameren
adds that MISO will have to expend considerable resources to re-assess
years of transmission planning work to apply the new rule.
---------------------------------------------------------------------------
\73\ See, e.g., Baltimore Gas & Electric at 16-17 (citing
Central Iowa Power Cooperative v. FERC, 606 F.2d 1156 (D.C. Cir.
1979)).
\74\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Large Public Power Council at 27 (citing National Fuel and Tenneco
Gas).
---------------------------------------------------------------------------
48. Sponsoring PJM Transmission Owners argue the Commission has
ignored other potential costs associated with eliminating the right of
first refusal, including expensive mitigation plans in the event that a
nonincumbent abandons a reliability project. Similarly, Xcel asserts
that Commission's statement in P 344 of Order No. 1000 indicates the
Commission's belief that certain nonincumbent transmission developers
will not be able to complete the projects assigned to them. Xcel adds
that other risks will increase from the utility transmission providers'
inability to guarantee reliable service, such as litigation arising
from outages.
49. Ad Hoc Coalition of Southeastern Utilities asserts that
Commission policy has persistently treated transmission as a natural
monopoly, and therefore the court's decision in Wisconsin Gas should
serve as a warning light rather than the license that the Commission
assumes it to be. Southern Companies contend that Order No. 1000
assumes that vertical integration is unduly discriminatory because it
requires nonincumbents to have a right to propose, own, build and
operate integrated network elements. Southern Companies assert that
they operate under the traditional regulatory compact, with
efficiencies of vertical integration, economy of scale, duty to serve,
and adequate return on investment, which ensures necessary transmission
is constructed on schedule and is appropriately operated and
maintained. Southern Companies state that by not recognizing and
rationally explaining this change in precedent, the
[[Page 32194]]
Commission has acted arbitrarily and capriciously.
C. Commission Determination
50. We deny the requests for rehearing that challenge the
Commission's determination that the reforms instituted by Order No.
1000 are needed. As we noted in Order No. 1000, changes are at work in
the electric utility industry that have created an additional, and
potentially significant, need for new transmission infrastructure.
Order No. 1000 cited studies conducted by the North American Electric
Reliability Corporation (NERC) and Edison Electric Institute (EEI) that
confirmed an increase in transmission development over the last several
years, and the Commission cited to an EEI-commissioned Brattle Group
study suggesting that approximately $298 billion in new transmission
facilities will be required over the period 2010 to 2030.\75\ Order No.
1000 explained that these changes are being driven in large part by the
changes in the generation mix, and it cited NERC's 2009 Assessment,
which stated that existing and potential environmental regulation and
state renewable portfolio standards are driving significant changes in
the generation mix, resulting in early retirements of coal-fired
generation, an increasing reliance on natural gas, and large-scale
integration of renewable generation.\76\
---------------------------------------------------------------------------
\75\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 44-45.
\76\ Id. P 45.
---------------------------------------------------------------------------
51. The Commission concluded in Order No. 1000 that current
transmission planning and cost allocation requirements are inadequate
to meet these challenges. Current requirements threaten to thwart
identification of transmission solutions that are more efficient or
cost-effective than would be the case without the reforms contained in
Order No. 1000. As a result, the Commission concluded--and we affirm
here--that it is necessary and appropriate that we take proactive steps
to ensure that this threat does not result in such adverse
consequences. The narrow focus of current transmission planning
requirements, and the shortcomings of current cost allocation
practices, represent a threat that justifies Order No. 1000's
requirements, and it is not one that the Commission can address
adequately or efficiently through the adjudication of individual
complaints.\77\ The Commission explained that the actual experiences
cited in the record provide additional support for action but are not
necessary to justify the remedy, and that the remedy is justified by
the theoretical threat identified therein.
---------------------------------------------------------------------------
\77\ Id. P 52.
---------------------------------------------------------------------------
52. Order No. 1000 addresses the inadequacy of existing
requirements by establishing minimum criteria that the transmission
planning process must satisfy, including general principles that cost
allocation practices must follow. These criteria are interrelated and
were designed as a package to ensure that an effective transmission
planning process is in place in each region.\78\ Effective transmission
planning requires coordination among transmission planning entities; is
open and transparent, which is necessary for any process that involves
multiple entities with a variety of needs or views regarding this
process; considers all transmission needs of all transmission
customers; results in an identifiable product reflecting regional
determinations; and does not create unnecessary barriers to the
consideration of good ideas or the selection of the most advantageous
transmission solutions, regardless of whether the developer of a
transmission solution is an incumbent transmission developer/provider
or a nonincumbent transmission developer. Effective transmission
planning should also recognize that there may be even more efficient or
cost-effective solutions that are identified through interregional
transmission coordination efforts than those solutions identified in a
regional transmission planning process. Finally, effective transmission
planning is performed with a clear ex ante understanding of who will
pay for a facility selected in a regional transmission plan for
purposes of cost allocation. Without that understanding, the likelihood
that selected facilities will be implemented is diminished, undermining
the entire purpose of the transmission planning process, namely, the
development of efficient and cost-effective transmission solutions.
---------------------------------------------------------------------------
\78\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at 42; Order
No. 1000, FERC Stats. & Regs. ] 31,323 at P 47.
---------------------------------------------------------------------------
53. These basic principles encompass all the reforms found in Order
No. 1000 and show how the reforms are interrelated to serve a common
purpose. If any of the reforms are absent, the effectiveness of
transmission planning and cost allocation processes would be
undermined. We are not able to identify any argument raised on
rehearing that demonstrates that any of these principles are invalid.
Instead, the overriding objection raised by the petitioners to the
Commission's discussion of the need for the reforms in Order No. 1000
is that the Commission either has not demonstrated the existence of a
problem that requires correction through implementation of new
requirements, or that it has not shown that the problems it has
identified exist in all regions of the country, thus undermining the
need for generic rules that apply to all public utility transmission
providers. The petitioners that raise these objections maintain that
the development of needed transmission facilities is proceeding apace,
either nationally or in a specific region, and thus currently there is
nothing amiss that requires correction. From this, petitioners conclude
that the Commission has not presented substantial evidence of a current
problem that shows the need for its reforms.
54. We disagree. As the Commission noted in Order No. 1000, the
expansion of the transmission grid is the result of a complex and often
contentious process that occurs over a long time horizon.\79\ It is
capital intensive and subject to numerous regulatory hurdles. It is
further complicated by the problem of determining how costs for the
expansion will be allocated in instances when multiple entities
benefit. Given the fundamental importance of transmission
infrastructure, and the many difficulties involved in its development,
including the long lead times involved, we continue to believe that a
proactive approach is necessary. As discussed in Order No. 1000 and
reiterated below, such an approach is fully consistent with the
applicable legal requirements.
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\79\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 50.
---------------------------------------------------------------------------
55. Petitioners' specific arguments that the Commission has not
adequately justified the need for the reforms in Order No. 1000 fall
under six broad headings: (1) The Commission has failed to demonstrate
that any existing rate, term or condition of or for transmission
service is unjust and unreasonable or unduly discriminatory or
preferential; (2) the Commission supports its need for reform based
solely on the existence of a theoretical threat, and it is not clear in
National Fuel whether such a decision can be supported on this basis
alone: (3) the theoretical threat that the Commission uses to justify
its reforms in Order No. 1000 amounts to hypothesis and speculation and
ignores existing realities, especially in the Southeast; (4) the
Commission has not identified a theoretical threat that justifies the
removal of federal rights of first refusal from Commission-
[[Page 32195]]
jurisdictional tariffs and agreements and that the Commission has not
shown that there is a reasonable expectation that competition in
transmission development may have some beneficial impact on rates; (5)
the burdens imposed by the Commission's reforms outweigh the benefits;
and (6) other issues that do not fall into a general category. We
address each of these arguments in turn below.
Whether Is It Necessary That the Commission Demonstrate That Any
Existing Rate, Term or Condition of or for Transmission Service Is
Unjust and Unreasonable or Unduly Discriminatory or Preferential
56. California ISO, PPL Companies, Southern Companies, and Oklahoma
Gas and Electric Company challenge the Commission on the grounds that
it has failed to demonstrate that any existing rate, term or condition
of or for transmission service is unjust and unreasonable or unduly
discriminatory or preferential. However, 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.\80\ When the Commission proceeds by rule it
can conclude that ``any tariff violating the rule would have such
adverse effects * * * as to render it `unjust and unreasonable' ''
within the meaning of section 206 of the FPA.\81\
---------------------------------------------------------------------------
\80\ Associated Gas Distributors v. FERC, 824 F.2d at 1008.
\81\ Id. (emphasis in original).
---------------------------------------------------------------------------
57. One circumstance that can justify the application of this
principle is the existence of a threat that, in the absence of
Commission action, would materialize and cause rates to be unjust and
unreasonable, or unduly discriminatory or preferential. A threat that
has not yet materialized is what the court in National Fuel described
as a ``theoretical threat.'' The Commission justified the need for the
reforms in Order No. 1000 based on such a threat created by the
inadequacy of existing transmission planning and cost allocation
requirements to meet the anticipated challenges facing the industry, a
threat whose existence was illustrated by actual problems that the
Commission noted in the order, but that are not necessary to justify
its response to the threat.\82\
---------------------------------------------------------------------------
\82\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 53.
---------------------------------------------------------------------------
Whether the Reforms in Order No. 1000 can be Supported on the Basis of
a Theoretical Threat Alone
58. A number of petitioners call into question the use of a
theoretical threat as the basis for the Commission's reforms.\83\ For
example, Ad Hoc Coalition of Southeastern Utilities maintains that,
based on National Fuel, it is not clear whether a decision might be
supported by theory alone. We disagree that the court in National Fuel
was non-committal on this point. The court specifically stated that the
Commission could choose ``to rely solely on a theoretical threat.''
\84\ While it listed certain matters that the Commission would need to
address on remand, it did not comment on the possibility of addressing
them successfully, nor did it say anything to suggest that this
approach might be defective in principle. FirstEnergy Service Company
argues that the list of specific matters that the court listed defines
the showing that must be made to rely on a theoretical threat in all
cases. However, the court's list of matters to be addressed on remand
was simply a reflection of the specific issues it saw in the case at
hand, not what was required in all cases. Moreover, when the court
stated in National Fuel that it expressed ``no view here whether a
theoretical threat alone would justify an order * * *,'' \85\ it was
referring to the justification of an order in the matter at hand, not
any and every possible proceeding. Additionally, we note that the same
court subsequently reconfirmed the legitimacy of reliance on
theoretical threats, and it based its conclusion directly on the ruling
it made in National Fuel.\86\
---------------------------------------------------------------------------
\83\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Large Public Power Council.
\84\ National Fuel, 468 F.3d at 844.
\85\ Id. at 844.
\86\ BNSF Railway Co. v. Surface Transportation Board, 526 F.3d
770, 778 (D.C. Cir. 2008) (BNSF Railway Co.) (finding that the
Surface Transportation Board could adopt a new method to correct
excessive railroad rates arising through gaming behavior by the
railroads even when there was no evidence of such behavior on their
part).
---------------------------------------------------------------------------
Whether the Commission's Argument That the Reforms in Order No. 1000
Are Needed Amounts to Hypothesis and Speculation and Ignores Existing
Realities, Especially in the Southeast
59. Several petitioners characterize the Commission's approach as
based on hypothesis and speculation. For example, Southern Companies
claim that the Commission is making ``little more than a guess--a
speculative hypothesis,'' \87\ and Ad Hoc Coalition of Southeastern
Utilities and Alabama PSC also claim that the Commission is acting on
mere conjecture. Southern Companies insist that the Commission must
provide detailed facts showing that existing cost allocation methods
are impairing better regional transmission solutions. NARUC states that
the Commission does not identify actual concerns or problems or rely on
any factual record and instead proceeds in a conclusory fashion. Some
petitioners also maintain that the existing situation in the Southeast
undercuts the Commission's position.
---------------------------------------------------------------------------
\87\ Southern Companies at 16.
---------------------------------------------------------------------------
60. As an initial matter, we note that, based on our expertise and
knowledge of the industry, we do not consider it to be speculation or
conjecture to conclude that regional transmission planning is more
effective if it results in a transmission plan, is open and
transparent, and considers all transmission needs. Nor do we consider
it speculation or conjecture to state that barriers to the proposal and
evaluation of alternative transmission solutions will inhibit more
efficient or cost-effective transmission solutions, or that the
implementation of transmission plans will be improved where there is a
clear ex ante understanding of who will pay for the facilities selected
in the regional transmission plan for purposes of cost allocation. As
we explain in the following discussion, such propositions are fully
consistent with the grounds for action that courts have accepted in the
past.
61. To argue that drawing such conclusions amounts to speculation
or conjecture also conflicts with the principle articulated above that
the Commission is not required to make individual findings under
section 206 when formulating generic rules. They also imply that a
threat that can justify Commission action in a rulemaking must be
actual, i.e., one whose consequences have been realized, not one whose
consequences are anticipated or, as the court expressed it in National
Fuel, a threat that is ``theoretical.''
62. These criticisms thus mischaracterize what the courts mean by
proceeding on the basis of a theoretical threat. It means to proceed on
the basis of a particular type of fact, ``generic'' facts that
constitute the basis for ``generic factual predictions'' that can
constitute a rational basis for an agency's decision.\88\ The court in
Associated Gas Producers gave the following as an example of an
acceptable generic factual prediction: ``the increased incentive to
compete
[[Page 32196]]
vigorously in the market would eventually lead to lower prices for all
consumers.'' \89\ The court treated such predictions as based on
behavioral assumptions that are not subject to serious dispute. Thus
the court stated that ``[a]gencies do not need to conduct experiments
in order to rely on the prediction that an unsupported stone will fall;
nor need they do so for predictions that competition will normally lead
to lower prices.'' \90\ Indeed, the court acknowledged that such
propositions can be accepted without record evidence when the
prediction is viewed ``as at least likely enough to be within the
Commission's authority.'' \91\
---------------------------------------------------------------------------
\88\ Associated Gas Distributors, 824 F.2d 981 at1008.
\89\ Id. (citing Wisconsin Gas, 770 F2d at 1161).
\90\ Id. at 1008-9.
\91\ Id. at 1008.
---------------------------------------------------------------------------
63. Other courts have recognized that when promulgating rules of
general and prospective applicability, agencies can draw ``factual
inferences * * * in the formulation of a basically legislative-type
judgment, for prospective application only.'' \92\ Such judgments are
closely bound up to what are sometimes referred to as ``legislative
facts,'' i.e., ``facts which help the tribunal determine the content of
law and of policy and help the tribunal to exercise its judgment or
discretion in determining what course of action to take.'' \93\ The
District of Columbia Circuit has stated that ``legislative facts are
crucial to the prediction of future events and to the evaluation of
certain risks, both of which are inherent in administrative
policymaking.'' \94\ The Supreme Court has ruled that when dealing with
matters that are ``primarily of a judgmental or predictive nature * * *
complete factual support in the record for [an agency's] judgment or
prediction is not possible or required; `a forecast of the direction in
which future public interest lies necessarily involves deductions based
on the expert knowledge of the agency.' '' \95\ This is precisely what
is involved in the Commission's reasoning in Order No. 1000.
---------------------------------------------------------------------------
\92\ United States v. Florida East Coast Ry., 410 U.S. 224, 246
(1973); United Air Lines, Inc. v. Civil Aeronautics Board, 766 F.2d
1107, 1119 (7th Cir 1985).
\93\ Association of National Advertisers, Inc., v. FTC, 627 F.2d
1151, 1161-62 (D.C. Cir. 1979) (Ass'n of National Advertisers)
(quoting 2 K. Davis, Administrative Law Treatise, Sec. 15.03, at
353 (1958)).
\94\ Id. at 1162.
\95\ FCC v. National Citizens Committee for Broadcasting, 436
U.S. 775, 814 (1978) (quoting FPC v. Transcontinental Gas Pipe Line
Corp., 365 U.S. 1, 29 (1961)); see also Ass'n of National
Advertisers, Inc., 627 F.2d at 1162.
---------------------------------------------------------------------------
64. We disagree with the arguments made by various petitioners that
we have ignored evidence that disproves our reasoning. The evidence in
question consists of a description of the current state of transmission
planning and development in a specific region combined with an
expression of satisfaction with the current situation. For example,
North Carolina Agencies state that there is no evidence that
transmission is lacking in the Southeast and that there is no need in
this region for transmission projects that can transfer large amounts
of renewable energy. North Carolina Agencies state that the
transmission planning processes in the Southeast are already highly
developed, and Southern Companies state that in the Southeast all
transmission needs have already been planned for.
65. First, the Commission is authorized not simply to make generic
findings but also to act on generic factual predictions.\96\ To state
that the facts in a particular region run counter to the Commission's
assessment of the future course of events is to argue either that
present circumstances can be expected to persist into the future or
that certain basic principles, such as the proposition that
transmission developers are more likely to invest if they have a
mechanism by which their costs will be allocated, do not apply in the
region. We do not find the latter sort of claim to be credible, and the
former claim simply overlooks the fact that the present is not a
prediction of the future. The Commission is authorized to make rules
with prospective effect that will prevent situations that are
inconsistent with the FPA from occurring, which means that it is
authorized to consider how the future may be different from the present
if the rules it proposes are not adopted. We thus also reject
Sacramento Municipal Utility Districts' claim that the Commission
cannot act unless it shows the existence of an ``actual problem'' in a
particular region, a claim that lies at the root of all the arguments
that petitioners make on this point. An ``actual problem'' is what one
has when a theoretical threat comes to fruition. To insist that the
Commission must identify the existence of an actual problem in the
present before it can act is thus to deny that a theoretical threat
that one reasonably concludes exists can be a basis for action. Such a
conclusion is inconsistent with the cases we have cited on this
point.\97\
---------------------------------------------------------------------------
\96\ Associated Gas Distributors, 824 F.2d at 1008.
\97\ See, e.g., BNSF Railway Co., 526 F.3d at 778.
---------------------------------------------------------------------------
66. In addition, these arguments overlook the fact that in Order
No. 1000, the Commission identifies a minimum set of requirements that
must be met to ensure that transmission planning processes and cost
allocation mechanisms result in Commission-jurisdictional services
being provided at rates, terms, and conditions that are just and
reasonable and not unduly discriminatory or preferential. Given that
the requirements are minimum requirements, it would not be surprising
that some current practices in some regions may already satisfy many of
them. If that is the case, the public utility transmission providers
concerned need only show in their compliance filing how current
practices in their regions satisfy the Commission's standards. This
does not mean that the reforms are not needed, as all of these
requirements are not satisfied in all regions. We thus do not consider
Alabama PSC's proposal of a regional or case-by-case approach for
applying these reforms to be appropriate or necessary. We also disagree
with Southern Companies and others that assert that there is not an
issue to be remedied in their respective regions. As we note above, if
public utility transmission providers believe that they already satisfy
the minimum requirements in Order No. 1000, they may seek to
demonstrate this in their compliance filings.
67. The concept of minimum requirements supplies the answer to
Southern Companies argument that there is no basis for requiring them
to adopt the nonincumbent transmission developer reforms of Order No.
1000 because they do not have a federal right of first refusal and
because there are no restrictions on nonincumbent transmission projects
in the SERTP planning process. Southern Companies also note that to
date no nonincumbents have proposed projects in SERTP. They attribute
this to incumbents, who they argue have developed a robust transmission
grid and are adequately investing in transmission. However, the purpose
of the minimum requirements for nonincumbent transmission developers is
to provide objective criteria that can help ensure that the lack of
nonincumbent participation will not be attributable to lack of equal
treatment or some other reason identified in Order No. 1000 as an
impairment to the identification and evaluation of more efficient or
cost-effective alternatives. Moreover, if the requirements of Order No.
1000 are in fact already met in SERTP, then Southern Companies need
only show in their compliance filing how current practices satisfy the
Commission's requirements. Finally, Southern Companies state the
Commission has no
[[Page 32197]]
authority to impose nonincumbent development rights, but the Commission
is not imposing any such rights in Order No. 1000. It is simply
establishing minimum requirements for the treatment of nonincumbent
transmission developers in the transmission planning process. These
requirements do not confer any rights to develop a facility. They only
confer a right to have a proposal considered.
68. Some petitioners confuse agency judgments based on legislative
facts, i.e., factual inferences made in light of the policy underlying
a statute, with formal academic theories. Southern Companies maintain
that the theoretical basis of Order No. 1000 does not constitute good
theory by scientific standards.\98\ California ISO argues that the
Commission's hypothesis that the absence of a regional cost allocation
method will cause rates to be unjust or unreasonable is not based on an
established economic theory and the Commission cites no peer-reviewed
or other economic analysis that supports its conclusion.
---------------------------------------------------------------------------
\98\ See, e.g., Southern Companies.
---------------------------------------------------------------------------
69. The courts have specifically rejected such notions. The court
in Associated Gas Distributors clearly distinguished between generic
factual predictions that are commonly made in rulemakings and the
practice of economics as an academic discipline.\99\ The court
criticized the use of another case, Electricity Consumers Resource
Council v. FERC,\100\ to invoke economic theory as a basis for decision
making in a way that is similar to the way that Southern Companies and
Ad Hoc Coalition of Southeastern Utilities invoke economic theory. For
example, Southern Companies state that ``FERC has pointed to no * * *
established theory (such as marginal pricing at issue in Electricity
Consumers) upon which it may rely to support the application of Order
No. 1000's requirements to the Southeast.'' \101\ The court in
Associated Gas Distributors stated that ``[c]learly nothing in
Electricity Consumer's reference to `economic theory' was intended to
invalidate agency reliance on generic factual predictions merely
because they are typically studied in the field called economics.''
\102\
---------------------------------------------------------------------------
\99\ Associated Gas Distributors, 824 F.2d at 1008.
\100\ 747 F.2d 1511 (D.C. Cir. 1984) (Electricity Consumers).
\101\ Southern Companies at 16.
\102\ Associated Gas Distributors, 824 F.2d at 1008; accord
Sacramento Municipal Utility District v. FERC, 616 F.3d 520, 531
(D.C. Cir. 2010) (stating that ``[n]either [Electricity] Consumers
nor any other case law prevents the Commission from making findings
based on `generic factual predictions' derived from economic
research and theory.'').
---------------------------------------------------------------------------
70. This is the case because the court recognized that there was no
reason that an agency must demonstrate the validity of well-established
general principles such as ``that competition will normally lead to
lower prices.'' \103\ Southern Companies and Ad Hoc Coalition of
Southeastern Utilities confuse a theoretical threat, a potential threat
that has not yet materialized, with a theory used in an academic
discipline, an area of activity that is not comparable to the tasks or
responsibilities entrusted to a regulatory agency. The type of
principles that the Commission has relied upon here are fully
commensurate with those that the court in Associated Gas Distributors
said the Commission could utilize when addressing matters that fall
within its area of expertise. For these same reasons, we disagree with
the argument of California ISO that the Commission's finding that the
absence of a cost allocation method will cause rates to be unjust or
unreasonable must be based on an established economic theory and that
the Commission must cite a peer-reviewed or other economic analysis
that supports its conclusion.
---------------------------------------------------------------------------
\103\ Associated Gas Distributors, 824 F.2d at 1009.
---------------------------------------------------------------------------
71. Moreover, we note that the substantial evidence standard does
not require scientific certitude, a point which serves to dispel the
confusion between theoretical threats and scientific theories. It only
requires evidence that a ``reasonable mind might accept'' as ``adequate
to support a conclusion.'' \104\ In the context of rulemakings that
involve legislative facts and generic factual predictions, the relevant
criterion is whether the agency has provided a reasonable explanation
of the problem presented and its solution to it.\105\ A reasonable
justification of a policy choice is not, and given the nature of the
task involved cannot be, a scientific prediction.
---------------------------------------------------------------------------
\104\ Dickenson v. Zurko, 527 U.S. 150, 155 (1999).
\105\ See Federal Communications Commission v. Nat'l Citizens
Comm. for Broadcasting, 436 U.S. 775, 814 (1978) (stating that
``complete factual support in the record for the [agency's] judgment
or prediction is not possible or required''); Industrial Union v.
Hodgson, 499 F.2d 467 at 475-476 (1974). Bradford Nat'l Clearing
Corp. v. SEC, 590 F.2d 1085, 1103-04 (D.C. Cir. 1978) (judicial
deference to agency increases where agency decision rests primarily
on predictions).
---------------------------------------------------------------------------
72. This point is confirmed by the discussion of theoretical
threats in National Fuel. While some petitioners argue that this case
requires substantial empirical verification of the existence of a
theoretical threat,\106\ a careful examination of what the courts says
shows that this is not correct. The court did not specify any
requirements for demonstrating the existence of a theoretical threat
other than a showing that the threat is ``plausible.'' \107\ A specific
theoretical threat that it found met this requirement is stated in its
entirety in the following language:
---------------------------------------------------------------------------
\106\ See, e.g., Sacramento Municipal Utility District.
\107\ National Fuel, 468 F.3d at 840.
If a pipeline did not have an affiliated marketer, it would be
in its interest to disseminate widely information relevant to
operating constraints, capacity, and available receipt points,
limited only by the cost of doing so. The affiliate relationship,
however, creates an incentive for the pipeline to withhold
information that otherwise would be made available to the
affiliate's competitors. Withholding this information from non-
affiliated shippers reduces their ability to arrange transactions
efficiently.\108\
---------------------------------------------------------------------------
\108\ Tenneco Gas v. FERC, 969 F.2d 1187, 1197 (1992) (Tenneco
Gas).
This description of a theoretical threat, which is drawn from an
earlier decision cited by the court in National Fuel, corresponds
precisely to the type of generic factual predictions discussed above
that can justify agency action. It focuses on an incentive to withhold
information that is created simply by the existence of an affiliate
relationship. The court nowhere indicated that the plausibility of this
theory depended on additional confirmation in the form of predictive
economic models or extensive empirical data.
73. We thus disagree with Southern Companies that our use of words
such as ``may'' and ``could'' in describing the anticipated effects of
our reforms is evidence that these reforms are based on speculation or
guesswork. When making a generic factual prediction, one is not
predicting what will occur with certainty in every instance but rather
what it is reasonable to conclude will occur with sufficient frequency
and to a sufficient degree to conclude that the reforms are needed. Our
use of words such as ``may'' and ``could'' in this context must be
understood in this sense.
74. California ISO states that the Commission is not relying on
economic theory to determine the means for achieving its goal but
rather to establish a statutory predicate for action. However, a
theoretical threat, which should not be confused with an economic
theory, is precisely that, a predicate for agency action. The
Commission's task is to assess current circumstances and to form a
judgment on the steps necessary to avoid adverse effects on rates that
it concludes are likely to arise if the present situation persists. We
reject the idea that the only
[[Page 32198]]
appropriate predicates for our action in this area are current failures
that are traceable to inadequate transmission planning and cost
allocation. That would mean that the only predicate for action is a
fully realized threat, which is contrary both to the clear position
taken by the courts, and, given the special problems involved in
transmission development, to the public interest.\109\
---------------------------------------------------------------------------
\109\ We reject for the same reasons the contention by Ad Hoc
Coalition of Southeastern Utilities and Large Public Power Council
that it is somehow significant that the Commission has effectively
conceded that there is no evidence justifying Order No. 1000 and it
is relying on theory alone. The Commission is acting on the basis of
a theoretical threat whose existence has been demonstrated through a
reasonable explanation. The identification of this threat is based
``on an assessment of the relevant market conditions'' and involves
``a forecast of the direction in which future public interest lies''
which ``necessarily involves deductions based on the expert
knowledge of the agency.'' Ass'n of National Advertisers, 627 F.2d
at 1162 (internal citations omitted). Such judgments will satisfy
evidentiary requirements in rulemakings such as this one. Id. at
1161-62.
---------------------------------------------------------------------------
75. Finally, aside from National Fuel and Associated Gas
Distributors, the only case that petitioners cite on rehearing dealing
with evidentiary burdens in a rulemaking is Business Roundtable v. SEC.
In that case, the court vacated a rule issued by the SEC on the grounds
that it had not adequately considered the rule's effect upon
efficiency, competition, and capital formation. A number of petitioners
describe this case as involving matters that are ``remarkably'' or
``strikingly'' similar to the present proceeding.\110\ However,
Business Roundtable dealt with a failure by the SEC to comply with
specific provisions of the Exchange Act and the Investment Company Act
of 1940 that require it to assess the economic impacts of a new rule.
The court described these requirements as being ``unique'' to the
SEC.\111\ Requirements that apply uniquely to the SEC under statutes
that it administers do not address requirements that apply to this
Commission under the FPA or its compliance with them. Moreover, the
petitioners that rely on Business Roundtable point to no requirements
in the FPA that are similar to those that applied to the SEC under its
statutes and that might show how the case applies to this proceeding.
We are, of course, required to consider the burdens that Order No. 1000
creates in relation to the benefits that we expect its requirements to
produce.\112\ However, we have done that and have concluded that, in
light of the substantial investment in new transmission facilities that
is generally expected to occur, the potential benefits from improved
planning for new transmission facilities outweigh the burdens involved
in complying with the requirements of Order No. 1000 to revise existing
transmission tariffs and institute additional planning procedures.
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\110\ See, e.g., Southern Companies; Ad Hoc Committee of
Southeastern Utilities; and Large Public Power Council.
\111\ Business Roundtable at 1148.
\112\ See, e.g., National Fuel, 468 F.3d at 844; Associated Gas
Distributors, 824 F.2d at 1019.
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Whether the Commission Has Identified a Theoretical Threat That
Justifies the Removal of Federal Rights of First Refusal From
Commission Jurisdictional Tariffs and Agreements and Has Shown That
There Is a Reasonable Expectation That Competition in Transmission
Development May Have Some Beneficial Impact on Rates
76. A number of petitioners contend that the Commission has not
identified a theoretical threat that justifies the removal of federal
rights of first refusal from Commission jurisdictional tariffs and
agreements and that the Commission has not shown that there is a
reasonable expectation that competition in transmission development may
have some beneficial impact on rates. In fact, the record in this
proceeding includes the type of evidence that courts have found
appropriate in these circumstances. The Federal Trade Commission, one
of the two federal agencies responsible for enforcement of the
antitrust laws, supported the elimination of federal rights of first
refusal as a means for promoting consumer benefit, support that it
described as consistent with antitrust policy disfavoring regulatory
barriers to entry in all but a limited number of instances.\113\ While
we possess our own expertise on barriers to entry when dealing
specifically with the transmission grid, we note that the court in
Tenneco Gas attributed considerable weight to analogous remarks by the
Department of Justice that supported the identification of a
theoretical threat.\114\
---------------------------------------------------------------------------
\113\ Federal Trade Commission Comments on Proposed Rule at 2,
7.
\114\ Tenneco Gas, 969 F.2d at 1202.
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77. Large Public Power Council maintains that Wisconsin Gas
contains strictures regarding agency action premised on the benefits of
competition that the Commission has violated. This case requires only
``that there must be `ground for reasonable expectation that
competition may have some beneficial impact.' '' \115\ We think that
there is a reasonable expectation that removal of a barrier to entry in
the area of transmission development will have benefits of the type
that competition creates in most industries. When the court in
Wisconsin Gas stated that ``unsupported or abstract allegations of the
benefits that will accrue from increased competition'' \116\ do not
form an adequate basis for agency action, it did this in response to
the Commission's position on a complex rate issue whose effects were
difficult to discern. Order No. 1000 does not involve a comparable
situation. In fact, the court's full argument was that such allegations
``cannot substitute for `a conscientious effort to take into account
what is known as to past experience and what is reasonably predictable
about the future.' '' \117\ In fact, we have made just such an effort,
and on that basis we find it quite reasonable to expect benefits from
removing barriers to transmission development. Moreover, as noted
above, this analysis is consistent with that of the Federal Trade
Commission.
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\115\ Wisconsin Gas, 770 F.2d 1144, at 1158 (quoting FCC v. RCA
Communications, Inc., 346 U.S. 86, 96-7 (1953)).
\116\ Id. at 1158.
\117\ Id. (quoting American Public Gas Association v. FPC, 567
F.2d 1016, 1037 (D.C. Cir. 1977)).
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78. We also see no significance in the fact that Wisconsin Gas
involved competitive sales of natural gas in accordance with a policy
established by Congress. Ad Hoc Committee of Southeastern Utilities and
Large Public Power Council state that Congress has voiced no similar
policy regarding competition in the development of transmission
infrastructure, but it likewise has not objected to it. We thus do not
see how this difference between Wisconsin Gas and this proceeding is
controlling. Barriers to entry in this area can adversely affect rates,
and our action to ensure that such barriers in the form of federal
rights of first refusal do not adversely affect rates is well within
the scope of actions that we are authorized to take under section 206
of the FPA. The fact that Congress expressed a policy regarding
competitive sales of natural gas does not affect this conclusion. These
points also address the objections by Oklahoma Gas and Electric Company
and Sponsoring PJM Transmission Owners that the Commission has not
supported the conclusion that competition between potential developers
will result in more efficient or cost effective solutions or that this
conclusion suffices to support Commission action under section 206.
79. Xcel and MISO Transmission Owners Group 2 argue that the
[[Page 32199]]
Commission has not explained why problems created by federal rights of
first refusal cannot be dealt with through individual complaints.
Rights of first refusal create barriers to participation in the
transmission development process. To require nonincumbent transmission
developers to overcome those barriers solely through individual
complaint proceedings, requiring litigation each time they seek to
engage in the development process would create expense, delay, and
uncertainty that would serve as a further disincentive to
participation. That is, they would have to invest in project
development and participate in an extensive regional transmission
planning process, and if the project is then taken over by an incumbent
transmission developer/provider who exercises a federal right of first
refusal, they would have to invest still more time and resources in
litigation. As long as the federal right of first refusal remains in a
Commission-approved tariff or agreement, their chances of succeeding in
litigation would be severely diminished. They would likely forego
participating in that region in the first place and place their efforts
elsewhere. The remedy suggested by Xcel and MISO Transmission Owners
Group 2 would thus itself act as a form of barrier to entry.
80. MISO Transmission Owners 2, Xcel, and MISO argue that the
Commission has not identified an instance where federal rights of first
refusal have led to adverse effects on rates, discrimination against a
nonincumbent transmission developer, or failure by a nonincumbent to
invest in a transmission facility. While the Commission did receive
evidence that nonincumbent transmission developers experience
discriminatory treatment,\118\ we think the more important point is
that the practical effect of a federal right of first refusal is to
discourage investment by nonincumbent transmission developers. We do
not think it is surprising that there is limited evidence of exclusion
of nonincumbent transmission developers in a situation that discourages
them from proposing projects in the first place. While Sponsoring PJM
Transmission Owners contrast the evidence of specific discrimination
provided in Order No. 888 to support open access transmission with the
number of specific examples of barriers to participation by
nonincumbent transmission developers in this proceeding, they fail to
acknowledge that Order No. 888 and Order No. 1000 involve different
factual circumstances and bases for Commission action. Order No. 888
dealt with instances of undue discrimination in transmission access
involving entities that were already connected to the transmission
grid. Order No. 1000, by contrast, deals as much or more with the
effect on rates of excluding entities whose ability even to become
involved in the transmission planning process is being hindered from
the outset.
---------------------------------------------------------------------------
\118\ See LS Power Comments on Proposed Rule at 3.
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81. MISO Transmission Owners 2 state that the Commission ignored
the example of nonincumbent transmission developer participation in
CapX2020, which they maintain shows that existing construction rights
are not a disincentive to investment, at least with respect to the
Midwest ISO.\119\ However, MISO Transmission Owners 2 do not identify
any nonincumbent transmission developer that independently proposed a
transmission project and was able to develop it despite the existence
of a federal right of first refusal, and initially referred only to
certain transmission dependent utilities that had been ``renters'' of
the transmission system'' \120\ but that had chosen to invest in and
own a portion of CapX2020.\121\ While the Commission supports
investment in transmission infrastructure by transmission dependent
utilities, the existence of a single joint project like CapX2020 does
not demonstrate that nonincumbent transmission developers are treated
in a manner that is not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\119\ Midwest Transmission Owners 2 Petition for Rehearing at
12.
\120\ Midwest Transmission Owners Reply Comments on Proposed
Rule at 14.
\121\ Midwest Transmission Owners Comments on the Proposed Rule
at 37 and n.89. Midwest Transmission Owners 2 consists of all the
entities that compose Midwest Transmission Owners, with the
exception of American Transmission Company LLC.
---------------------------------------------------------------------------
82. We disagree with Baltimore Gas & Electric that if our concern
is the effect of federal rights of first refusal on transmission rates,
we should deal with rates directly rather than federal rights of first
refusal. Barriers to entry affect markets in various ways. These
include their ability to discourage innovation. Federal rules should
not prevent consumers from being able to benefit from the full range of
advantages that competition can provide, which the preservation of
barriers to entry does not allow.
83. We also disagree with Baltimore Gas & Electric that our
rationale for eliminating federal rights of first refusal has no
applicability to the transmission owner members of PJM because they
have relinquished all transmission planning decisions to PJM and thus
have no economic incentive to discriminate against nonincumbents. Even
if the transmission owner members of PJM have no economic reason to
object to development by nonincumbent transmission developers, this
does not mean that federal rights of first refusal cannot adversely
affect transmission rates. In other words, the Commission's rationale
for requiring the elimination of federal rights of first refusal is not
based solely on the economic incentives of incumbent transmission
developers/providers; it is also based on the belief that expanding the
universe of transmission developers offering potential solutions can
lead to the identification and evaluation of potential solutions to
regional needs that are more efficient or cost-effective.
84. These points apply equally to the argument of Sunflower, Mid-
Kansas, and Western Farmers that it is not in the economic self-
interest of public utility transmission providers in the SPP region to
inhibit projects proposed by nonincumbent transmission developers
because no state in the SPP region has enacted retail competition. For
example, the fact that no state in the SPP region would stand for
anticompetitive behavior by incumbent transmission developers/providers
does not ensure that the potentially more efficient or cost-effective
solutions offered by nonincumbent transmission developers will be
considered. To do that, it is necessary to have a requirement that they
be considered without having to adjudicate complaints of
anticompetitive behavior that discourage proposals of alternative
solutions.
85. We disagree with Xcel that requiring the elimination of a
federal right of first refusal for reliability projects constitutes an
overly broad remedy. While Xcel may be correct that it is less likely
that a nonincumbent transmission developer will propose a competing
transmission project that satisfies only a specific reliability need, a
nonincumbent transmission developer may decide to propose a
transmission project that satisfies several regional needs, including a
specific reliability need. In that instance, the Commission is
concerned that if an incumbent transmission developer/provider has the
ability to assert a federal right of first refusal for a transmission
project because it addresses a reliability need, then the nonincumbent
transmission developer may be discouraged from proposing the
transmission project that satisfies several regional needs. In
[[Page 32200]]
addition, we note that nothing in Order No. 1000 prevents an incumbent
transmission developer/provider from choosing to meet a reliability
need or service obligation by building new transmission facilities that
are located solely within its retail distribution service territory or
footprint and that is not submitted for regional cost allocation.\122\
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\122\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 262.
---------------------------------------------------------------------------
86. Ad Hoc Coalition of Southeastern Utilities asserts that the
Commission's longstanding treatment of transmission as a natural
monopoly undercuts its support for competition in the development of
transmission infrastructure, but we see no contradiction here. In
dealing with transmission as a natural monopoly, the Commission has
explained that ``[t]he monopoly characteristic exists in part because
entry into the transmission market is restricted or difficult. * * * In
addition, as unit costs are less for larger lines and networks,
transmission facilities still exhibit scale economies.'' \123\ The
Commission has never found that natural monopoly is antithetical to
competition in all respects. Rather it has said ``it is often better
for a single owner (or group of owners) to build a single large
transmission line rather than for many transmission owners to build
smaller parallel lines on a non-coordinated basis.'' \124\ This is
because ``effective competition among owners of parallel transmission
lines is unlikely, and often impossible, with existing practices and
technology.'' \125\ This, however, does not mean that determining who
will be the owner (or group of owners) of a particular line with
natural monopoly characteristics cannot be done on a competitive basis
or that competition in this connection would not promote benefits that
are similar to the benefits that it produces elsewhere in our economy,
in terms of improved facilities, enhanced technology, or better
transmission solutions generally.
---------------------------------------------------------------------------
\123\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Service by Public Utilities and Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Notice of Proposed Rulemaking and Supplemental Notice of Proposed
Rulemaking, 60 FR 17662 (April 7, 1995), FERC Stats. & Regs. ]
32,514, at 33,070 (1995).
\124\ Id.
\125\ Id.
---------------------------------------------------------------------------
87. This point provides the answer to the Oklahoma Gas and
Electric's statement that nothing Order No. 1000 will result in head-
to-head competition between transmission service providers and PJM
Transmission Owners' statement that the real issue is not competition
between transmission service providers but rather which entity will be
the monopoly owner of a transmission line. These statements overlook
the fact that competitive forces can be harnessed in a number of ways.
In this case, the Commission seeks to make it possible for nonincumbent
transmission developers to compete in the proposal of more efficient or
cost-effective transmission solutions. Oklahoma Gas and Electric
Company states that the choice of new transmission projects will not be
made in the market but rather in the stakeholder process, but this
simply highlights the fact that competitive forces can be harnessed in
various ways, including through the offering of competitive
alternatives in a stakeholder process. Oklahoma Gas and Electric
Company states that choices in the stakeholder process are based on
uncertain estimates and inputs, but this is true of the transmission
planning process whether or not it allows for competitive proposals.
88. The fact that incumbent transmission developers/providers may
have certain advantages, such as rights of way and experience with the
area in question, does not affect these conclusions. Incumbent
transmission developers/providers may in some situations be well-
equipped to prevail in a competitive process, but this is not an
argument against competition. One cannot presume that an incumbent
transmission developer/provider will always be better placed to
construct and own a project and that the transmission planning process
therefore will always reach the same result with or without a federal
right of first refusal, as Baltimore & Electric Company maintains. The
fact that an incumbent transmission developer/provider may possess
certain capabilities does not imply that the incumbent transmission
developer/provider is more capable than any possible nonincumbent
transmission developer in all situations.
89. Nor do the effects of differing corporate structures, rates of
return, or the other factors mentioned by Sponsoring PJM Transmission
Owners affect our conclusion. These are all matters that can be
considered in the transmission planning process, as can the issue of
potential other costs and risks that Ad Hoc Coalition of Southeastern
Utilities and Large Public Power Council propose may arise. Such
matters may be relevant to the identification of more efficient or cost
effective solutions. We do not see how they require one to conclude
that competition will not promote more efficient or cost-effective
solutions.
90. Finally, the nonincumbent reforms of Order No. 1000 are not
based on the assumption that vertical integration is unduly
discriminatory. Southern Companies argues that vertical integration
provides efficiencies and benefits to consumers, and we do not deny
that this may be the case in some situations. However, if it is, we
would expect that vertically-integrated public utilities will be well
positioned to compete in a transmission development process that is
open to nonincumbent transmission developers. Southern Companies
argument against nonincumbent transmission developer participation
confuses the concept of vertical integration with that of monopoly. The
existence of vertical integration does not imply that the vertically
integrated public utility must be a monopoly. The emergence of
competitive generation markets makes it no longer possible to argue
that vertically integrated utilities are natural monopolies in all
aspects of electric service.\126\ In short, vertical integration itself
is not unduly discriminatory, but there is no basis for claiming that
vertical integration requires the exclusion of nonincumbent
transmission developers.
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\126\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ]
31,036, at 31,642 (1996) (noting Congressional recognition of
``rising costs and decreasing efficiencies of utility-owned
generating facilities'' and also describing the emergence of ``non-
traditional power producers * * * [that following the enactment of
the Public Utility Regulatory Policies Act of 1978] began to build
new capacity to compete in bulk power markets''), order on reh'g,
Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ]
31,048, order on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997),
order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in
relevant part sub nom. Transmission Access Policy Study Group v.
FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v.
FERC, 535 U.S. 1 (2002). See also, Morgan Stanley Capital Group,
Inc. v. Public Utility District No. 1 of Snohomish County,
Washington, 554 U.S. 527, 535-36 (2008) (stating that ``[s]ince the
1970's * * * engineering innovations have lowered the cost of
generating electricity and transmitting it over long distances,
enabling new entrants to challenge the regional generating
monopolies of traditional utilities'').
---------------------------------------------------------------------------
Whether the Burdens Imposed by the Commission's Reforms Outweigh the
Benefits
91. Next, we address the question of the burdens imposed by the
Commission's reforms. The court made clear in both National Fuel and
Associated Gas Distributors that one metric for assessing whether a
rule has been adequately justified is whether the costs the rule
imposes are reasonable in
[[Page 32201]]
light of the threat identified.\127\ The Commission acknowledged in
Order No. 1000 that its new requirements would require adoption and
implementation of additional processes and procedures, but it noted
that in many cases public utility transmission providers already engage
in processes and procedures of the type in question.\128\ Large Public
Power Council argues that the implications of Order No. 1000 in
``creating a mechanism for socializing the cost of new regional
transmission developments are dramatic, and involve, by the
Commission's own reckoning, cost shifting for the recovery of
potentially hundreds of billions of dollars in transmission
investment.'' \129\ However, Order No. 1000 requires that the costs of
facilities selected in a regional transmission plan for purposes of
cost allocation be allocated in a way that is roughly commensurate with
benefits, i.e, allocated in accordance with the requirements of cost
causation. To the extent that Large Public Power Council's use of the
term ``socializing'' costs is meant to refer to a method of cost
allocation that does not conform with the principle of cost causation,
we disagree with that characterization of Order No. 1000's cost
allocation requirements. Consequently, we do not see how ensuring that
the costs of facilities selected in a regional transmission plan for
purposes of cost allocation are allocated to those who receive benefits
from the facilities represents ``cost shifting'' or an undue burden. On
the contrary, it is a clear benefit because it ensures that rates for
those facilities will be just and reasonable and not unduly
discriminatory or preferential, and it promotes the identification of
more efficient or cost-effective transmission solutions. Moreover, it
is a benefit that is achieved at minimal cost, i.e., the cost of
adopting and implementing additional procedures, in comparison to the
estimated billions of dollars of needed transmission investment that
current transmission planning and cost allocation practices have been
frustrating,\130\ or the estimated $298 billion in investment in new
transmission facilities that EEI suggests will be required over the
period from 2010 to 2030.\131\
---------------------------------------------------------------------------
\127\ National Fuel, 468 F.3d at 844; Associated Gas
Distributors, 824 F.2d at 1019.
\128\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 56.
\129\ Large Public Power Council at 18.
\130\ See Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 38
(discussing Brattle Group study contending that a large portion of
projects with an estimated total cost of over $180 billion will not
be built due to overlaps and deficiencies in transmission planning
and cost allocation processes).
\131\ See id. P 44.
---------------------------------------------------------------------------
92. We likewise disagree with Ad Hoc Coalition of Southeastern
Utilities' and Southern Companies' assertion that the interregional
transmission coordination reforms are contrary to National Fuel because
the burdens of such coordination outweigh any potential benefits. We
note that Order No. 1000 provided a sufficient rationale for the need
for specific reform of the interregional transmission coordination
requirements. Order No. 1000 explained that ``[c]lear and transparent
procedures that result in the sharing of information regarding common
needs and potential solutions across the seams of neighboring
transmission planning regions'' would help identify interregional
transmission facilities that could more efficiently or cost-effectively
meet the needs of each region.\132\ The Commission further found that
Order No. 890's transmission planning requirements ``are too narrowly
focused geographically'' and do not provide for adequate analysis of
the benefits of interregional transmission facilities in neighboring
regions.\133\ Accordingly, the Commission concluded that the
interregional transmission coordination reforms should be adopted now
and not delayed.
---------------------------------------------------------------------------
\132\ Id. P 368.
\133\ Id. P 369.
---------------------------------------------------------------------------
93. We continue to find that we have adequately justified the
interregional transmission coordination requirements and that, in doing
so, we have fully satisfied what is required by National Fuel, as that
standard is discussed herein. We disagree with the contention that such
requirements are overly burdensome as compared to the benefits. The
interregional transmission coordination requirements are part of what
goes into effective transmission planning. These requirements will help
public utility transmission providers, in consultation with
stakeholders, in one transmission planning region to work proactively
with their counterparts in neighboring regions to identify what may be
more efficient or cost-effective transmission facilities than the
solutions identified in individual regional transmission plans. We do
not believe these benefits are outweighed by the burdens involved,
i.e., the cost of the adoption and implementation of procedures
necessary for interregional transmission coordination, particularly
when compared to the significant transmission investment expected in
the future. Indeed, it may be the case that there will be little burden
at all for the members of the Ad Hoc Coalition of Southeastern
Utilities in implementing these requirements, given that they state
that there is already an ``optimization'' analysis along the seams and
interfaces in the Southeast.\134\ Accordingly, we deny rehearing on
this issue.
---------------------------------------------------------------------------
\134\ Ad Hoc Coalition of Southeastern Utilities at 65.
---------------------------------------------------------------------------
94. We also disagree with Large Public Power Council and Ameren
that the transmission planning requirements of Order No. 1000 will
place unnecessary burdens on planning engineers by requiring them to
focus on matters other than meeting the needs of their native loads or
will require a reassessment of prior planning. We see no contradiction
between transmission planning for native loads and ensuring that
transmission plans are consistent with regional or interregional
transmission needs. Indeed, the native loads of individual entities
ultimately benefit from improved regional transmission planning and
interregional transmission coordination because they benefit from
improvements to the transmission grid that extend beyond their own
local facilities. We therefore do not think that any additional burden
that Order No. 1000 may create for planning engineers outweighs the
benefits that we expect Order No. 1000 to provide. In addition, the
requirements of Order No. 1000 apply only to new transmission
facilities, and we therefore do not see how they require a reassessment
of past planning activities.
95. We have not, as Sponsoring PJM Transmission Owners contend,
ignored costs associated with elimination of federal rights of first
refusal, specially the need for expensive mitigation plans in the event
a nonincumbent transmission developer abandons a reliability project.
We see no reason to expect that the performance of incumbent and
nonincumbent transmission developers/providers will differ, and as a
result, the example that Sponsoring PJM Transmission Owners advances is
based on conjecture. Moreover, selection criteria for project
developers are an appropriate means of providing assurances that all
project developers will be in a position to fulfill their commitments.
96. Sacramento Municipal Utility District states that Order No.
1000 does not satisfy the requirements of reasoned decision-making
because it fails to take into account whether the cost allocation
provisions will discourage rather than facilitate regional transmission
planning. As we have noted already, the Commission continues to find
that
[[Page 32202]]
transmission planning is more successful when it is understood upfront
who will be allocated costs for the facilities in a transmission plan.
Regional cost allocation methods accomplish this, among other things.
The regional participants will decide which facilities in the regional
transmission plan will have their costs allocated according to a method
that they select, and which facilities will not. It is thus known how
much each beneficiary will pay for the first set of facilities when the
regional transmission plan is formed, and it is known that the latter
set of facilities must be supported by the facility sponsors alone.
Sacramento Municipal Utility District appears to take the position that
the cost allocation requirements will discourage transmission planning
because entities will be forced to pay for facilities from which they
receive no benefit. We address and reject this argument elsewhere in
this order.\135\
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\135\ See discussion infra at section IV.
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Other Issues
97. A number of petitioners raise objections to our demonstrations
of the need for reform that do not fall under any of the general
categories set forth above.
98. We are not, as Coalition for Fair Transmission Policy asserts,
stepping beyond our statutory authority and seeking to address every
policy problem that faces the industry. We have fully explained our
statutory authority in Order No. 1000, and we are addressing only
matters that can affect transmission rates in a way that could cause
them to become unjust and unreasonable, or unduly discriminatory or
preferential. We find nothing ambiguous about, for example, our
reference to such things as the impacts of renewable portfolio
policies, as Coalition for Fair Transmission Policy maintains. These
policies affect transmission needs and thus transmission rates, and
rather than being ambiguous, our reference to them provides a clear and
concrete example of how transmission planning cannot be fully effective
if it does not consider all transmission needs.
99. We also reject the characterization of our action in Order No.
1000 by Coalition for Fair Transmission Policy as commandeering
regional transmission planning. The transmission planning and cost
allocation requirements of Order No. 1000 are focused on the
transmission planning process, not any substantive outcomes of this
process.\136\ Order No. 1000 establishes a set of minimum requirements
that regional planning must meet and allows considerable flexibility in
the implementation of these requirements. Establishing flexible minimum
requirements for a process cannot be equated with commandeering that
process.
---------------------------------------------------------------------------
\136\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 12.
---------------------------------------------------------------------------
100. Coalition for Fair Transmission Policy states that the
Commission's authority under section 216 of the FPA to site
transmission facilities in national interest corridors would not have
been necessary if it had authority to address all policy problems and
commandeer the transmission process. We do not see how the Commission's
limited authority under this section is relevant to Order No. 1000.
Since we are acting to address matters that can have an adverse effect
on transmission rates and are not taking any control over the
transmission planning process itself, we are not taking any actions
that fall within the scope of the activities authorized in section 216.
101. In response to NARUC's concern that compliance with Order No.
1000 may stall existing local, regional, and DOE-funded
interconnection-wide planning, the Commission stated in Order No. 1000
that the compliance filing deadlines it established are compatible with
the interests of those that intend to develop transmission planning
processes that take into account the lessons learned through the ARRA-
funded transmission planning initiatives.\137\ NARUC states that its
reason for concern is the need to sort through ambiguities and comply
with Order No. 1000. The Commission is committed to engaging in
outreach and consultation to assist the compliance process. NARUC also
maintains that the ARRA-funded transmission planning initiatives may
eliminate the need for the Commission's reforms, but as we noted in
Order No. 1000, those initiatives are complementary to, not substitutes
for, the reforms in Order No. 1000. For example, they do not
specifically provide for regional cost allocation or for ongoing
coordination of planning for interregional transmission facilities,
which we concluded is necessary to ensure that rates, terms, and
conditions of jurisdictional services are just and reasonable and not
unduly discriminatory or preferential.\138\ NARUC has not challenged
this conclusion regarding the ARRA-funded transmission planning
initiatives in its petition for rehearing.
---------------------------------------------------------------------------
\137\ Id. P 794.
\138\ Id. P 371.
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III. Transmission Planning
A. Regional Transmission Planning Process
102. 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.\139\ Second, Order No. 1000 adopted reforms under
which transmission needs driven by Public Policy Requirements are
considered in local and regional transmission planning processes.\140\
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.\141\ 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.\142\
---------------------------------------------------------------------------
\139\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 68.
\140\ 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. at P 2.
\141\ Id.
\142\ Id. P 68 n.57.
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1. Legal Authority for Order No. 1000's Transmission Planning Reforms
a. Final Rule
103. Order No. 1000 concluded that the Commission has the authority
under section 206 of the FPA to adopt the transmission planning
reforms. The Commission explained that the reforms build on those of
Order No. 890, in which the Commission reformed the pro forma OATT to,
among other things, require each public utility transmission provider
to have a coordinated, open
[[Page 32203]]
and transparent regional transmission planning process.\143\ The
Commission concluded that the reforms adopted in Order No. 1000 are
necessary to address remaining deficiencies in transmission planning
and cost allocation processes so that the transmission grid can better
support wholesale power markets and thereby ensure that Commission-
jurisdictional transmission services are provided at rates, terms and
conditions that are just and reasonable and not unduly discriminatory
or preferential.\144\
---------------------------------------------------------------------------
\143\ Id. P 99.
\144\ Id.
---------------------------------------------------------------------------
104. Order No. 1000 rejected arguments that FPA section 202(a)
\145\ precluded the Commission from adopting the transmission planning
reforms, explaining that this provision requires that the
interconnection and coordination, i.e., coordinated operation (such as
power pooling), of facilities be voluntary and the provision does not
mention planning.\146\ The Commission explained that transmission
planning is a process that occurs prior to the interconnection and
coordination of transmission facilities. The Commission explained that
this is consistent with the Central Iowa Power Coop. v. FERC
decision,\147\ because the court in that case was presented with a
request that the Commission require an enhanced level of, or tighter,
power pooling, which the court found it could not do given ``the
expressly voluntary nature of coordination under section 202(a).''
\148\ Section 202(a) was therefore relevant to the problem at issue in
Central Iowa because, unlike Order No. 1000, the operation of the
system through power pooling was its central subject matter.\149\ The
Commission also found that because section 202(a) does not mention
transmission planning, it was unnecessary to resort to the legislative
history of the provision, which nevertheless discussed ``planned
coordination'' of the operation of facilities, not the planning process
for the identification of transmission facilities.\150\
---------------------------------------------------------------------------
\145\ Section 202(a) reads, in relevant part, as follows:
For the purpose of assuring an abundant supply of electric
energy throughout the United States with the greatest possible
economy and with regard to the proper utilization and conservation
of natural resources, the Commission is empowered and directed to
divide the country into regional districts for the voluntary
interconnection and coordination of facilities for the generation,
transmission, and sale of electric energy. * * *
16 U.S.C. 824a(a).
\146\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 100-06.
\147\ 606 F.2d 1156 (D.C. Cir. 1979) (Central Iowa).
\148\ Id. at 1168.
\149\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 102-03.
\150\ Id. PP 104-05.
---------------------------------------------------------------------------
105. The Commission also made clear that nothing in Order No. 1000
infringed on those matters traditionally reserved to the states, such
as matters relevant to siting, permitting and construction, as the
reforms in Order No. 1000 are associated with the processes used to
identify and evaluate transmission system needs and potential solutions
to those needs.\151\ Further, the Commission disagreed with commenters
suggesting that the transmission planning reforms in the Proposed Rule,
which were similar to those adopted in Order No. 1000, were
inconsistent or precluded by, or legally deficient for failing to rely
on, FPA section 217(b)(4),\152\ because Order No. 1000 supports the
development of needed transmission facilities, which ultimately
benefits load-serving entities.\153\
---------------------------------------------------------------------------
\151\ Id. P 107.
\152\ Section 217(b)(4) of the FPA specifies that:
The Commission shall exercise the authority of the Commission
under this Act 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.
16 U.S.C. 824q(b)(4).
\153\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 108.
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106. Next, the Commission concluded that it could require public
utility transmission providers to amend their OATTs to provide for the
consideration of transmission needs driven by Public Policy
Requirements. The Commission explained that such requirements may
modify the need for and configuration of prospective transmission
facility development and construction, and therefore, the transmission
planning process and the resulting transmission plans would be
deficient if they do not provide an opportunity to consider
transmission needs driven by Public Policy Requirements.\154\ The
Commission also rejected assertions that the transmission planning
reforms were inconsistent with the Administrative Procedure Act, due
process requirements, or Commission regulations governing incentive
rates.\155\ The Commission explained that it satisfied FPA section
206's burden, as its review of the record demonstrated that existing
transmission planning processes are unjust and unreasonable or unduly
discriminatory or preferential.\156\ Finally, the Commission addressed
concerns raised by non-jurisdictional entities regarding issues
associated with public power participation in the regional transmission
planning process.\157\
---------------------------------------------------------------------------
\154\ Id. PP 109-12.
\155\ Id. PP 113-15.
\156\ Id. P 116.
\157\ Id. P 117.
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107. In the section above on Need for Reform, the Commission has
already addressed legal arguments surrounding the Commission's
determination that there is substantial evidence establishing a need
for the package of reforms in Order No. 1000. A number of petitioners,
however, also seek rehearing of the Commission's conclusions regarding
its legal authority to specifically require Order No. 1000's regional
transmission planning and interregional transmission coordination
reforms. In general, these arguments, addressed below, concern: (1) The
Commission's interpretation of FPA section 202(a); (2) the Commission's
statements regarding section 217(b)(4); (3) Order No. 1000's alleged
infringement on state regulatory jurisdiction; (4) Order No. 1000's
requirement to consider transmission needs driven by Public Policy
Requirements; (5) legal issues related to interregional transmission
coordination; and (6) other legal issues.
b. Order No. 1000's Interpretation of FPA Section 202(a)
i. Requests for Rehearing and Clarification
108. Several petitioners argue that the Commission erred in
concluding that FPA section 202(a) permitted the Commission to require
public utility transmission providers to engage in mandatory regional
transmission planning and interregional transmission coordination.\158\
Generally, these petitioners assert that the Commission erred in
interpreting both the language of the statute and the D.C. Circuit's
Central Iowa decision that addressed the scope of section 202(a).\159\
Petitioners also cite to the D.C. Circuit's Atlantic City decision for
support for their proposition that transmission planning
[[Page 32204]]
is to be left to the voluntary action of public utilities under section
202(a).\160\
---------------------------------------------------------------------------
\158\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
California ISO; FirstEnergy Service Company; Large Public Power
Council; North Carolina Agencies; PPL Companies; Sacramento
Municipal Utility District; Southern Companies; and Xcel.
\159\ While most of the arguments regarding section 202(a) are
opposed to the Commission's authority over transmission planning as
a general matter, some parties raise this argument in the specific
context of interregional transmission coordination. All of the
rehearing requests regarding section 202(a) are addressed here.
\160\ Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 12 (D.C. Cir.
2002) (Atlantic City).
---------------------------------------------------------------------------
109. Many petitioners contend that Order No. 1000's interpretation
of section 202(a) is contrary to the plain meaning of the provision. Ad
Hoc Coalition of Southeastern Utilities argues that Order No. 1000
itself recognizes that transmission planning is an aspect of the
``coordination of facilities for * * * transmission'' because Order No.
1000 states that ``coordination of planning on a regional basis will
also increase efficiency through the coordination of transmission
upgrades.'' \161\ Ad Hoc Coalition of Southeastern Utilities also
argues that Order No. 1000 states that its interregional coordination
requirements involve ``coordination with regard to the identification
and evaluation of interregional transmission facilities * * *.'' \162\
FirstEnergy Service Company also cites to statements in Order No. 1000
itself, which it argues demonstrates that the Commission recognized
that transmission planning is an aspect of coordination.\163\
---------------------------------------------------------------------------
\161\ Ad Hoc Coalition of Southeastern Utilities at 35 (quoting
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 254 (emphasis
added)). See also PPL Companies.
\162\ Ad Hoc Coalition of Southeastern Utilities at 35 (quoting
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 345 n.310
(emphasis added)). PPL Companies also point out that Order No. 890
states that ``the coordination requirements imposed [therein] are
intended to address transmission planning issues.'' Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 453.
\163\ FirstEnergy Service Company at 9 (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 (stating that Order No. 1000 ``improves
coordination between neighboring transmission planning regions'')).
FirstEnergy Service Company further argues that Order No. 1000
elsewhere uses ``coordination'' to refer to coordinated planning
between regions.
---------------------------------------------------------------------------
110. Additionally, Ad Hoc Coalition of Southeastern Utilities
disagrees that section 202(a) only applies to interconnection and
operation because section 202(a) discusses ``interconnection and
coordination'' but does not mention operation. It also argues that
interconnection is discussed along with coordination rather than to the
exclusion of coordination. Thus, it argues that language regarding the
``coordination of facilities for * * * transmission'' encompasses
transmission planning. It also argues that the interconnection of
transmission facilities encompasses transmission planning. FirstEnergy
Service Company asserts that the natural reading of ``coordination'' is
not limited to ``coordinated operation,'' but also includes
``coordinated planning.'' \164\ FirstEnergy Service Company notes that,
while the Commission points to the fact that section 202(a) does not
mention planning in an effort to avoid this natural reading of
``coordination,'' the logic of the Commission's argument would mean
that ``coordinated operations'' must also be excluded, because section
202(a) does not explicitly mention ``operations,'' a point echoed by
California ISO.
---------------------------------------------------------------------------
\164\ FirstEnergy Service Company at 9 (quoting Wolverine Power
Co. v. FERC, 963 F.2d 446, 454 (D.C. Cir. 1992); U.S. v. Wells, 519
U.S. 482, 483 (1997)).
---------------------------------------------------------------------------
111. Ad Hoc Coalition of Southeastern Utilities argues that good
utility practice compels the conclusion that coordination and
interconnection closely involve system planning, asserting that for
transmission systems to be interconnected and operated in a reliable
manner, they must be planned in a coordinated manner to avoid serious
reliability consequences. FirstEnergy Service Company states that the
Commission cites no authority for the proposition that section 202(a)
focuses on power pooling, but asserts that, even if power pools were
the focus of section 202(a), the fact that the first power pool was
formed to realize the benefits and efficiencies possible by
interconnecting to share generating resources involves at least a
limited form of coordinated planning.
112. Sacramento Municipal Utility District argues that Congress
left the issue of regional planning to the voluntary decision of the
entities involved and only once they elect to do so would the
Commission have authority to determine whether the terms of their
arrangements are just and reasonable and not unduly
discriminatory.\165\ It also argues that if Congress intended that the
Commission should encourage the coordination of transmission
operations, there is no logical reason that it did not also intend that
it encourage transmission planning, which further means that it did not
intend that the Commission could mandate transmission planning.
Moreover, PPL Companies assert that in all the revisions Congress made
to the FPA in the Energy Policy Act of 2005,\166\ it did not mandate
regional planning and left section 202(a) in place without changes to
that provision's voluntary nature.
---------------------------------------------------------------------------
\165\ Sacramento Municipal Utility District at 23 (citing
Central Iowa, 606 F.2d at 1167-68).
\166\ Energy Policy Act of 2005, Public Law 109-58, Sec. Sec.
1261 et seq., 119 Stat. 594 (2005) (EPAct 2005).
---------------------------------------------------------------------------
113. Petitioners also argue that the Commission misinterpreted
Central Iowa, asserting that the court in that case understood that
coordination included transmission planning.\167\ FirstEnergy Service
Company states that Central Iowa described coordination as including
planning and described various degrees and methods of regional
coordination.\168\ Similarly, North Carolina Agencies note that Central
Iowa quoted the Commission's own statement that ``coordination is joint
planning and operation of bulk power facilities by two or more electric
systems for improved reliability and increased efficiency * * *.'' They
also argue that Central Iowa's statement that the Commission could not
have mandated the power pooling agreement means that the Commission
could not have mandated the adoption of coordinated transmission
planning.\169\
---------------------------------------------------------------------------
\167\ See, e.g., FirstEnergy Service Company; North Carolina
Agencies; Large Public Power Council; Sacramento Municipal Utility
District; Ad Hoc Coalition of Southeastern Utilities; and Southern
Companies.
\168\ FirstEnergy Service Company at 11 (citing Central Iowa,
606 F.2d at 1168, n.36).
\169\ North Carolina Agencies at 7-8 (citing Central Iowa, 606
F.2d at 1168, n.36).
---------------------------------------------------------------------------
114. Large Public Power Council also asserts that the court in
Central Iowa found that the Commission's involvement in transmission
planning rests on the voluntary cooperation of utilities subject to the
statute. Sacramento Municipal Utility District contends that the
Commission's assertion that Central Iowa meant only to refer to the
operation of transmission facilities when it said ``voluntary power
pooling'' rather than planning of their construction is not credible,
noting that the court explicitly stated that one type of pooling
arrangement is designed to achieve certain goals, ``plus the economies
of joint planning and construction of generation and transmission
facilities.'' Ad Hoc Coalition of Southeastern Utilities points to
legislative history cited in Central Iowa stating that Congress ``is
confident that enlightened self-interest will lead the utilities to
cooperate * * * in bringing about the economies which can alone be
secured through planned coordination.'' \170\ It also states that
Central Iowa noted that non-generating distribution systems ``could
attend MAPP meetings at which long-range plans are discussed'' and it
points to Central Iowa's rejection of calls to enlarge the scope of the
power pooling agreement because it ``would be inconsistent with
Congress' intent to
[[Page 32205]]
promote planned coordination of electric systems.'' \171\
---------------------------------------------------------------------------
\170\ Ad Hoc Coalition of Southeastern Utilities at 30 (citing
Central Iowa, 606 F.2d at 1162 (quoting S. Rep. No. 74-62)).
\171\ Ad Hoc Coalition of Southeastern Utilities at 39 (quoting
Central Iowa, 660 F.2d at 1165, 1170).
---------------------------------------------------------------------------
115. Other petitioners also assert that the legislative history of
section 202(a), as well as the Commission's own precedent, undermine
Order No. 1000's interpretation of that provision.\172\ North Carolina
Agencies emphasize that Congress rejected arguments by the Federal
Power Commission that it should be empowered to mandate such
coordination when it adopted section 202(a)'s requirements. They argue
that section 202(b) \173\ also reveals that Congress purposefully
limited the Commission's authority to require coordination by enabling
it only to order the interconnection of facilities and the sale/
exchange of electricity. Ad Hoc Coalition of Southeastern Utilities and
Southern Companies point out that the solicitor of the Federal Power
Commission testified before Congress that the express intent in
drafting section 202(a) was to facilitate regional planning.
Petitioners also cite to Federal Power Commission policy statements
regarding data collection that make statements such as ``[l]ong-range
planning is an indispensable element to the accomplishment of the
objectives of [s]ection 202(a)'' and that achieving the goals of
section 202(a) ``requires coordinated efforts on an industry[-]wide
basis, at both the regional and national levels, to enhance reliability
and adequacy of service.'' \174\
---------------------------------------------------------------------------
\172\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Large Public Power Council; Sacramento Municipal Utility District;
and Southern Companies.
\173\ FPA section 202(b) provides, in part:
Whenever the Commission, upon application * * * and after notice
* * * and after opportunity for hearing, finds such action necessary
or appropriate in the public interest it may by order direct a
public utility * * * to establish physical connection of its
transmission facilities with the facilities of one or more other
persons engaged in the transmission or sale of electric energy, to
sell energy to or exchange energy with such persons: Provided, That
the Commission shall have no authority to compel the enlargement of
generating facilities for such purposes, nor to compel such public
utility to sell or exchange energy when to do so would impair its
ability to render adequate service to its customers.
16 U.S.C. 824a(b).
\174\ Ad Hoc Coalition of Southeastern Utilities at 40 (quoting
Reliability and Adequacy of Electric Service--Reporting of Data,
Order No. 838-4, 56 FPC 3547, 3548 (1976); Reliability and Adequacy
of Electric Service--Reporting of Data, Order No. 383, 41 FPC 846
(1969)); Southern Companies at 39-40; Large Public Power Council at
19-20.
---------------------------------------------------------------------------
116. Ad Hoc Coalition of Southeastern Utilities points to the 1970
National Power Survey, which stated that ``coordination is joint
planning and operation of bulk power facilities by two or more electric
systems for improved reliability and increased efficiency which would
not be attainable if each system acted independently.'' \175\
Sacramento Municipal Utility District argues that the notion that
section 202(a) does not include transmission planning, or that
transmission planning is not considered part of the coordination of
electric systems, would surprise those who recall the Federal Power
Commission's work with regional reliability councils in the decades
following the Northeast blackout of 1965. It also asserts that the
Commission's interpretation cannot be squared with the 1993 Policy
Statement Regarding Regional Transmission Groups, where the Commission
recognized it lacked authority to mandate the formation of regional
transmission organizations.\176\
---------------------------------------------------------------------------
\175\ Ad Hoc Coalition of Southeastern Utilities at 37. Ad Hoc
Coalition of Southeastern Utilities also states that the
Commission's interpretation of Central Iowa is at odds with former
Commissioner Vicky A. Bailey's statement that ``Congress * * * was
motivated by the desire to leave the coordination and joint planning
of utility systems to be to the voluntary judgment of individual
utilities.'' Ad Hoc Coalition of Southeastern Utilities at 40
(quoting Regional Transmission Organizations, Order No. 2000, FERC
Stats. & Regs. ] 31,089 (Bailey, Comm'r. concurring)).
\176\ Sacramento Municipal Utility District at 25 (citing Policy
Statement Regarding Regional Transmission Groups, FERC Stats. &
Regs. ] 30,967 at 30,870 & 30,872 (1993) (RTG Policy Statement)).
---------------------------------------------------------------------------
117. Some petitioners also cite to the D.C. Circuit's Atlantic City
decision. FirstEnergy Service Company quotes Atlantic City's conclusion
that the Commission's ``expansive reading of its section 203
jurisdiction could not be reconciled with section 202, which has been
definitively interpreted to make clear that Congress intended
coordination and interconnection arrangements be left to the voluntary
action of the utilities.'' \177\ Ad Hoc Coalition of Southeastern
Utilities claims that Atlantic City reinforces that section 202(a)
encompasses transmission planning, noting that the court held that
section 202(a) applied to an ISO arrangement, which encompassed
transmission planning, and therefore its voluntary nature precluded the
Commission from requiring transmission owners to make a filing under
section 203 before they could leave the ISO.\178\ Southern Companies
state Order No. 1000 conceded that the interregional coordination
required constitutes the ``coordination of facilities * * * for
transmission.'' \179\ Thus, Southern Companies argue that Order No.
1000, by specifying that public utility transmission providers adopt
identical terms and conditions in their respective OATTs, requires the
functional equivalent of mandatory coordination agreements despite the
court's decision in Atlantic City that the Commission cannot require
adoption of coordination agreements.\180\
---------------------------------------------------------------------------
\177\ First Energy Companies at 7 (citing Atlantic City, 295
F.3d at 12).
\178\ Ad Hoc Coalition of Southeastern Utilities at n.117
(citing Atlantic City, 295 F.3d at 11-14).
\179\ Southern Companies at 85 (citing Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 345 n.310; 16 U.S.C. 824a(a)).
\180\ Southern Companies at 85 (citing Atlantic City, 295 F.3d
at 12 (D.C. Cir. 2002)).
---------------------------------------------------------------------------
118. Southern Companies also assert that the design of the FPA is
one of specifically conferred powers, not broad sweeping
authority.\181\ They add that regional transmission planning is
voluntary under section 202(a) and note the Commission did not invoke
its limited authority under section 216. Southern Companies also assert
that the Commission's broader plenary authority over interstate
transmission facilities set forth in FPA section 201 cannot be
construed to allow the Commission to indirectly regulate matters
incident to primary state jurisdiction over transmission facility
necessity, siting, and construction.\182\
---------------------------------------------------------------------------
\181\ Southern Companies at 101 (citing Otter Tail Power Co. v.
U.S., 410 U.S. 366, 374 (1973) (stating that Part II of the FPA does
not involve pervasive regulatory scheme over any or all activities
that could have an effect on transmission rates or services)).
\182\ Southern Companies at 102 (citing 16 U.S.C. 824(b)).
---------------------------------------------------------------------------
119. In addition, Large Public Power Council disagrees with the
Commission's statement in Order No. 1000 that Order No. 890 serves as
precedent for the exercise of mandatory authority over transmission
planning because jurisdictional and non-jurisdictional utilities
voluntarily complied with the Order No. 890 reforms, leaving no
opportunity for judicial review. Accordingly, Large Public Power
Council argues the question of whether the Commission has acted outside
of its authority may always be raised.\183\
---------------------------------------------------------------------------
\183\ Large Public Power Council at 21 (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 99).
---------------------------------------------------------------------------
120. Finally, Ad Hoc Coalition of Southeastern Utilities asserts
that even if section 202(a) does not encompass transmission planning,
nothing in the FPA provides the Commission with any authority in this
area. It reiterates that section 217(b)(4) is clear that the Commission
is charged with facilitating transmission planning to meet native load,
and it adds that nothing else in the statute suggests that the
Commission has authority over this area.
[[Page 32206]]
ii. Commission Determination
121. We deny rehearing. The arguments provided in the various
requests for rehearing on the Commission's interpretation of FPA
section 202(a) do not persuade us that the Commission's interpretation
is at odds with existing precedent or that it does not represent a
reasonable interpretation of the statute. The arguments raised on
rehearing largely repeat or further elaborate upon points that the
Commission rejected in Order No. 1000. For ease of reference in the
following discussion, we restate here our interpretation of section
202(a).
122. Section 202(a) reads, in relevant part, as follows:
For the purpose of assuring an abundant supply of electric
energy throughout the United States with the greatest possible
economy and with regard to the proper utilization and conservation
of natural resources, the Commission is empowered and directed to
divide the country into regional districts for the voluntary
interconnection and coordination of facilities for the generation,
transmission, and sale of electric energy. * * * \184\
\184\ 16 U.S.C. 824(a) (2006).
123. As the Commission explained in Order No. 1000, section 202(a)
requires that the interconnection and coordination, i.e., the
coordinated operation, of facilities be voluntary. It neither mentions
planning nor implicitly establishes limits on the Commission's
jurisdiction with respect to transmission planning. The Commission
explained that transmission planning is a process that occurs prior to
the interconnection and coordination of transmission facilities. The
transmission planning process itself does not create any obligations to
interconnect or operate in a certain way. Thus, the Commission found
that when establishing transmission planning process requirements, it
is in no way mandating or otherwise impinging upon matters that section
202(a) leaves to the voluntary action of public utility transmission
providers.\185\ As explained below, this point is reinforced by the way
that section 202(a) presents the matters that it does address in a
specific sequence.
---------------------------------------------------------------------------
\185\ See Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP
100-01.
---------------------------------------------------------------------------
124. First, section 202(a) empowers the Commission to divide the
country into regional districts. If the Commission takes that step, the
statute then envisions voluntary interconnection of facilities within
those districts, after which occurs the voluntary coordination of those
facilities, something which can occur only after the facilities are
interconnected. This sequence leads to the inference that the
``coordination of facilities'' refers to their operational
coordination, the only relevant form of coordination once facilities
are interconnected.
125. The planning of new transmission facilities occurs before they
can be interconnected, and for this reason any transmission planning
relevant to these facilities occurs prior to those matters that the
statute mandates be voluntary. The requirements of Order No. 1000
explicitly pertain only to the coordination of transmission planning,
not the coordination of operations of generation and transmission
facilities. In short, Order No. 1000 deals with the coordination of a
process that is separate and distinct from, and that is completed prior
to, the coordination of facilities that is the concern in section
202(a). For this reason, the transmission planning requirements of
Order No. 1000 fall outside the scope of section 202(a) because they
apply to matters that occur prior to any actions that fall within its
scope.
126. Our task here is to provide a reasonable interpretation of
section 202(a),\186\ and we have done that. Our reading of the statute
follows the direct flow of the statutory language, and in that way, it
conforms with ``the cardinal rule that `[s]tatutory language must be
read in context [since] a phrase `gathers meaning from the words around
it.' ' '' \187\ It draws the most reasonable inference from the absence
of any mention of planning, i.e., that Congress did not intend section
202(a) to apply to the planning of new transmission facilities. It also
is consistent with the intent of Congress, which was the promotion of
the economic use of resources through power pooling, as we discuss
herein.\188\
---------------------------------------------------------------------------
\186\ Chevron U.S.A. v. Natural Resources Defense Council, 467
U.S. 837, 842-45 (1984) (Chevron).
\187\ General Dynamics Land Sys., Inc. v. Cline, 540 U.S. 581,
596 (2004). (quoting Jones v. United States, 527 U.S. 373, 389,
(1999) (quoting Jarecki v. G. D. Searle & Co., 367 U.S. 303, 307
(1961))).
\188\ See discussion infra at P 0.
---------------------------------------------------------------------------
127. The arguments that have been raised on rehearing against this
interpretation of section 202(a) fall into two broad categories. The
first involves claims concerning the nature of planning. The argument
that petitioners advance is that planning by its nature is inherently
inseparable from the interconnection and coordination of facilities
mentioned in the statute. These arguments assert that the nature of
planning is such that the requirement that it be voluntary either is
found directly in the plain meaning of the language of the statute or
is clearly implied by that language. The second class of arguments
involves the claim that a number of court cases involving section
202(a), in particular Central Iowa, demonstrate that the transmission
planning requirements of Order No. 1000 violate the statute. Many
petitioners also point to Commission orders and studies that they claim
support the same conclusion.
128. The first class of arguments can be summarized as follows:
planning is necessary to interconnect and coordinate facilities;
section 202(a) prohibits the Commission from requiring the
interconnection and coordination of facilities; therefore, section
202(a) prohibits the Commission from requiring anything pertaining to
new transmission facility planning. For example, Ad Hoc Coalition of
Southeastern Utilities argues that transmission planning is an aspect
of the coordination of facilities, and therefore, if the
interconnection and coordination of transmission facilities must be
voluntary, transmission planning alone also must be coordinated
voluntarily. A number of other petitioners make similar arguments.\189\
---------------------------------------------------------------------------
\189\ See, e.g., PPL Companies; and Southern Companies.
---------------------------------------------------------------------------
129. While it is true that facilities must be planned before they
can be interconnected and coordinated, we find that this fact proves
nothing regarding the scope of section 202(a). The fact that many
significant undertakings require planning does not mean that the
planning process is indistinct and inseparable from the implementation
of plans and subsequent operations. For instance, there is a
significant difference between planning a trip and taking it. Likewise,
the act of planning the transmission grid and the act of coordinating
facilities in their operations are two quite different things. In the
case of transmission facilities, planning involves the consideration of
various alternatives using economic and engineering analysis, whereas
the operation of interconnected facilities involves operational
cooperation, such as coordinated dispatch, among other things. We thus
disagree with the various petitioners who argue that the ``coordination
of facilities * * * for transmission'' necessarily encompasses
transmission planning. The latter must be completed before the former
can occur. Moreover, planning is an extremely general concept, which
means that in practice there are many different types of planning. A
plan for
[[Page 32207]]
the coordination of facilities for the generation, transmission, and
sale of electric energy is an operational plan for facilities already
in existence. Such a plan differs from a plan for the development of
new transmission facilities, which is all that is at issue under Order
No. 1000.
130. In addition, to plan is not to mandate some action that occurs
beyond the planning process. Between planning and the implementation of
a plan stands a decision to proceed or not to proceed with some or all
of the planning proposals. We thus disagree with North Carolina
Agencies that the transmission planning process itself creates
obligations regarding interconnection or operation.
131. FirstEnergy Service Company states that one must begin with
the literal terms of the statute and maintains that when one does, one
finds that the natural reading of ``coordination'' includes both
coordinated planning and coordinated operation. While we agree with
FirstEnergy Service Company on the starting point of statutory
interpretation, one cannot stop there. It is a ``fundamental principle
of statutory construction (and, indeed, of language itself) that the
meaning of a word cannot be determined in isolation, but must be drawn
from the context in which it is used.'' \190\ Section 202(a) does not
use the term ``coordination'' in isolation but rather in the phrase
``coordination of facilities.'' The language found in section 202(a)
does not include any terms such as plan or planning or any synonyms for
such terms. We disagree that the ``natural reading'' of
``coordination'' in the phrase ``coordination of facilities'' requires
one to conclude that the phrase means both ``coordination of
facilities'' and ``coordination of planning.''
---------------------------------------------------------------------------
\190\ Deal v. United States, 508 U.S. 129, at 132 (1993).
---------------------------------------------------------------------------
132. FirstEnergy Service Company defends its ``natural'' reading of
the term ``coordination'' in section 202(a) by pointing to the various
uses that the Commission has made of the term in Order No. 1000,
including statements on how the planning requirements of Order No. 1000
promote coordination among planning regions. Ad Hoc Coalition of
Southeastern Utilities and PPL Companies make similar arguments. We
reject these arguments because, as used by the Commission in those
instances, ``coordination'' simply means ``joint cooperation,'' not
coordination as petitioners argue. The word ``coordination,'' like
``planning,'' is extremely general in its scope. Its meaning in one
context, such as section 202(a), does not suggest or imply that it has
the same meaning in every other context, such as Commission references
to the coordination of new transmission planning. As noted above, ``the
meaning of a word cannot be determined in isolation, but must be drawn
from the context in which it is used.'' \191\ In the case of Order No.
1000, the use of the term ``coordination'' in connection with new
requirements is restricted to interregional transmission coordination.
We see no connection between the coordination between regions and the
coordination of facilities referred to in section 202(a).
---------------------------------------------------------------------------
\191\ Deal v. United States, 508 U.S. at 132.
---------------------------------------------------------------------------
133. Additionally, Ad Hoc Coalition of Southeastern Utilities
overlooks this point when it argues that Order No. 1000 found that its
interregional transmission coordination requirements involve
``coordination with regard to the identification and evaluation of
interregional transmission facilities * * *.'' \192\ The quoted
language is taken out of context as the footnote in Order No. 1000 from
which it is drawn is intended to make clear that the Commission draws a
distinction between the interregional transmission coordination it is
requiring in Order No. 1000 and the type of coordination at issue in
section 202(a). The full footnote is as follows: ``[w]e note that our
use of the term `coordination' with regard to the identification and
evaluation of interregional transmission facilities is distinct from
the type of coordination of system operations discussed in connection
with section 202(a) of the FPA.'' \193\ FirstEnergy Service Company
also claims support for its argument in the statement in Order No. 1000
that its interregional planning reforms would ``improve coordination
among public utility transmission planners with respect to the
coordination of interregional transmission facilities.'' \194\ This
argument, however, fails for the same reason. The language from Order
No. 1000 cited immediately above makes clear that the Commission
distinguished its use of the word ``coordination'' with regard to
interregional coordination of new transmission planning in Order No.
1000 from the meaning of the word ``coordination'' in section 202(a).
---------------------------------------------------------------------------
\192\ Ad Hoc Coalition of Southeastern Utilities at 35 (quoting
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 345 n.310
(emphasis added)).
\193\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 345
n.310 (emphasis added).
\194\ Id. P 345.
---------------------------------------------------------------------------
134. We also disagree with FirstEnergy Service Company that the
Commission cites no authority for the proposition that power pools and
operational activities were the focus of section 202(a). Central Iowa
supports the Commission's view.\195\ Moreover, the standard that the
Commission must satisfy in advancing an interpretation of section
202(a) is that it be a reasonable interpretation.\196\ The Commission's
interpretation is a reasonable one, given that the provision seeks the
promotion of the ``interconnection and coordination of facilities for
the generation, transmission, and sale of electric energy,'' i.e.,
existing resources of public utility systems, for the purpose of
promoting ``the greatest possible economy and with regard to the proper
utilization and conservation of natural resources.'' \197\ Such
economizing of resources is the purpose of a power pool. This is
precisely the point made in the secondary literature that the court
quoted in Central Iowa, which reinforces the point that the case
supports the Commission's interpretation.\198\
---------------------------------------------------------------------------
\195\ See, e.g., Central Iowa, 606 F.2d at 1160-62 (stating that
the agreement at issue is designed to promote reliable and
economical operation of the interconnected electric network in the
mid-continent area).
\196\ Chevron U.S.A. v. Natural Resources Defense Council, 467
U.S. 837, 842-45 (1984) (Chevron).
\197\ 16 U.S.C. 824a(a).
\198\ Central Iowa, 606 F.2d at n.16.
---------------------------------------------------------------------------
135. Sacramento Municipal Utility District argues that if Congress
intended that the Commission should encourage the coordination of
transmission operations, there is no logical reason that it did not
also intend that the Commission encourage transmission planning, which
further means that it did not intend that the Commission could mandate
transmission planning. On the contrary, there is no logical basis for
this conclusion. Section 202(a) deals with the coordination of
facilities, i.e., facilities already in existence, whereas Order No.
1000 deals with the planning of new transmission facilities. While
facilities must be planned before they can be built, and built before
they can be coordinated, it does not logically follow that
encouragement of the coordination of existing facilities entails
encouraging the planning of new facilities, which, if built, could be
coordinated. There is thus no logical basis for concluding that
Congress intended anything at all with regard to planning of new
transmission facilities.
136. Similar considerations apply to the argument that the plain
meaning of section 202(a) requires one to conclude that joint planning
must be voluntary. The basic principle underlying the plain meaning
rule is that in interpreting a statute, ``we start--and if it is
`sufficiently clear in its context,' end--
[[Page 32208]]
with the plain language of the statute.'' \199\ To end with the plain
language of the statute means that:
\199\ Lutheran Hosp. of Indiana, Inc. v. Business Men's Assur.
Co., 51 F.3d 1308, 1312 (7th Cir. 1995) (quoting Ernst & Ernst v.
Hochfelder, 425 U.S. 185, 201 (1976)).
* * * when words are free from doubt they must be taken as the
final expression of the legislative intent, and are not to be added
to or subtracted from by considerations drawn from titles or
designating names or reports accompanying their introduction, or
from any extraneous source. In other words, the language being
plain, and not leading to absurd or wholly impracticable
consequences, it is the sole evidence of the ultimate legislative
intent.\200\
---------------------------------------------------------------------------
\200\ Caminetti v. United States, 242 U.S. 470, 490 (1917).
Section 202(a) makes no mention of transmission plans, planning new
transmission, or any planning at all. Therefore, the plain meaning rule
does not support petitioners' argument. Petitioners' reading of section
202(a) is not a required interpretation of the statute.
137. For instance, Ad Hoc Coalition of Southeastern Utilities
argues that the coordination of facilities for transmission encompasses
transmission planning. This is an argument based on inference, not
plain meaning, and ``[i]nterpreting the intent of Congress from the
inferential meaning of its statutes is a far different exercise * * *
from looking at the plain meaning of a statute for an express
provision. * * *'' \201\ To argue that a statute requires a particular
result based on an inference, the inference must be a necessary one,
not simply one that is possible.\202\ That the interpretation proposed
by petitioners is not a necessary one is demonstrated by the existence
of other, and in our view, more reasonable interpretations such as the
one advanced in Order No. 1000. We are required only to present a
reasonable interpretation,\203\ and we believe that we have done so.
---------------------------------------------------------------------------
\201\ Breuer v. Jim's Concrete of Brevard, Inc., 292 F.3d 1308,
1309 (11th Cir. 2002), aff'd, 538 U.S. 691 (2003).
\202\ Kirkhuff v. Nimmo, 683 F.2d 544, 549 (D.C. Cir. 1982);
Safarik v. Udall, 304 F.2d 944, 948 (D.C. Cir. 1962); 2B Sutherland
Statutory Construction Sec. 55:3 (7th ed.).
\203\ Chevron, 467 U.S. at 842-45.
---------------------------------------------------------------------------
138. Nevertheless, Ad Hoc Coalition of Southeastern Utilities and
Southern Companies further maintain that the Federal Power Commission
assisted Congress in drafting the FPA with the express intent of
facilitating regional planning. They argue that the legislative history
of the statute demonstrates this and undercuts the Commission's
position that the ``planned coordination'' mentioned in the legislative
history refers only to the coordination of facility operations.
However, the evidence on which Ad Hoc Coalition of Southeastern
Utilities and Southern Companies base their argument--statements made
in Congressional hearings by the Federal Power Commission's solicitor
and drafting representative, Dozier A. DeVane--does not support their
conclusion and is, at best, irrelevant to the point they seek to make.
139. It is important to note that Mr. DeVane was commenting on an
early draft of the FPA that differs in fundamental respects from the
version that eventually became law. Specifically, the draft in question
created an obligation for all public utilities ``to furnish energy to,
exchange energy with, and transmit energy for any person upon
reasonable request therefore. * * *'' \204\ The draft also required
public utilities to receive a certificate of public convenience and
necessity before constructing or operating new jurisdictional
facilities or abandoning facilities other than through retirement in
the normal course of business.\205\ In short, the draft statute was to
require sales and exchanges of energy that are central to pooling
operations, and the Commission was to have direct oversight over the
development of the transmission grid through the approval of new
facilities prior to construction. As Ad Hoc Coalition of Southeastern
Utilities and Southern Companies note, Mr. DeVane considered these
sections to be among those that were ``absolutely necessary to
effectively carry out regional planning.'' \206\ Thus, even if Ad Hoc
Coalition of Southeastern Utilities and Southern Companies are correct
that the Federal Power Commission draft of the FPA expressed an intent
to facilitate planning, that intent is not expressed in the statute
itself since provisions that the Federal Power Commission
representative considered to be essential to the goal were not included
in the statute. Moreover, given the fact that the Commission would have
had oversight over the transmission development process through the
power to issue certificates of public convenience and necessity, we
think that Mr. DeVane meant by ``planning'' the planning and promotion
of enhanced power pooling under active Commission supervision,
something very different from the matters at issue in this proceeding.
We thus do not agree with Ad Hoc Coalition of Southeastern Utilities
and Southern Companies that the legislative history of the FPA
contradicts the Commission's interpretation of section 202(a) of the
statute.
---------------------------------------------------------------------------
\204\ Hearing on H.R. 5423 Before the House Interstate & Foreign
Commerce Comm. 74th Cong. 32 (1935).
\205\ Id. The language on certificates of public convenience and
necessity is found in section 204(a) of the draft statute, which
provided that:
No public utility shall undertake the construction or extension
of any facilities subject to the jurisdiction of the Commission, or
acquire or operate any such facilities, or extension thereof, or
engage in production or transmission by means of any such new or
additional facilities or receive energy from any new source, unless
and until there shall first have been obtained from the Commission a
certificate that the present or future public convenience and
necessity require or will require such new construction, or
operation or additional supply of electric energy. * * *
\206\ Ad Hoc Coalition of Southeastern Utilities at 41 (quoting
Hearing on H.R. 5423 Before the House Interstate & Foreign Commerce
Comm. 74th Cong. 560 (1935)); Southern Companies at 40 (quoting the
same text).
---------------------------------------------------------------------------
140. This brings us to the second class of arguments advanced by
petitioners, those that rely on sources such as court cases dealing
with section 202(a), as well as Commission orders and reports.
Petitioners who advance such arguments on rehearing focus on Central
Iowa. As the Commission noted in Order No. 1000, Central Iowa dealt
with a claim that the Commission should have used its authority under
section 206 of the FPA to compel greater integration of the utilities
within the Mid-Continent Area Power Pool (MAPP) than was specified in
the MAPP agreement. Those who took this position in the Commission
proceeding at issue in Central Iowa sought to have the Commission
require MAPP participants ``to construct larger generation units and
engage in single system planning with central dispatch.'' \207\ The
court held that given ``the expressly voluntary nature of coordination
under section 202(a),'' the Commission was not authorized to grant that
request.\208\
---------------------------------------------------------------------------
\207\ Central Iowa, 606 F.2d at 1166.
\208\ Id. at 1168.
---------------------------------------------------------------------------
141. The court in Central Iowa was thus presented with a request
that the Commission require an enhanced level of, or tighter, power
pooling. Section 202(a) was relevant to the problem at issue in Central
Iowa because the operation of the system through power pooling is its
central subject matter. Order No. 1000, however, is focused on the
process of planning new transmission, which is distinct from any
specific system operations. Nothing in Order No. 1000 is tied to the
characteristics of any specific form of system operations, and nothing
in it requires any changes in the way existing operations are
conducted. Order No. 1000 requires compliance with certain general
principles within the
[[Page 32209]]
transmission planning process regardless of the nature of the
operations to which that process is attached. The court's
interpretation of section 202(a) with respect to system operations is
therefore not applicable.\209\
---------------------------------------------------------------------------
\209\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at 103.
---------------------------------------------------------------------------
142. Many of the arguments that petitioners make based on their
reading of Central Iowa attempt to demonstrate that regional
transmission planning must be voluntary because the court in various
ways noted the importance of planning for the interconnection and
coordination of facilities. Large Public Power Council maintains that
the court in Central Iowa believed that planning was an intimate part
of the authority addressed in section 202(a) based on the court's
reference to a passage in the legislative history discussing ``the
economies which alone can be secured through * * * planned
coordination.'' \210\ Several petitioners also point to the court's use
of the definition of ``coordination'' set forth in the Commission's
1970 National Power Survey. This definition states that ``coordination
is joint planning and operation of bulk power facilities by two or more
electric systems for improved reliability and increased efficiency
which would not be attainable if each system acted independently.''
Large Public Power Council also cites the court's reference to a
passage from the 1970 National Power Survey that states that the
``[r]eduction of installed reserve capacity is made possible by mutual
emergency assistance arrangements and associated coordinated
transmission planning.'' \211\
---------------------------------------------------------------------------
\210\ Large Public Power Council at 20 (quoting S Rep. No. 74-
621 at 49 (1935), as cited by Central Iowa, 606 F.2d at 1162).
\211\ Large Public Power Council at 21 (quoting 1970 National
Power Survey, p. I-17-1, as cited by Central Iowa, 606 F. 2d at
n.23).
---------------------------------------------------------------------------
143. As explained in Order No. 1000, section 202(a) does not
mention ``planning,'' and we have determined that section 202(a) was
not intended to address the process of planning new transmission
facilities that is the subject of this proceeding. Moreover, the cited
legislative history does not refer to the new transmission planning
process that is the subject of Order No. 1000. Instead, the legislative
history refers to ``planned coordination,'' i.e., to the pooling
arrangements and other aspects of system operation that are the
underlying focus of section 202(a). It is in this sense that Central
Iowa must be understood when it refers to engaging ``voluntarily in
power planning arrangements.'' The ``planned coordination'' mentioned
in the legislative history cited in Central Iowa means ``planned
coordination'' of the operation of existing facilities, not the
planning process for the identification of new transmission facilities.
In short, neither Central Iowa nor the legislative history cited in
that case involves or applies to the planning process for new
transmission facilities. Rather, they deal with the coordinated, i.e.,
shared or pooled, operation of facilities after those facilities are
identified and developed. By contrast, Order No. 1000 deals with the
process for planning new transmission facilities, a separate and
distinct set of activities that occur before new transmission facility
construction and before the generation and transmission operational
activities that are the subject of section 202(a).\212\
---------------------------------------------------------------------------
\212\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 105.
---------------------------------------------------------------------------
144. Additionally, we note that in referring to ``the economies
which alone can be secured through * * * planned coordination,'' the
legislative history is referring to the economies that arise through
the coordination of facilities in power pool operations. The
legislative history states that Part II of the FPA ``seeks to bring
about the regional coordination of the operating facilities of the
interstate utilities.'' \213\ Planned coordination in facility
operations generally involves utilizing the lowest cost generation
facilities available at any particular time and reducing installed
reserve capacity. The new transmission planning required by Order No.
1000 is intended to ensure that transmission planning processes
consider and evaluate possible transmission alternatives and produce
transmission plans that can meet transmission needs more efficiently
and cost-effectively. Nothing in the coordinated new transmission
planning process envisioned by Order No. 1000 requires or inevitably
leads to the coordinated operation of existing generation and
transmission facilities and coordinated sales of electric energy in
pooling operations envisioned in the legislative history of section
202(a).
---------------------------------------------------------------------------
\213\ S. Rep. No. 621, 74th Cong., 1st Sess. 4 (1935).
---------------------------------------------------------------------------
145. Moreover, the fact that the legislative history describes the
coordination of facilities that Congress had in mind as ``planned''
does not make the planning requirements in Order No. 1000 part of what
was under discussion in the legislative history. As noted above,
planning is an extremely general concept. The broad range of activities
that involve planning cannot be deemed to be intrinsically related to
each other simply by virtue of having a characteristic in common that
virtually all business, commercial, and industrial activities share.
146. Additionally, nothing anyone cites to in the 1970 National
Power Survey suggests that its definition of the term ``coordination''
is intended as an interpretation of the term ``coordination'' for
purposes of section 202(a). Moreover, if ``coordination'' means, as the
1970 National Power Survey defines it to mean, ``joint planning and
operation of bulk power facilities'' (emphasis supplied), then joint
planning alone, which is only one element of the definition, is not
coordination under this definition. Therefore, Order No. 1000 does not
require coordination under this definition because it does not require
one of the essential elements of the definition (i.e., it does not
require joint operation). We thus see no basis to conclude that the
definition of ``coordination'' in the 1970 National Power Survey or use
of the definition by the court in Central Iowa demonstrates that the
phrase ``coordination of facilities'' in section 202(a) also means
``coordination of planning.''
147. The language from the 1970 National Power Survey that Large
Public Power Council cites also does not demonstrate that planning is
necessarily part of the authority addressed in section 202(a). This
language simply points out that coordinated transmission planning can
play a role in reducing the amount of installed reserve capacity
needed. The coordination of plans for new transmission can have many
beneficial effects, but the argument that one of these effects brings
it within the function addressed in section 202(a) because it is
something that the section requires to be voluntary is another example
of a failure to distinguish between new transmission planning and the
implementation of plans for other purposes. The statement from the 1970
National Power Survey does not show that planning is an integral part
of the authority addressed in section 202(a) because nothing in it
shows how the planning requirements of Order No. 1000 have the effect
of requiring either the interconnection or the coordination of
facilities.
148. Additionally, Sacramento Municipal Utility District argues
that the court in Central Iowa did not mean to refer only to facility
operations when referring to voluntary power pooling because it noted
that some forms of pooling are designed to achieve certain goals, plus
economies of joint planning and construction of generation and
transmission facilities. This fact does not make joint planning by
itself, which is the subject of Order No. 1000, a form
[[Page 32210]]
of power pooling or demonstrate that something falls within the scope
of section 202(a) simply because it is something that some power pools
have decided to do.
149. Sacramento Municipal Utility District also cites Central Iowa
as support for the argument that the Commission's authority is limited
to determining whether the terms of any voluntary agreements to plan
together are just and reasonable and not unduly discriminatory or
preferential. In fact, however, Central Iowa does not support
Sacramento Municipal Utility District's argument. In that case, the
court approved Commission action requiring joint planning where one
group of public utilities refused to agree to plan together with
another group. Specifically, the MAPP agreement separated MAPP members
into different classes based on the size of their systems and allowed
members of the class with larger, but not those with smaller, systems
to have access to the planning function. Those not admitted objected,
and the Commission found the size criterion irrelevant and unduly
discriminatory and required the admission of the previously excluded
systems.\214\
---------------------------------------------------------------------------
\214\ Mid-Continent Area Power Pool Agreement, Opinion No. 806,
58 F.P.C. 2622, 2631-36 (1977) (MAPP Agreement Order).
---------------------------------------------------------------------------
150. In other words, Central Iowa involved a situation where a
power pool voluntarily agreed to joint planning and operation, but
allowed only some members to participate in planning. The Commission
found that it was unduly discriminatory to allow only some members to
participate in planning, directed MAPP to allow all members to
participate in planning, and the Court affirmed that decision.\215\
While Sacramento Municipal Utility District contends Central Iowa
limits the Commission's ability to create planning requirements to the
circumstances there, nothing in the Court's opinion supports this.
Rather the opinion shows that the Court focused on and affirmed the
Commission on the specific facts before it. Whether the Commission can
mandate planning in other circumstances, such as those here, was
neither considered by nor ruled on by the Court. For these reasons, we
also disagree with North Carolina Agencies that the court's statement
in Central Iowa that the Commission could not have mandated the
adoption of the MAPP agreement means that the Commission could not have
mandated coordinated transmission planning. The court specifically
approved a Commission mandate of joint planning.
---------------------------------------------------------------------------
\215\ Central Iowa, 606 F.2d at 1170-72.
---------------------------------------------------------------------------
151. We also disagree with Sacramento Municipal Utility District
that the Commission's action in the order underlying Central Iowa was
proper only because the planning provisions of the MAPP agreement were
``the voluntary decision of the entities involved,'' \216\ i.e., the
voluntary decision of those MAPP members that had agreed to engage in
planning with some MAPP members but not with others. Rather, the
Commission imposed the requirement in the absence of any substantive
agreement to the requirement among the parties affected, because the
practices at issue were matters that were subject to the Commission's
jurisdiction under sections 205 and 206 of the FPA.\217\ That is, the
Commission's authority arises from the fact that planning is a practice
that affects rates, and the Commission has a duty under sections 205
and 206 of the FPA to ensure that such practices are just and
reasonable and not unduly discriminatory or preferential. Indeed, this
is the very same authority upon which the Commission relies in adopting
the transmission planning reforms in Order No. 1000. This point also
supplies our response to Ad Hoc Coalition of Southeastern Utilities'
claim that even if section 202(a) does not encompass transmission
planning, nothing in the FPA gives the Commission any authority in this
area.
---------------------------------------------------------------------------
\216\ Sacramento Municipal Utility District at 23.
\217\ Central Iowa at 1170; MAPP Agreement Order, 58 F.P.C. at
2636-37.
---------------------------------------------------------------------------
152. Regarding Ad Hoc Coalition of Southeastern Utilities' argument
that the Commission's interpretation of Central Iowa is at odds with
former Commissioner Vicky A. Bailey's statement that ``Congress * * *
was motivated by the desire to leave the coordination and joint
planning of utility systems to be to the voluntary judgment of
individual utilities,'' \218\ we note that she made this statement in
an opinion in which she concurred in part and dissented in part.
Neither concurring opinions nor dissenting opinions constitute binding
precedent,\219\ and Commissioner Bailey's statement thus does not call
into question the validity of our actions here.
---------------------------------------------------------------------------
\218\ Ad Hoc Coalition of Southeastern Utilities at 40 (quoting
Regional Transmission Organizations, Order No. 2000, FERC Stats. &
Regs. ] 31,089 (Bailey, Comm'r. concurring in part and dissenting in
part)).
\219\ Maryland v. Wilson, 519 U.S. 408, 412-13 (1997)
(acknowledging that a concurring opinion does not constitute binding
precedent).
---------------------------------------------------------------------------
153. We also find nothing in Atlantic City that is relevant to the
issue of the Commission's authority to establish transmission planning
requirements. In Atlantic City, the court held that the Commission
could not require a transmission-owing public utility to obtain
authorization under section 203 of the FPA before withdrawing from an
ISO. The court reasoned that section 203 applies only to situations
where a public utility sells, leases, or otherwise disposes of
jurisdictional assets, and the transfers of control over such
facilities that occurred when a public utility joined or departed from
an ISO did not rise to the level of such a transaction. The court also
concluded that the Commission's position that approval under section
203 is required could not be reconciled with the requirement of section
202(a) that arrangements for the interconnection and coordination of
facilities be voluntary. The court nowhere stated or implied that these
voluntary arrangements also covered planning matters. Indeed, the
court's main point was that section 202(a) ``does not provide [the
Commission] with any substantive powers `to compel any particular
interconnection or technique of coordination.' '' \220\ Nothing in
Order No. 1000 compels ``any particular interconnection or technique of
coordination'' or indeed any interconnection or coordination of
facilities at all.
---------------------------------------------------------------------------
\220\ Atlantic City, 295 F.3d at 12 (quoting Duke Power Co. v.
Federal Power Comm'n, 401 F.2d 930, 943 (D.C. Cir. 1968)).
---------------------------------------------------------------------------
154. Some petitioners maintain that Atlantic City demonstrates that
the Commission cannot impose planning requirements because the ISO
agreement at issue in that case encompassed transmission planning.
However, the fact that section 202(a) has applicability to some aspects
of an agreement does not mean that it has applicability to all aspects.
The claim to the contrary is based on the idea that every kind of
transmission planning is inseparable from the interconnection and
coordination of facilities, a claim that we reject. In addition, it is
clear from the context in which the court raised section 202(a) in
Atlantic City that it was not making any statements that are relevant
to transmission planning.
155. As noted above, the issue before the Atlantic City court was
whether the transfer of control over jurisdictional facilities that
occurred when a public utility entered or left an ISO was a
jurisdictional transfer for purposes of section 203 of the FPA. For
purposes of section 202(a), such a transfer constitutes a decision
either to
[[Page 32211]]
coordinate facilities through the ISO or to withdraw from such a
coordination arrangement, i.e., to turn operational authority over to
an ISO or to reclaim that authority from the ISO. Neither joint nor
coordinated new transmission planning involves any transfer of control
over any facilities, which makes clear that the court in Atlantic City
was not addressing issues pertinent to transmission planning. We thus
disagree with Southern Companies that the transmission planning
requirements of Order No. 1000 constitute the functional equivalent of
a coordination agreement that the court in Atlantic City found must be
voluntary.
156. We also disagree with PPL Companies that the lack of a mandate
on regional transmission planning in the Energy Policy Act of 2005 and
the fact that Congress made no changes to section 202(a) has any
significance for Order No. 1000. Section 202(a) does not mention
transmission planning. With respect to the Energy Policy Act of 2005,
which does not address regional transmission planning, we note that the
Supreme Court has observed that ``[t]he search for significance in the
silence of Congress is too often the pursuit of a mirage.'' \221\
---------------------------------------------------------------------------
\221\ Sampson v. Murray, 415 U.S. 61, 78 (1974) (quoting
Scripps-Howard Radio v. F.C.C., 316 U.S. 4, 11 (1942)).
---------------------------------------------------------------------------
157. Sacramento Municipal Utility District maintains that the
Commission's work with regional reliability councils in the decades
following the Northeast blackout of 1965 contradicts its interpretation
of section 202(a). To demonstrate this point, Sacramento Municipal
Utility District quotes a long passage from a 1993 proposed rule
dealing with information to be filed by transmitting utilities
providing information on potentially available transmission capacity
and known constraints.\222\ The passage in question includes a number
of statements that point out the importance of planning for the
development of coordinated systems. However, this passage does not
mention section 202(a) or the Commission's jurisdiction, and nothing in
the document from which it is drawn states anything, either explicitly
or implicitly, that allows one to conclude that transmission planning
either is or is not something that can be subject to Commission
requirements.
---------------------------------------------------------------------------
\222\ New Reporting Requirement Under the Federal Power Act and
Changes to Form No. FERC-714, FERC Stats. & Regs, Proposed
Regulations ] 32,685 at 32,688 (1993).
---------------------------------------------------------------------------
158. Finally, the same conclusion applies to the Commission policy
statements on data collection that petitioners cite. None of these
policy statements includes any analysis of the scope of section 202(a).
They do mention the importance of planning for achieving the goals of
section 202(a), but such statements do not speak to what the Commission
can require with respect to planning. Indeed, since they require
reporting of information relevant to planning, one can just as easily
infer that they pertain to matters where the Commission can establish
requirements.
c. Role of FPA Section 217(b)(4)
i. Requests for Rehearing and Clarification
159. Some petitioners contend that the transmission planning
reforms in Order No. 1000 ignore or run counter to the requirements of
FPA section 217(b)(4).\223\ Similarly, several petitioners raise
concerns that Order No. 1000's requirement that public utility
transmission providers, in consultation with stakeholders, consider
transmission needs driven by Public Policy Requirements is prohibited
by section 217(b)(4).\224\ Finally, some petitioners argue that the
Commission erred in not finding that section 217(b)(4) is a Public
Policy Requirement for purposes of Order No. 1000.\225\
---------------------------------------------------------------------------
\223\ See, e.g., PPL Companies; Southern Companies; Ad Hoc
Coalition of Southeastern Utilities; and North Carolina Agencies. Ad
Hoc Coalition of Southeastern Utilities and Southern Companies argue
that Congress added section 217 in response to the Commission's
Standard Market Design (SMD) proposal in Docket No. RM01-12-000.
They assert that many considered this proposal as an intrusion on
utilities' ability plan to meet their native load.
\224\ See, e.g., Large Public Power Council; Southern Companies;
Ad Hoc Coalition of Southeastern Utilities.
\225\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
APPA; Large Public Power Council; National Rural Electric Coops; and
Transmission Access Policy Study Group.
---------------------------------------------------------------------------
160. With respect to whether Order No. 1000's transmission planning
reforms are inconsistent with section 217(b)(4), PPL Companies argue
that Order No. 1000 undermines the intent of section 217 by stating
that all planning improvements will assist load-serving entities.
161. Transmission Dependent Utility Systems ask the Commission to
clarify that regional and interregional transmission planning processes
will abide by section 217(b)(4) by optimizing solutions for
transmission to allow long-term firm access to economically-priced
long-term energy supplies by all load-serving entities to best satisfy
their service obligations. Transmission Dependent Utility Systems
therefore seek clarification or rehearing that coordination of
reliability and economic planning includes identifying optimal
solutions to congestion, to ensure that load-serving entities'
reasonable needs are met under FPA section 217(b)(4). They argue that
once a transmission customer identifies an interregional transmission
need, the interregional coordination process should consider this even
if no developer has proposed an interregional solution and the public
utility transmission providers themselves have not identified a
potential interregional solution.
162. APPA and National Rural Electric Coops argue that Order No.
1000 incorrectly concludes that section 217(b)(4) does not provide a
preference to load-serving entities, explaining that in Order No. 681,
the Commission stated that section 217(b)(4) provided such a
preference.\226\ Meanwhile, Coalition for Fair Transmission Policy
states that, rather than seeking a preference, entities are requesting
a reasonable safeguard against planning process results that breach an
unambiguous statutory prescription. It adds that Order No. 1000's
dismissal of requests for section 217(b)(4) protection in the regional
transmission process is insufficient in light of Congress' directive to
enable load-serving entities to fully implement their resource
decisions made under state authority.
---------------------------------------------------------------------------
\226\ APPA at 10-11 (citing Long-Term Firm Transmission Rights
in Organized Electricity Markets, Order No. 681, FERC Stats. & Regs.
] 31,226, at P 319, 320 (2006) (stating that ``a broader preference
for load-serving entities in general vis-[agrave]-vis non-load-
serving entities is fully supported by the statute'' and that ``we
believe section 217 of the FPA provides a general `due' preference
for load-serving entities'')); National Rural Electric Coops at 9-10
(citing same).
---------------------------------------------------------------------------
163. NARUC argues that the planning process should require
integrated resource plans or enacted state energy policies to be
properly incorporated in the regional and interregional plans. NARUC
states that while Order No. 1000 purports to respect integrated
resource planning, it denies requests to have the planning process
follow the requirement in FPA section 217(b)(4) for bottom-up
transmission planning based on the needs of load-serving entities. It
contends that this leaves the process open to potential top-down
planning that might abrogate state integrated resource plans or other
electricity policies enacted by state legislatures or regulators.
Finally, NARUC seeks clarification that the Commission does not intend
to leverage regional and interregional transmission plans that emerge
from Order No. 1000 or the forthcoming compliance processes to infringe
upon state siting authority or exceed the Commission's backstop siting
authority under FPA section 216.
[[Page 32212]]
164. Other petitioners raise concerns about the relationship
between section 217(b)(4) and Order No. 1000's requirement that public
utility transmission providers consider transmission needs driven by
Public Policy Requirements. Large Public Power Council argues that the
requirement that public utility transmission providers consider
transmission needs driven by Public Policy Requirements runs counter to
FPA section 217(b)(4). It argues that imposing such a requirement would
result in reconsideration by regional planners of the same matters that
resulted in the transmission demand projections by load-serving
entities, and is likely to lead to skewed decision-making, reflecting
political value judgments and stakeholder business plans. Southern
Companies also assert that these requirements violate section 217(b)(4)
by hampering their ability to expand the transmission system to meet
the needs of their native load by making the transmission planning
process more bureaucratic and inefficient.
165. Several petitioners assert that the Commission erred in not
stating specifically that FPA section 217(b)(4) is a Public Policy
Requirement that must be considered in the transmission planning
process.\227\ APPA states that this provision is a specific legal
directive regarding transmission planning enacted by Congress and
imposed on the Commission. Transmission Access Policy Study Group
explains that the intent of section 217(b)(4) is to protect all load-
serving entities, including transmission dependent utilities, and
therefore, failure to include it as a public policy that must be
considered in planning sends the message that planning to meet the
reasonable needs of transmission dependent load-serving entities is
optional in the planning process. Transmission Access Policy Study
Group asserts that treating such entities as simply stakeholders whose
needs may or may not be considered in the planning process violates
section 217(b)(4)'s directive to the Commission to help meet load-
serving entities' needs. Ad Hoc Coalition of Southeastern Utilities
states that section 217, as the only passage in the FPA that explicitly
addresses planning, imposes on the Commission an obligation of a higher
order than furthering other public policies not mentioned in the
Commission's organic statute. Ad Hoc Coalition of Southeastern
Utilities contends that Order No. 1000 fails to facilitate planning to
meet native load because it compels load-serving entities to
participate in planning processes in which their obligations to serve
native load are considered as just one among many public policies goals
that may be advanced by stakeholders. Large Public Power Council
agrees.
---------------------------------------------------------------------------
\227\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
APPA; Large Public Power Council; National Rural Electric Coops; and
Transmission Access Policy Study Group.
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166. Other petitioners argue that the Commission's nonincumbent
reforms violate section 217(b)(4) by making it more difficult for them
to meet their obligations to serve native load.\228\ Southern Companies
assert that not only does the Commission lack authority to impose Order
No. 1000's nonincumbent transmission developer requirements, but, to
the extent it makes it more difficult for Southern Companies to expand
their transmission system to meet their native load service
obligations, those requirements are prohibited by section 217(b)(4).
---------------------------------------------------------------------------
\228\ See, e.g., Baltimore Gas & Electric; and Southern
Companies.
---------------------------------------------------------------------------
167. As for the regional planning process, MISO Transmission Owners
Group 2 argues that eliminating the federal rights of first refusal
will discourage robust participation in regional transmission planning.
It asserts that eliminating the federal right of first refusal provides
an incentive for incumbent public utilities with state-imposed retail
service obligations that have local transmission planning processes to
rely on their local process rather than the regional process to expand
their transmission systems to serve their customers and comply with
state mandates. It argues the same is true for incumbent public utility
transmission providers that are NERC-registered entities that must
construct transmission facilities to satisfy reliability standards or
avoid NERC penalties. According to MISO Transmission Owners Group 2,
this will result in the type of divided, inefficient, and potentially
duplicative transmission expansion process that Order No. 1000 purports
to discourage, and will create an unreasonable incentive for utilities
with local planning processes to favor local projects when a regional
solution is warranted.
ii. Commission Determination
168. We deny rehearing. We continue to find that the transmission
planning reforms required by Order No. 1000 are consistent with the
Commission's obligations under FPA section 217(b)(4). Section 217(b)(4)
directs the Commission 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.\229\
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\229\ 16 U.S.C. 824q(b)(4) (2006).
We believe that the regional transmission planning reforms required
by Order No. 1000 are consistent with this mandate because they will
enhance the transmission planning process for all interested entities,
including load-serving entities. We expect that load-serving entities
and their customers, like other interested parties, will benefit from a
regional planning process that identifies transmission solutions that
are more efficient or cost-effective than what may be identified in the
local transmission plans of individual public utility transmission
providers. For example, we expect that the planning process required by
Order No. 1000 will help identify efficient or cost-effective
transmission projects that address the transmission needs of load-
serving entities and their customers, whether they are driven by
reliability, economics, or public policy requirements.
169. The Commission's discussion of the relationship between
section 217(b)(4) and the transmission planning reforms undertaken in
Order Nos. 890 and 890-A further demonstrate that the Order No. 1000
regional transmission planning reforms are consistent with, and not
prohibited by, section 217(b)(4).\230\ In Order No. 890-A, the
Commission explained that ``[t]ransmission planning activities are
within our jurisdiction and, therefore, we have a duty under FPA
section 206 to remedy undue discrimination in this area and a further
obligation under FPA section 217 to act in a way that facilitates the
planning and expansion of facilities to meet the reasonable needs of
LSEs [load-serving entities].'' \231\ We believe that the discussions
in Order Nos. 890 and 890-A apply with equal force here.\232\ Contrary
to some
[[Page 32213]]
petitioners' arguments, section 217(b)(4) does not limit or prohibit
the transmission planning reforms required by Order No. 1000; rather,
it directs the Commission to take action to facilitate the planning and
expansion of transmission facilities to meet the reasonable needs of
load-serving entities. While each transmission planning region may
conclude that different approaches are best suited to accommodate those
needs, we find that the framework we set forth in Order No. 1000 will
assist in accomplishing the requirements of section 217(b)(4).
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\230\ In Order No. 890, the Commission explained that section
217(b)(4) supported the transmission planning reforms therein. See
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 436. Order No.
1000's regional transmission planning reforms require public utility
transmission providers to, among other things, adopt Order No. 890
transmission planning principles as part of their regional
transmission planning process. Order No. 1000, FERC Stats. & Regs. ]
31,323 at PP 150-52.
\231\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 172.
\232\ The Commission discusses its jurisdiction with respect to
transmission planning in this rule. See Order No. 1000, Stats. &
Regs. ] 31,323 at section III.A.2; see also discussion supra at
section III.A.1.
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170. As the Commission explained in Order No. 1000, the reforms
adopted therein build on the requirements of Order No. 890 and further
facilitate open and transparent transmission planning to, a goal that
does not conflict with FPA section 217. Indeed, the Commission
explained that Order No. 1000 is consistent with section 217, because
it supports the development of needed transmission facilities that
benefit load-serving entities. The Commission pointed out that the fact
that the Order No. 1000 transmission planning reforms serve the
interests of other stakeholders as well does not place the Commission's
action in conflict with section 217.\233\ Nothing in Order No. 1000 is
intended to prevent or restrict a load-serving entity from fully
implementing resource decisions made under state authority. Rather, the
Commission's expectation is that Order No. 1000 will facilitate the
evaluation of potential transmission facilities needed to accommodate
such resource decisions.
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\233\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 108.
---------------------------------------------------------------------------
171. We find that assertions made by APPA and National Rural
Electric Coops that section 217(b)(4) establishes a preference for
load-serving entities are too broad. APPA and National Rural Electric
Coops state that Order No. 681, in which the Commission promulgated
regulations under section 217(b)(4) regarding long-term firm
transmission rights, expressly noted such a preference. However, Order
No. 681 made this point in the context of securing long-term firm
transmission rights supported by existing transmission capacity, which
was the subject of that rulemaking proceeding, but not in the broader
context of planning new transmission capacity. Specifically, Order No.
681 established a guideline that provided:
Load-serving entities must have priority over non-load-serving
entities in the allocation of long-term firm transmission rights
that are supported by existing transmission capacity. The
transmission organization may propose reasonable limits on the
amount of existing transmission capacity used to support long-term
firm transmission rights.\234\
---------------------------------------------------------------------------
\234\ Order No. 681, FERC Stats. & Regs. ] 31,226 at P 325.
172. We do not find this statement inconsistent with the reforms in
Order No. 1000, which address the planning and cost allocation for new
transmission.\235\ In any event, as discussed above, we find that Order
No. 1000's transmission planning reforms will aid, not hinder, load-
serving entities in meeting their reasonable transmission needs. Thus,
nothing in Order No. 1000's transmission planning reforms conflicts
with the existing requirements of Order No. 681 regarding the
availability of long-term firm transmission rights in organized
electricity markets.
---------------------------------------------------------------------------
\235\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 65 (the
requirements of Order No. 1000 are ``intended to apply to new
transmission facilities, which are those transmission facilities
that are subject to evaluation, or reevaluation as the case may be,
within a public utility transmission provider's local or regional
transmission planning process after the effective date of the public
utility transmission provider's filing adopting the relevant
requirements'' in Order No. 1000).
---------------------------------------------------------------------------
173. In addition, by requiring that transmission needs driven by
Public Policy Requirements be considered in local and regional
transmission planning processes, our expectation is that such a
requirement will assist load-serving entities and others in better
meeting their transmission needs. For this same reason, we allow but do
not require that the coordination of reliability and economic
transmission planning include identifying optimal solutions to
congestion to ensure that load-serving entities' needs are met under
section 217(b)(4), as suggested by Transmission Dependent Utility
Systems.
174. We also disagree with Coalition for Fair Transmission Policy's
contention that Order No. 1000 may not allow load-serving entities to
implement their states' resource decisions. As discussed in the
following section, nothing in Order No. 1000 conflicts or interferes
with the states' integrated resource planning processes. Accordingly,
and for the reasons discussed above, we do not believe that Order No.
1000's requirements conflict with section 217, as some petitioners
maintain.
175. We also disagree with petitioners such as Large Public Power
Council that the consideration of transmission needs driven by Public
Policy Requirements runs counter to section 217(b)(4). First, as we
stated above, we find that Order No. 1000 will enhance, not impede,
meeting the needs of load-serving entities. We also believe that these
specific reforms may assist load-serving entities in meeting their
transmission needs, especially because many, if not all, of the Public
Policy Requirements will likely impose legal obligations on load-
serving entities. Therefore, we see nothing inconsistent between these
reforms and section 217(b)(4).
176. We affirm Order No. 1000's conclusion that we will not
prescribe any statutes and regulations as Public Policy Requirements
for purposes of Order No. 1000, including section 217(b)(4). We
explained that we would not pick and choose any federal or state law or
regulation as a Public Policy Requirement. Rather, it will be up to
public utility transmission providers, in consultation with
stakeholders, to develop a process that considers transmission needs
driven by Public Policy Requirements.
177. Further, we disagree with NARUC's assertion that, while Order
No. 1000 purports to support integrated resource planning, its
requirements are contrary to section 217(b)(4)'s requirement of a
bottom-up transmission planning process. First, by its terms, section
217(b)(4) does not require a bottom-up transmission planning process,
as NARUC claims. Rather, section 217(b)(4) requires the Commission to
exercise its authority to facilitate the planning and expansion of
transmission facilities to assist load-serving entities in meeting
their reasonable transmission needs and to secure long-term firm
transmission rights. It does not speak at all to how transmission
planning processes should be established. Second, regardless of whether
a regional transmission planning process is termed bottom-up or top-
down, we emphasize that nothing in any of Order No. 1000's requirements
interferes with states' authority to require integrated resource
planning or utilities' obligation to comply with such requirements, as
discussed herein.
178. We disagree with petitioners that argue that Order No. 1000's
nonincumbent transmission developer reforms are prohibited by, or
inconsistent with, section 217(b)(4).\236\ Contrary to Southern
Companies' contention, these reforms do not make it more difficult for
incumbent
[[Page 32214]]
transmission providers to serve native load. Indeed, we believe just
the opposite to be the case, for as found in Order No. 1000, the
Commission believes that greater participation by transmission
developers in the transmission planning process may lower the cost of
new transmission facilities, enabling more efficient or cost-effective
deliveries by load-serving entities and increased access to
resources.\237\ Accordingly, we expect that incumbent transmission
providers will ultimately benefit from these reforms because they
support the identification of more efficient or cost-effective
transmission solutions, thereby improving their ability to meet the
reasonable needs of load-serving entities to satisfy their load serving
obligations.
---------------------------------------------------------------------------
\236\ Other issues regarding Order No. 1000's nonincumbent
reforms are discussed in section III.B, infra.
\237\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 291.
---------------------------------------------------------------------------
179. We also disagree with MISO Transmission Owners Group 2 that
these reforms will necessarily encourage incumbent transmission
providers to favor local transmission planning and local transmission
projects over regional transmission planning and regional transmission
solutions. While nothing in Order No. 1000 prohibits an incumbent
transmission provider from proposing a local transmission solution to
satisfy a reliability need or service obligation, we are not persuaded
that allowing incumbent transmission providers to choose among these
options will lead to less robust regional transmission planning. There
are a variety of factors that incumbent transmission providers must
consider when deciding whether to propose a local transmission facility
instead of relying on a transmission facility selected in the regional
transmission plan for purposes of cost allocation. We also believe, as
discussed in Order No. 1000 and herein, that the nonincumbent
transmission developer reforms will lead to more competition among
developers, which in turn will lead to the identification of more
efficient and cost-effective transmission facilities. Accordingly, we
are not persuaded that the elimination of a federal right of first
refusal will necessarily will lead to inefficient or duplicative
transmission planning processes.
d. Effect on Integrated Resource Planning and State Authority Over
Transmission Siting, Permitting, and Construction
i. Requests for Rehearing and Clarification
180. Several state regulators and others claim that Order No. 1000
improperly intrudes on authority over matters traditionally reserved to
the states, such as integrated resource planning and the construction
and siting of transmission facilities.\238\ North Carolina Agencies and
Southern Companies argue that, in contrast to the extensive
jurisdiction over transmission planning historically exercised by the
states, the FPA grants the Commission little, if any, authority in this
area. Florida PSC and Georgia PSC also state that FPA section 201(a)
limits the Commission's authority to regulate interstate transmission
and wholesale power sales to only those matters that are not subject to
state regulation, and that the Commission provided no evidence of
discrimination to support preempting state authority over transmission
planning.\239\
---------------------------------------------------------------------------
\238\ See, e.g., NARUC; Florida PSC; Alabama PSC; Georgia PSC;
Kentucky PSC; North Carolina Agencies; Large Public Power Council;
Ad Hoc Coalition of Southeastern Utilities; Southern Companies; and
Coalition for Fair Transmission Policy.
\239\ In relevant part, FPA section 201(a) provides that federal
regulation over the interstate transmission and wholesale sale of
electric energy only ``extend[s] to those matters which are not
subject to regulation by the States.'' 16 U.S.C. 824(a).
---------------------------------------------------------------------------
181. Several petitioners argue that Order No. 1000's planning
reforms will disrupt, and potentially preempt, a state's integrated
resource planning.\240\ For example, Georgia PSC states that if
regional and interregional transmission planning and coordination
requirements result in a previously unidentified transmission project
being included in a Commission-regulated process, that result will
disrupt and skew existing state-regulated transmission and integrated
resource planning processes, and will undermine its ability to
effectively regulate bundled retail service.
---------------------------------------------------------------------------
\240\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Alabama PSC; Georgia PSC; and Southern Companies.
---------------------------------------------------------------------------
182. Similarly, Alabama PSC contends that least-cost, reliable
solutions identified for its ratepayers through integrated resource
planning will be subordinated to the solutions identified for the
region under the Commission-administered process, with no assurance
that this regional solution will hold local ratepayers harmless. NV
Energy also asserts that inclusion of alternative transmission and non-
transmission proposals in the regional or interregional plan could
trump a transmission facility in a local plan, rendering the state's
integrated resource planning process meaningless.\241\ NV Energy
contends that this could lead to ``forum shopping,'' particularly in
the case of considering Public Policy Requirements, and that states may
be reluctant to approve the siting of facilities that are the result of
a process of exclusion or substitution of facilities that they deem
necessary and appropriate in their integrated resource planning
processes.\242\ NV Energy thus seeks clarification that for any
facilities included in a ``local'' plan, those facilities are not
subject to ``de novo'' review at the regional or interregional level
unless the transmission provider voluntarily subjects the facilities to
an alternative review or the facilities are proposed by the
transmission provider for regional cost allocation and they are so
chosen.\243\ Coalition for Fair Transmission Policy seeks clarification
that regional transmission planning processes and interregional
transmission coordination do not have the ability or authority to
affect or change resource decisions made by entities with
responsibility to meet public policy requirements and the transmission
needs that they have identified associated with those resource
decisions, except with the voluntary agreement of those responsible
entities.
---------------------------------------------------------------------------
\241\ See also Coalition for Fair Transmission Policy at 27
(citing Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 154).
\242\ NV Energy at 7-8.
\243\ NV Energy at 9.
---------------------------------------------------------------------------
183. Kentucky PSC argues that Order No. 1000 infringes on state
jurisdiction over integrated resource planning through its failure to
require transmission planning and cost allocation processes to allow
for the unique role of state regulators in determining which projects
will be constructed and who will pay for them. Kentucky PSC notes that
in Kentucky, only the state legislature can decide if in-state
utilities must use certain proportions of various types of energy
resources. It maintains that a decision to develop a transmission
facility might de facto make decisions about types and locations of
generation resources. Kentucky PSC also argues that Order No. 1000
erred regarding the consideration of non-transmission alternatives,
asserting that such matters are within the exclusive province of state-
regulated integrated resource planning.\244\
---------------------------------------------------------------------------
\244\ See also Alabama PSC at 3-4.
---------------------------------------------------------------------------
184. Some petitioners, such as Ad Hoc Coalition of Southeastern
Utilities, argue that regional cost allocation determinations under
Order No. 1000 will have a preemptive effect on decisions made at the
state level. Ad Hoc Coalition of Southeastern Utilities asserts that if
ratepayers must pay for a nonincumbent's transmission line
[[Page 32215]]
chosen in the regional planning process, it would be difficult for the
incumbent owner to pursue an alternate project, resulting in the
indirect regulation of actual transmission planning decisions,
including siting, construction, permitting, and resource planning
decisions. It states that the Commission is prohibited from doing
indirectly what it is prohibited from doing directly.\245\ Ad Hoc
Coalition of Southeastern Utilities also states that if the Commission
states on rehearing that it does not regulate substantive planning,
then it should explain the ramifications of a transmission provider not
implementing the regional transmission plan. Southern Companies raise
the same argument, emphasizing that the decision to fund transmission
projects determines the projects to be pursued.
---------------------------------------------------------------------------
\245\ Ad Hoc Coalition of Southeastern Utilities at 43-44
(citing generally Towns of Concord, Norwood, and Wellesley, Mass. v.
FERC, 955 F.2d 67, 71 n.2 (D.C. Cir. 1992)).
---------------------------------------------------------------------------
185. Ad Hoc Coalition of Southeastern Utilities assert that Order
No. 1000's regional and interregional processes will likely result in
more long distance transmission lines, which could prove to be
disruptive to a bottom-up integrated resource planning process due to
its significant impacts on bulk power flows.
ii. Commission Determination
186. As we stated in Order No. 1000, nothing therein is intended to
preempt or otherwise conflict with state authority over the siting,
permitting, and construction of transmission facilities or over
integrated resource planning and similar processes. Order No. 1000
explained that ``nothing in this Final Rule involves an exercise of
siting, permitting, and construction authority. The transmission
planning and cost allocation requirements of this Final Rule, like
those of Order No. 890, are associated with the processes used to
identify and evaluate transmission system needs and potential solutions
to those needs.'' Order No. 1000 concluded that ``[t]his in no way
involves an exercise of authority over those specific substantive
matters traditionally reserved to the states, including integrated
resource planning, or authority over such transmission facilities.''
\246\
---------------------------------------------------------------------------
\246\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 107.
---------------------------------------------------------------------------
187. We affirm that conclusion here. In so finding, we recognize,
as we did in Order No. 1000, that the states have a significant
jurisdictional role in the siting, permitting, and construction of
transmission facilities, and that many states require public utility
transmission providers to undertake and implement integrated resource
plans. However, as we explain below, the Commission may undertake Order
No. 1000's reforms without intruding on state jurisdiction.
188. At the outset, it is important to recognize that Order No.
1000's transmission planning reforms are concerned with process; these
reforms are not intended to dictate substantive outcomes, such as what
transmission facilities will be built and where.\247\ We recognize that
such decisions are normally made at the state level.\248\ Rather, Order
No. 1000's transmission planning reforms are intended to ensure that
there is an open and transparent regional transmission planning process
that produces a regional transmission plan. If public utility
transmission providers' regional transmission processes satisfy these
requirements, then they will be in compliance with Order No. 1000's
regional transmission planning requirements. Thus, contrary to
arguments raised by some state regulators and others, Order No. 1000's
transmission planning reforms respect the jurisdictional authority of
the states regarding the siting, permitting, and construction of
transmission facilities.
---------------------------------------------------------------------------
\247\ Id. P 113 (``This Final Rule is focused on ensuring that
there is a fair regional transmission planning process, not
substantive outcomes of that process.'') (emphasis in original).
\248\ The Commission has limited backstop transmission siting
authority under section 216 of the FPA. However, that limited
authority is not at issue in this proceeding. In response to NARUC,
we clarify that nothing in Order No. 1000 is intended to leverage
the regional transmission planning or interregional transmission
coordination reforms to exceed the Commission's section 216 backstop
authority.
---------------------------------------------------------------------------
189. In support of their contention that Order No. 1000 infringes
on state authority, North Carolina Agencies claim that the SMD White
Paper expressly acknowledged that the planning aspects of the SMD
proposal infringed on state jurisdiction over transmission planning.
The content of the SMD White Paper is not relevant to this
proceeding.\249\ There is nothing in Order No. 1000 that preempts state
authority regarding transmission planning, including authority over the
siting, permitting, and construction of transmission facilities.
---------------------------------------------------------------------------
\249\ In addition, what North Carolina Agencies actually cite to
is a brief summary of arguments that the SMD White Paper proceeds to
address.
---------------------------------------------------------------------------
190. By requiring public utility transmission providers to
participate in an open and transparent regional transmission planning
process that leads to the development of a regional transmission plan,
the Commission has facilitated the identification and evaluation of
transmission solutions that may be more efficient or cost-effective
than those identified and evaluated in the local transmission plans of
individual public utility transmission providers.\250\ This will
provide more information and more options for consideration by public
utility transmission providers and state regulators and, therefore, can
hardly be seen as detrimental to state-sanctioned integrated resource
planning. Of course, we recognize that a regional transmission planning
process may not identify any such transmission facilities and, even
where more efficient or cost-effective transmission solutions are
identified and selected in the regional transmission plan for purposes
of cost allocation, such solutions may not ultimately be constructed
should the developer not secure the necessary approvals from the
relevant state regulators. Consistent with this, we also clarify that
we do not require that the transmission facilities in a public utility
transmission provider's local transmission plan be subject to approval
at the regional or interregional level, unless that public utility
transmission provider seeks to have any of those facilities selected in
the regional transmission plan for purposes of cost allocation.
---------------------------------------------------------------------------
\250\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 146
(``We determine that such [regional] transmission planning will
expand opportunities for more efficient and cost-effective
transmission solutions for public utility transmission providers and
stakeholders. This will, in turn, help ensure that the rates, terms
and conditions of Commission-jurisdictional services are just and
reasonable and not unduly discriminatory or preferential.'').
---------------------------------------------------------------------------
191. Accordingly, in response to Ad Hoc Coalition of Southeastern
Utilities, we disagree that we are effectively making decisions about
which transmission facilities will be sited and constructed, that we
are effectively preempting state decisions in that regard, or that we
are doing anything indirectly that we cannot do directly. As discussed
above, we conclude that we possess ample legal authority under the FPA
to implement Order No. 1000's transmission planning reforms. As we also
explain immediately above, nothing in Order No. 1000 explicitly or
implicitly requires that any transmission facilities be sited,
permitted, or constructed. We do not see that decisions made in the
regional transmission planning process would interfere with these
state-jurisdictional processes. Further, in response to Ad Hoc
Coalition of Southeastern Utilities' question regarding the
implications of not implementing the regional transmission plan, we
reiterate that Order No. 1000 requires a regional transmission plan be
developed
[[Page 32216]]
pursuant to a Commission-approved process, the Commission is not
requiring that such a plan be filed for Commission approval or be
implemented. Rather, as was made clear in Order No. 1000, the
designation of a transmission project as a ``transmission facility in a
regional transmission plan'' or a ``transmission facility selected in a
regional transmission plan for purposes of cost allocation'' only
establishes how the developer may allocate the costs of such a facility
in Commission-approved rates if it is built.\251\ Order No. 1000,
however, does not require that such facilities be built, give any
entity permission to build a facility, or relieve a developer from
obtaining any necessary state regulatory approvals.\252\
---------------------------------------------------------------------------
\251\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 66.
\252\ Id.
---------------------------------------------------------------------------
192. We disagree with Ad Hoc Coalition of Southeastern Utilities
that the Order No. 1000 transmission planning reforms will be
disruptive to integrated resource planning due to the impact of long-
distance transmission lines on bulk power flows. Some public utility
transmission providers may be concerned that Order No. 1000, because it
provides for transmission facilities being selected in the regional
transmission plan for purposes of cost allocation, establishes an
incentive for other entities to propose larger regional transmission
projects that may disrupt or interfere with state-level integrated
resource planning efforts. Even if such an incentive were present, we
note that unless a long-distance transmission solution identified in
the regional transmission planning process is a more efficient or cost-
effective solution than what is identified in the local transmission
plans of individual public utility transmission providers, it would not
be selected in the regional transmission plan for purposes of cost
allocation.
193. We also disagree with Kentucky PSC that Order No. 1000's
direction that public utility transmission providers, in consultation
with stakeholders, consider non-transmission alternatives is outside of
the Commission's jurisdiction. We do not require anything more than
considering non-transmission alternatives as compared to potential
transmission solutions, similar to what was developed in Order No. 890,
Order No. 890-A, and resulting compliance filings.\253\ The evaluation
of non-transmission alternatives as part of the regional transmission
planning process does not convert that process into integrated resource
planning. Order No. 1000 requires that there be a regional transmission
plan that includes transmission facilities selected in the regional
transmission plan for purposes of cost allocation.\254\
---------------------------------------------------------------------------
\253\ Id. P 155 n. 149 (citing to Commission orders addressing
Order No. 890 compliance filings that require the evaluation of
transmission, generation, and demand response on a comparable basis
in the public utility transmission providers' transmission planning
process).
\254\ It may be the case that non-transmission alternatives may
result in a regional transmission planning process deciding that a
proposed transmission facility is not a more efficient or cost-
effective solution and, accordingly, that facility may not be
selected in the regional transmission plan for purposes of cost
allocation. Such a decision by the regional transmission planning
process does not interfere with integrated resource planning.
---------------------------------------------------------------------------
194. In further response to those petitioners who claim that Order
No. 1000 will disrupt state integrated resource planning, we note that
the identification of more efficient or cost-effective transmission
facilities through a regional transmission planning process should not
disrupt state integrated resource planning. In any event, we find that
such concerns are speculative and, should they arise, it will be in the
context of a specific factual circumstance. If any issues arise in such
a context, affected parties are free to raise these issues before the
Commission in the appropriate proceeding.
e. Legal Authority Related to Consideration of Transmission Needs
Driven by Public Policy Requirements
i. Requests for Rehearing and Clarification
195. Several petitioners express concerns about the Commission's
legal authority to require public utility transmission providers to
consider transmission needs driven by Public Policy Requirements,
arguing that the Commission failed to meet its burden, and that the
requirements raise federalism issues and go beyond the Commission's
statutory authority.
196. PPL Companies assert that while the Commission may permit
public utility transmission providers to consider Public Policy
Requirements on a voluntary basis, it erred in mandating such
consideration without first finding that existing rates are unjust,
unreasonable, or unduly discriminatory. They assert that the Commission
has not met its FPA section 206 burden to explain why consideration of
transmission needs driven by Public Policy Requirements will remedy
unjust and unreasonable rates or undue discrimination. They argue that
having to plan for and construct such public policy-driven transmission
projects could unduly burden utilities and their customers with
additional unjust and unreasonable costs that would not likely have
been incurred but for the Public Policy Requirements.
197. ELCON, AF&PA, and the Associated Industrial Groups argue that,
by allowing one state's public policy agenda to adversely affect
electricity prices in other states that do not share that agenda, Order
No. 1000 raises significant federalism issues. They claim that this
obscures political accountability because ISOs/RTOs will have
discretion to determine which public policy to follow, and that this
approach permits the federal government to burden state taxpayers with
onerous, unpopular policies or force them to subsidize the public
policy decisions of neighboring states without facing the political
accountability that federalism demands. They state that the federal
government cannot commandeer state legislatures and state executives in
the name of federal interests.\255\ Alabama PSC raises similar
concerns.
---------------------------------------------------------------------------
\255\ ELCON, AF&PA, and the Associated Industrial Groups at 10
(quoting New York v. United States, 505 U.S. 144 (1992)); see also
PSEG Companies at 45.
---------------------------------------------------------------------------
198. PPL Companies argue that the FPA does not permit utilities, or
the Commission, to pursue public policy objectives broadly, and such a
departure from the FPA requires an amendment to the statute itself and
cannot be undertaken by the Commission via rulemaking.\256\ PSEG
Companies contend that the Commission acted outside the scope of its
authority, arguing that there is no statute authorizing the Commission
to require that transmission providers build public policy projects or
even consider Public Policy Requirements. They also argue that, in the
absence of specific findings of undue discrimination in a particular
region, the Commission should leave it to transmission providers to
determine if there is a problem that needs to be
[[Page 32217]]
addressed through revisions to the planning process and, if necessary,
develop solutions that do not get ahead of states' efforts to implement
their own public policies. They argue that the requirement that
transmission providers prognosticate public policy outcomes and plan
the system based on those predictions is not proportional to the
alleged problem and is thus impermissible.\257\ They also allege that
the Commission did not explain how and why the existing construct
focusing on the planning of reliability and economic projects has not
served the needs of load-serving entities.
---------------------------------------------------------------------------
\256\ PPL Companies at 10-11 (citing NAACP v. FPC, 425 U.S. 662,
669-70 (1976) (explaining why Congress' direction for the Commission
to act in furtherance of the public interest under the FPA ``is not
a broad license to promote the general welfare''); Atlantic City,
295 F.3d at 8 (explaining that, as a federal agency, the Commission
is a ``creature of statute,'' having ``no constitutional or common
law existence or authority, but only those authorities conferred
upon it by Congress.'' (quoting Michigan v. EPA, 268 F.3d 1075, 1081
(D.C. Cir. 2001) (emphasis added)); Louisiana Pub. Serv. Comm'n v.
FCC, 476 U.S. 355, 374 (1986) (recognizing that ``an agency
literally has no power to act * * * unless and until Congress
confers power upon it''); American Petroleum Inst. v. EPA, 52 F.3d
1113, 1119-20 (D.C. Cir. 1995) (stating that in the absence of
statutory authorization for its act, an agency's ``action is plainly
contrary to law and cannot stand''); Ethyl Corp. v. EPA, 51 F.3d
1053, 1060 (D.C. Cir. 1995)).
\257\ PSEG Companies at 47 (citing California Indep. Sys.
Operator Corp. v. FERC, 372 F.3d 395 (D.C. Cir. 2004) (CAISO v.
FERC)).
---------------------------------------------------------------------------
199. Ad Hoc Coalition of Southeastern Utilities and Large Public
Power Council assert that the Commission exceeded its authority under
the FPA, as delineated in NAACP v. FPC, by directing transmission
providers to consider Public Policy Requirements in the planning
process. Ad Hoc Coalition of Southeastern Utilities argues that
although Congress directs the Commission to act in furtherance of the
public interest, it is not a broad license to promote the general
public welfare.\258\ Instead, it asserts that public interest must be
understood in the context of the broad goals of the FPA itself--to
ensure the provision of reliable transmission service on a non-
discriminatory basis, at just and reasonable rates. Thus, it argues
that the Commission lacks authority to consider broad concepts of
public policy in implementing its duties under the FPA, and may not
promulgate rules advancing environmental goals. It notes that the
Commission has recognized that its NEPA-related responsibilities to
consider environmental policy objectives do not extend to section 205
rate filings.\259\
---------------------------------------------------------------------------
\258\ Ad Hoc Coalition of Southeastern Utilities at 53 (citing
NAACP v. FPC, 425 U.S. 662, 665 (1976)).
\259\ Ad Hoc Coalition of Southeastern Utilities at 54 (citing,
e.g., Monongahela Power Co., 39 FERC ] 61,350, at 62,097, reh'g
denied, 40 FERC ] 61,256 (1987) (Monongahela); 18 CFR 380.4(a)(15)
(2011)). See also Large Public Power Council.
---------------------------------------------------------------------------
200. Southern Companies argue that the Commission lacks authority
under the FPA to enforce and implement state and federal policies,
which violates Comcast v. FCC.\260\ They add that Order No. 1000's
regulation of specific evaluative practices violates precedent
establishing that the Commission cannot regulate a matter just because
the Commission is able to articulate some relationship between that
matter and the Commission-regulated, wholesale electric and
transmission services.\261\ They assert that the Commission's reading
of the holding of CAISO v. FERC, which it interprets as giving it
authority to control anything that affects the need for interstate
transmission facilities, is too broad since all aspects of our modern,
electricity-consuming lives drive the need for interstate transmission
facilities.\262\
---------------------------------------------------------------------------
\260\ Southern Companies at 51 (citing Comcast Corp. v. FCC, 600
F.3d 642, 659 (D.C. Cir. 2010)).
\261\ Southern Companies at 51 (quoting State of Missouri v.
Southwestern Bell Tel. Co., 262 U.S. 276, 289 (1923) (stating that a
regulatory agency with general oversight and rate authority ``is not
the owner of the property of public utility companies, and is not
clothed with the general power of management incident to
ownership'') (Southwestern Bell)).
\262\ Southern Companies at 52 (citing CAISO v. FERC, 372 F.3d
395).
---------------------------------------------------------------------------
201. Southern Companies asserts that Public Policy Requirements are
merely components that drive load growth and resource decisions that
are the major aspects of integrated resource planning, which
demonstrates that addressing Public Policy Requirements is an issue for
state-regulated integrated resource planning. In addition, they state
that even though it already incorporates public policies into its
transmission planning process, Order No. 1000's Public Policy
Requirement appears to add nothing but costs and burdens by mandating
nothing more than compliance activities. Therefore, Southern Companies
argue that Order No. 1000's Public Policy Requirements are arbitrary
and capricious,\263\ and violate National Fuel.\264\
---------------------------------------------------------------------------
\263\ Southern Companies at 50 (citing Motor Vehicles Mfrs.
Ass'n of the U.S. v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29,
43 (1983)).
\264\ Southern Companies at 50 (citing National Fuel, 468 F.3d
at 844).
---------------------------------------------------------------------------
202. Bonneville Power seeks clarification that the Public Policy
Requirement reforms to its local planning process must be consistent
with its statutory authorities related to providing regional and
interregional transmission facilities.\265\ Bonneville Power states
that its statutory authorities for planning and building transmission
facilities are not constrained by the FPA's just and reasonable and not
unduly discriminatory standard. It also explains that while its
Administrator may consider policies at play under those standards, he
must also factor in other considerations.\266\ If the Commission
declines to grant this clarification, Bonneville Power seeks rehearing,
arguing that the Commission failed to provide reasonable notice of the
requirement and failed to consider Bonneville Power's comments and
statutory requirements.
---------------------------------------------------------------------------
\265\ Bonneville Power at 21. Bonneville Power states that it is
only requesting clarification with respect to its local planning
process rather than with respect to the regional planning process in
which it voluntarily participates. Bonneville Power at 22.
\266\ Bonneville Power states that Congress recognized this in
section 1232 of EPAct 2005, which provides that if Bonneville Power
enters into a contract, agreement, or arrangement for participation
in a transmission organization, then it must assure, among other
things, ``consistency with the statutory authorities, obligations,
and limitations of the federal utility.'' Bonneville Power at 22
(quoting 42 U.S.C. Sec. 16431(c)(1)(C)).
---------------------------------------------------------------------------
ii. Commission Determination
203. We deny rehearing. Many of the arguments raised on rehearing
simply repeat assertions made by commenters in response to the Proposed
Rule in this proceeding, namely, that the Commission is not permitted
to require public utility transmission providers to consider
transmission needs driven by public policy under the FPA or that the
direction to public utility transmission providers to consider
transmission needs driven by Public Policy Requirements is not a
practice affecting rates.
204. At the outset, it is important to emphasize exactly what these
reforms are intended to do and what they clearly are not intended to
do. As explained in Order No. 1000, in requiring the consideration of
transmission needs driven by Public Policy Requirements, the Commission
is not mandating fulfillment of those requirements or that public
utility transmission providers consider the Public Policy Requirements
themselves. We address this issue in more detail below,\267\ but we
clarify here the basic components of Order No. 1000's requirements in
this regard, as it appears there are misconceptions about precisely
what Order No. 1000 requires. To be clear, we are not requiring that
any federal or state laws or regulations themselves be considered as
part of the transmission planning process. That distinction is
critical, and we want to be clear that this is not what Order No. 1000
requires.\268\
---------------------------------------------------------------------------
\267\ See discussion infra at section III.A.2.
\268\ See discussion infra at section III.A.2.
---------------------------------------------------------------------------
205. Instead, the Commission is acknowledging that the requirements
in question are facts that may affect the need for transmission
services and these facts must be considered for that reason. Our intent
is that public utility transmission providers consider such
transmission needs just as they consider transmission needs driven by
reliability or economic concerns.\269\ We are not
[[Page 32218]]
requiring that public utility transmission providers do any more than
that. Such requirements may modify the need for and configuration of
prospective transmission facilities. Accordingly, the transmission
planning process and the resulting transmission plans would be
deficient if they do not provide an opportunity to consider
transmission needs driven by Public Policy Requirements.\270\ As a
result, in Order No. 1000 we acted pursuant to our section 206
authority to ensure that this deficiency is remedied in the OATTs of
public utility transmission providers.
---------------------------------------------------------------------------
\269\ We note that this is consistent with the approach taken in
Order No. 888, and reiterated in Order No. 890, that public utility
transmission providers are obligated to plan for the needs of their
transmission customers. See, e.g., Order No. 890, FERC Stats. &
Regs. ] 31,241 at PP 418-19.
\270\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 109.
---------------------------------------------------------------------------
206. We thus disagree with PSEG Companies that Order No. 1000's
requirements in this regard are impermissible because the remedy is
disproportionate to the identified problem. Again, we are requiring
only that there be a process in place for public utility transmission
providers, in consultation with stakeholders, to consider transmission
needs driven by Public Policy Requirements. We believe that these
reforms are necessary, because the record shows that there are, and
there will continue to be, federal and state laws and regulations that
will have a direct impact on transmission needs, just as reliability
and economic concerns have a direct impact on transmission needs. By
setting forth this process, our expectation is that public utility
transmission providers, in consultation with stakeholders, will
identify more efficient or cost-effective solutions to such
transmission needs than may be the case without these requirements.
207. Given the parameters described above, and discussed in more
detail below,\271\ we do not see how these reforms are comparable to
the matters at issue in NAACP v. FPC. As discussed in Order No. 1000,
the Court in NAACP v. FPC found that the Commission did not have the
power under the FPA or the Natural Gas Act (NGA) to construe its
obligation to promote the public interest under those statutes as
creating a ``broad license to promote general public welfare.'' \272\
The Court also found that the Commission's duty to promote the public
interest under the FPA and NGA ``is not a directive to the Commission
to seek to eradicate discrimination,'' and it thus did not authorize
the Commission to promulgate rules prohibiting the companies it
regulates from engaging in discriminatory employment practices merely
because the statutes pertain to matters affected with a public
interest.\273\ We reiterate here that the consideration of transmission
needs driven by Public Policy Requirements ``cannot be construed as
pursuing broad general welfare goals that extend beyond matters subject
to our authority under the FPA.'' \274\
---------------------------------------------------------------------------
\271\ See discussion infra at section III.A.3.
\272\ NAACP v. FERC, 425 U.S. 662 at 668.
\273\ Id. at 670.
\274\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 111.
---------------------------------------------------------------------------
208. The planning necessary to consider transmission needs driven
by Public Policy Requirements is not different in substance from the
planning required to address reliability or economic needs. Such
planning requires an open and transparent process that provides
interested stakeholders with access to studies, models and data used to
make decisions. This transparency and coordination helps to ensure no
undue discrimination on the part of the public utility transmission
provider in planning for its own needs vis-[agrave]-vis the needs of
customers to which it is obligated to provide open access transmission
service. Thus, we disagree with petitioners that suggest that Order No.
1000's requirements in this regard are analogous to promoting broad
notions of public policy, as contemplated in NAACP v. FPC.
209. Similarly, we find that references to the Commission's order
in Monongahela are not relevant here. In that case, the Commission
explained that we ``have consistently recognized that [our] review of
electric rate filings is not subject to NEPA,'' \275\ and we then
rejected arguments by an environmental advocacy group that the
Commission curtail the operation of existing but unused capacity within
a transmission provider's system. We stated that ``[b]ecause the
Commission does not possess such curtailment authority by virtue of
section 201(b) of the FPA, it could not accomplish indirectly through
NEPA that which it is prohibited from doing directly under section
201(b) of the FPA.'' \276\ Nothing in Order No. 1000 contradicts these
statements. Similar to our discussion above that we are not promoting
broad notions of public policy, we emphasize that we are not advocating
for any particular environmental or other public policy and we are not
requiring electric rate filings under section 205 to be subjected to
NEPA. We are requiring only that transmission needs driven by Public
Policy Requirements be considered in transmission planning processes,
just as public utility transmission providers consider reliability- and
economic-based transmission needs.
---------------------------------------------------------------------------
\275\ Monongahela, 39 FERC ] 61,350 at 62,097
\276\ Id.
---------------------------------------------------------------------------
210. Further, we disagree with Southern Companies that our actions
in this regard are akin to what was at issue in CAISO v. FERC. As
explained in Order No. 1000, in that case, the court found that the
Commission did not have the authority under section 206 of the FPA to
direct the California ISO to alter the structure of its corporate
governance, concluding that the choosing and appointment of corporate
directors is not a ``practice * * * affecting [a] rate'' within the
meaning of the statute.\277\ The court explained that the Commission is
empowered under section 206 to assess practices that directly affect or
are closely related to a public utility's rates and ``not all those
remote things beyond the rate structure that might in some sense
indirectly or ultimately do so.'' \278\ As we explained in Order No.
1000, the transmission planning activities that are the subject of the
rule have a direct and discernable effect on rates.\279\ These reforms
are intended to help create a path to allow public utility transmission
providers, in consultation with stakeholders, in each transmission
planning region to assess what transmission needs are being driven by
Public Policy Requirements, just as they currently look to whether
transmission needs are driven by reliability or economic
considerations.
---------------------------------------------------------------------------
\277\ CAISO v. FERC, 372 F.3d at 403.
\278\ Id.
\279\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 112.
---------------------------------------------------------------------------
211. Similarly, our actions in this regard are not contrary to the
Supreme Court's opinion in Southwestern Bell, which was cited by
Southern Companies. We are ``not the owner of the property of public
utility companies'' and we are ``not clothed with the general power of
management incident to ownership,'' and nothing in these rules provide
the Commission with such authority.\280\ We are, as we discuss herein,
providing for the consideration of transmission needs driven by Public
Policy Requirements, just as public utility transmission providers
consider transmission needs driven by reliability or economics. That
direction is not tantamount to directing public utility transmission
providers how to manage their property.
---------------------------------------------------------------------------
\280\ Southwestern Bell, 262 U.S. at 289.
---------------------------------------------------------------------------
212. Because, as discussed herein, we have statutory authority to
implement these reforms, we disagree with Southern Companies' that
Order No. 1000 is contrary to Comcast v. FCC, where the court concluded
that the
[[Page 32219]]
Federal Communications Commission (FCC) lacked requisite statutory
authority to regulate an Internet service provider's network management
practices. The court explained that the FCC could not rely on policy
statements in the Communications Act of 1934 by themselves as the basis
for the FCC to exercise ancillary authority to regulate Internet
service, noting that policy statements are not delegations of
regulatory authority.\281\ The court also found that the FCC's reliance
on other statutory provisions failed because the agency was using its
ancillary authority to pursue standalone policy objectives rather than
to support its exercise of a delegated power.\282\ By contrast, the
Commission's transmission planning reforms, including those related to
Public Policy Requirements, fall within the Commission's statutorily
mandated duties under the FPA, as discussed above. Thus, the Commission
is not relying on ancillary authority to pursue standalone policy
objectives, much less basing its actions on broad statements of
Congressional policy.
---------------------------------------------------------------------------
\281\ Comcast v. FCC, 600 F.3d at 654-55.
\282\ Id. at 658-61.
---------------------------------------------------------------------------
213. We disagree with ELCON, AF&PA, and Associated Industrial
Groups that Order No. 1000's requirements regarding Public Policy
Requirements raise significant federalism issues. As a factual matter,
there are significant differences between what we are requiring in
Order No. 1000 and the decision in New York v. U.S., which petitioners
cite in support of their federalism argument. In that case, the Supreme
Court held that the federal government could not compel states to
implement a federal regulatory program.\283\ That is not what is at
issue here. Instead, Order No. 1000 requires that local and regional
transmission planning processes consider transmission needs driven by
Public Policy Requirements. This requirement is directed to public
utility transmission providers, which are subject to the Commission's
FPA jurisdiction, and not states. States are not required to implement
any action.
---------------------------------------------------------------------------
\283\ New York v. U.S., 505 U.S. at 151.
---------------------------------------------------------------------------
214. Petitioners' federalism argument focuses more on the
allocation of costs associated with transmission facilities developed
in response to Public Policy Requirements that are selected in the
regional transmission plan for purposes of cost allocation. But it is
unclear how petitioners can reasonably make the leap from the federal
commandeering of state legislatures at issue in New York v. U.S. to the
requirement that costs for transmission needs driven by Public Policy
Requirements be allocated pursuant to an Order No. 1000-compliant cost
allocation method. As discussed below, it may or may not be the case
that entities in one state benefit from a new transmission facility
built in response to another state's Public Policy Requirement, in
accordance with a transmission planning region's regional cost
allocation method. For example, a transmission facility selected in a
regional transmission plan for purposes of cost allocation that was in
the first instance advanced to meet the transmission needs driven by a
particular state's Public Policy Requirement may also provide
reliability or economic benefits to entities located outside of that
state. We do not see how a regional cost allocation method making such
a finding equates with the commandeering of states by the federal
government or that this is tantamount to requiring the states to
implement a federal regulatory program. Rather, this simply ensures
that costs are allocated to all those entities that benefit from any
given transmission facility that is selected in a regional transmission
plan for purposes of cost allocation, regardless of whether those
benefits are reliability, economic, or related transmission needs
driven by Public Policy Requirements.
215. Next, we disagree with Southern Companies that the
consideration of transmission needs driven by Public Policy
Requirements interferes with integrated resource planning. First, as we
explain above, Order No. 1000 does not infringe on integrated resource
planning. States can continue to require utilities under their
jurisdiction to engage in integrated resource planning, and nothing in
Order No. 1000 changes that or otherwise negates those state-level
resource decisions. Second, with respect to these specific reforms, we
note that this requirement is a tool for public utility transmission
providers to consider transmission needs that may not be captured under
existing transmission planning processes, which are focused on
reliability and economic needs. If the transmission planning process
does consider additional transmission needs, i.e., those driven by
Public Policy Requirements, that does not mean this interferes with
state-level integrated resource planning, just as those existing
transmission planning processes do not interfere today.
216. We clarify that, for entities such as Bonneville Power, which
may be subject to their own organic statutes and regulations, nothing
in Order No. 1000's reforms regarding the consideration of transmission
needs driven by Public Policy Requirements is intended to preempt those
organic statutes or regulations. We believe that this should address
Bonneville Power's concern.
f. Legal Issues Related to Order No. 1000's Interregional Transmission
Coordination Reforms
i. Requests for Rehearing and Clarification
217. While most rehearing requests address legal issues associated
with transmission planning in general, some petitioners raise legal
issues specifically related to Order No. 1000's interregional
transmission coordination reforms.
218. Some petitioners argue that the Commission lacks authority to
require transmission providers to engage in interregional
coordination.\284\ Xcel, for example, argues that the Commission has
not adequately explained how interregional transmission planning
activities of public utilities directly affect jurisdictional rates. It
asserts that under a planning process no rate is charged and no
transmission customer is in privity to the transmission owner.
California ISO asserts that it is not precluded from arguing that the
Commission's interregional planning requirements in Order No. 1000 are
beyond its authority based on the fact that it did not seek judicial
review of the transmission planning provisions of Order No. 890.
---------------------------------------------------------------------------
\284\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
California ISO; Southern Companies; and Xcel.
---------------------------------------------------------------------------
219. Ad Hoc Coalition of Southeastern Utilities and Southern
Companies assert that the Commission has not historically required
transmission planning and coordination agreements to be filed, and
argues that it is arbitrary and capricious for the Commission to
determine now that such agreements are jurisdictional under section
205. They state that the Commission did not include transmission
planning and coordination agreements among the type of agreements that
are listed as jurisdictional in the Commission's Prior Notice
order.\285\ Ad Hoc Coalition of Southeastern Utilities adds that this
is logical because the penalty for untimely filings of jurisdictional
agreements, i.e., the payment of a refund to the affected customer in
the form of interest on the payments received over the period that the
jurisdictional agreement was not on file, would not apply to a
transmission
[[Page 32220]]
coordination planning agreement.\286\ For example, because there are no
rates or payments in a transmission planning or coordination agreement,
it asserts that there would be no penalty, which reinforces its claim
that the Commission has no jurisdiction over such agreements for
purposes of section 206.
---------------------------------------------------------------------------
\285\ Ad Hoc Coalition of Southeastern Utilities at 63-64;
Southern Companies at 85 (citing Prior Notice and Filing Req'ts
Under Part II of the Fed. Power Act, 64 FERC ] 61,139 (1993) (Prior
Notice Order)).
\286\ Ad Hoc Coalition of Southeastern Utilities at 63 (citing
generally Prior Notice Order, 64 FERC ] 61,139, App. at 11.)
---------------------------------------------------------------------------
220. WIRES states that section 206 requires the Commission to
indicate what measures will cure the practical and legal deficiencies
in interregional planning and to order industry to make curative
filings, not to ask industry to spend months in effect deciding what
will satisfy the FPA. Moreover, it states that ordering regulated
entities to make filings under section 205 is impermissible. It
therefore contends that Order No. 1000 lacks substantial evidence for
this approach and is not the result of reasoned decision-making.
221. Bonneville Power seeks clarification that the formal procedure
required by Order No. 1000 to identify and jointly evaluate
transmission facilities that are proposed to be located within adjacent
transmission planning regions may be established in a manner that
allows Bonneville Power to identify and evaluate the interregional
facility in an open and transparent process in accordance with its
statutory authority.\287\ Alternatively, it requests rehearing of the
Commission's rejection of Bonneville Power's concerns on the grounds
that the Commission's decision is arbitrary and capricious and violates
the Administrative Procedure Act. Bonneville Power argues that, if the
requirement for a formal procedure to identify and jointly evaluate
proposed interregional facilities includes details about how the
facilities will be planned and developed, then the Commission
effectively ignored Bonneville Power's comment without explanation.
Bonneville Power asserts that the Commission's requirement, in effect,
impermissibly requires non-public utilities to adhere to the FPA
requirements applicable to public utilities, which it believes will
have a chilling effect on non-public utility participation in regional
planning process, contrary to the Commission's goal of broad-based
participation. Bonneville Power also argues that the Commission lacks
authority to require it to accept regulations under sections 205 and
206 as a condition of its participation in regional or interregional
transmission planning.
---------------------------------------------------------------------------
\287\ Bonneville Power at 32-34 (citing Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 478, 481).
---------------------------------------------------------------------------
ii. Commission Determination
222. We affirm our legal authority to undertake Order No. 1000's
reforms regarding interregional transmission coordination. We disagree
with Xcel that we have not explained how interregional transmission
coordination is a practice affecting jurisdictional rates. Similar to
our regional transmission planning reforms, the Commission found that
the interregional transmission coordination reforms will help to
identify transmission facilities that may be more efficient or cost-
effective than what individual transmission planning regions may
identify, thereby helping to ensure that jurisdictional rates for
transmission service are just and reasonable and not unduly
discriminatory or preferential.
223. Further, we disagree with WIRES that we cannot undertake the
interregional transmission coordination reforms as set forth in Order
No. 1000. Order No. 1000 requires that the public utility transmission
providers in each pair of neighboring transmission planning regions,
working through their regional transmission planning processes, must
develop the same language to be included in each public utility
transmission provider's OATT that describes the interregional
transmission coordination procedures for that particular pair of
regions, or alternatively, to enter into interregional coordination
agreements.\288\ In doing so, the Commission is allowing public utility
transmission providers in the first instance to negotiate the terms of
the common OATT language or agreements, so long as they meet the
minimum requirements set forth in Order No. 1000. This approach is
consistent with the regional flexibility provided elsewhere in Order
No. 1000. WIRES offers no compelling reason that we should depart from
that approach here. The Commission has taken appropriate action under
FPA section 206 to undertake the interregional transmission
coordination reforms. While we provide flexibility and, therefore,
allow public utility transmission providers the ability to craft
agreements that take into account their needs and the needs of their
stakeholders, it is important to note that the Commission will review
each compliance filing to ensure that they are just and reasonable and
not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\288\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 475.
---------------------------------------------------------------------------
224. We also disagree with Ad Hoc Coalition of Southeastern
Utilities and Southern Companies that it is arbitrary and capricious to
require public utility transmission providers to file interregional
transmission coordination agreements. As an initial matter, as noted
above, the Commission does not require that public utility transmission
providers enter into interregional transmission coordination agreements
to comply with Order No. 1000, though they may do so. Rather, public
utility transmission providers must develop common OATT language that
implements Order No. 1000's interregional transmission coordination
reforms. As noted above, we find that these reforms are necessary to
identify more efficient or cost-effective transmission facilities than
what individual transmission planning regions may identify, thereby
helping to ensure that jurisdictional rates for transmission service
are just and reasonable and not unduly discriminatory or preferential.
Accordingly, it follows that such common OATT language must be filed
with the Commission. Furthermore, we fail to see how this is changed by
the Commission allowing, as an alternative, public utility transmission
providers to reflect the interregional transmission coordination
procedures in an agreement filed with the Commission.
225. Moreover, whether or not such agreements were contemplated in
the Prior Notice Order, we find that the Prior Notice Order does not
prescribe the entire universe of filings that the Commission will
require to be filed. To so limit the universe of such agreements would
impede the Commission's statutory duty to ensure that the rates, terms,
and conditions of jurisdictional service are just and reasonable and
not unduly discriminatory or preferential. In the Prior Notice Order,
the Commission made an effort to bring certainty to a number of
jurisdictional issues surrounding certain agreements. Among other
things, the Prior Notice Order stated that ``the utility industry
remains unclear as to whether various types of agreements need to be
filed for Commission review because of the uncertain jurisdictional
status of particular types of agreements.'' \289\ It should be noted
that the Commission did not represent that the agreements it addressed
in the Prior Notice Order were, or would be, the only agreements that
are subject to the Commission's jurisdiction.\290\
---------------------------------------------------------------------------
\289\ Prior Notice Order, 64 FERC ] 61,139 at 61,977.
\290\ In the appendix to the Prior Notice Order, the Commission
provided ``a brief analysis of the various types of agreements
identified by the participants in this proceeding * * *. [T]his
analysis is general in nature and is intended to be illustrative of
the Commission's current thinking on these subjects.'' Prior Notice
Order, 64 FERC ] 61,139 at 61,989. The specific types of agreements
discussed in the appendix to the Prior Notice Order include: (1)
Contribution in aid of construction agreements; (2) Qualifying
Facility agreements; (3) exchanges; (4) borderline agreements; and
(5) de minimis agreements. Id. at 61,989-96.
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[[Page 32221]]
226. Ad Hoc Coalition of Southeastern Utilities overstates the
Prior Notice Order's discussion when it contends that the Prior Notice
Order's remedy for late-filed agreements (i.e., time-value refunds)
shows the questionable jurisdictional nature of interregional
transmission coordination agreements because the remedy would not
apply. We stated: ``If a utility files an otherwise just and reasonable
cost-based rate after the new service has commenced, we will require
the utility to refund to its customers the time value of the revenues
collected * * * for the entire period that the rate was collected
without Commission authorization * * *. We will implement a similar
remedy for the unauthorized late filing of market-based rates.'' \291\
We note that this discussion focuses on rate filings (whether market-
based or cost-based). However, there are other types of documents that
the Commission requires to be filed that govern the terms and
conditions of jurisdictional transmission service. For example, many
pro forma OATT provisions deal with terms and conditions rather than
strictly with rates. And, as discussed herein, we find that
interregional transmission coordination issues have a direct and
concrete impact on jurisdictional rates and, consequently,
interregional transmission coordination agreements must also be filed.
---------------------------------------------------------------------------
\291\ Id. at 61,979-80.
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227. We clarify for Bonneville Power that Order No. 1000's
interregional transmission coordination reforms are not intended to
preempt the statutes governing Bonneville Power. However, to the extent
that any of the interregional transmission coordination efforts in
which Bonneville Power participates does have the effect of interfering
with Bonneville Power's statutory duties, it may bring those concerns
to the Commission's attention.
g. Other Legal Issues Related to Regional Transmission Planning
Requirements
i. Requests for Rehearing and Clarification
228. APPA asserts that public power systems will likely be unable
to participate in regional transmission planning processes without
specific assurances that their legal obligations and concerns will be
accommodated in regional transmission planning processes. In
particular, APPA is concerned that public power systems may lose their
tax-exempt status if transmission facilities are found to be used for
private activity rather than public activity. APPA argues that Order
Nos. 888 and 890 acknowledged the importance of this issue by limiting
a jurisdictional public utility's transmission obligations regarding
facilities funded with local furnishing bonds, and that Congress
limited the Commission authority to require non-jurisdictional
transmission providers to provide comparable transmission service. APPA
states that the Commission's expectation that non-public utility
transmission providers will participate in regional transmission
planning processes is at odds with the Commission's declining to
provide assurance in Order No. 1000 of accommodations for their unique
limitations, choosing instead to advise public power systems to
advocate such accommodation on their own in these regional processes.
APPA encourages the Commission to reaffirm the specific assurances
provided to public power transmission providers in the past regarding
the protection of their tax-exempt financing.
229. Arizona Cooperative and Southwest Transmission seek
clarification that nothing in Order No. 1000 alters the rights of
entities to submit section 206 complaints charging that a transmission
plan submitted, accepted, or approved under Order No. 1000, or a
subsequent cost allocation or cost recovery made under such a plan,
establishes or contributes to a rate, charge, classification, rule,
regulation, practice, or contract that is not just and reasonable or
that is unduly discriminatory or preferential. Otherwise, they seek
rehearing because the right to file a complaint and the applicable
standard for such complaints and for a rate, charge, classification,
rule, regulation, practice or contract is established by sections 205
and 206 of the FPA and cannot be abrogated by the Commission by rule or
practice.
ii. Commission Determination
230. We recognize that Order No. 1000 may have been unclear as to
whether public power entities, such as those represented by APPA, would
be provided with the same assurances that they received in Order Nos.
888 and 890 as to whether the requirements of the rule would abrogate
their tax-exempt status or cause them to violate a private activity
bond rule. Order No. 1000 had focused on the consistency of reciprocity
obligations in the three orders but did not specifically address the
tax-exempt status of public power entities. To be clear, the assurances
provided in Order Nos. 888 and 890 remain unchanged in Order No. 1000.
Consistent with Order Nos. 888 and 890, nothing in Order No. 1000 is
intended to abrogate the tax-exempt status of public power entities or
otherwise cause such entities to violate a private activity bond rule
for purposes of section 141 of title 26 of the Internal Revenue Code.
231. In response to Arizona Cooperative and Southwest Transmission,
we clarify that nothing in Order No. 1000 modifies any right to file a
section 206 complaint. In so clarifying, we make the following
observations. We note that Order No. 1000 does not require the filing
of a regional transmission plan for Commission approval. Nonetheless,
entities may file a complaint regarding the implementation of the
process itself. We have entertained such complaints in similar
circumstances.\292\ For example, a party might argue in a section 206
complaint that the public utility transmission providers in a given
region did not follow their Commission-approved Order No. 1000-
compliant regional transmission process in selecting facilities in
their regional transmission plan for purposes of cost allocation. Of
course, under section 206, the complainant bears the burden of proof to
demonstrate that the process was unjust and unreasonable and that its
proposed remedy is just and reasonable. We also note that a primary
purpose of Order No. 1000 is to establish a Commission-approved open
and transparent regional transmission planning process that includes
cost allocation determinations based on a cost allocation method that
is also Commission-approved.\293\
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\292\ See, e.g., Transmission Technology Solutions, LLC and
Western Grid Development, LLC v. California Indep. Sys. Operator
Corp., 135 FERC ] 61,077 (2011) (Transmission Technology Solutions).
\293\ See, e.g., Transmission Technology Solutions, 135 FERC ]
61,077 at P 122 (``Contrary to Complainants' arguments, CAISO
submitted evidence to demonstrate that its decision-making process
reflected objective analysis; was consistent with the CAISO Tariff;
and was based on approving the most prudent and cost-effective long-
term projects that maintain reliability for the region.'').
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2. Regional Transmission Planning Requirements
a. Final Rule
232. Order No. 1000 required each public utility transmission
provider to participate in a regional transmission planning process
that produces a regional transmission plan that complies with seven of
the nine transmission planning principles of
[[Page 32222]]
Order No. 890.\294\ Order No. 1000 required public utility transmission
providers to evaluate, through this regional transmission planning
process and in consultation with stakeholders, alternative transmission
solutions that might meet the needs of the transmission planning region
more efficiently or cost-effectively than solutions identified by
individual public utility transmission providers in their local
transmission planning process. This could include transmission
facilities needed to meet reliability requirements, address economic
considerations, or meet transmission needs driven by Public Policy
Requirements.\295\ When evaluating the merits of such alternative
transmission solutions, the Commission also directed public utility
transmission providers in the transmission planning region to consider
proposed non-transmission alternatives on a comparable basis.\296\ In
addition, Order No. 1000 provided public utility transmission providers
in each transmission planning region the flexibility to develop, in
consultation with stakeholders, procedures by which the public utility
transmission providers in the region identify and evaluate the set of
potential solutions that may meet the region's needs more efficiently
or cost-effectively.
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\294\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 146,
151 & n.141 (the regional participation and cost allocation
principles were not included because they are the subject of
specific reforms in Order No. 1000).
\295\ Id. P 148.
\296\ Id.
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233. The Commission clarified that for purposes of Order No. 1000,
a transmission planning region is one in which public utility
transmission providers, in consultation with stakeholders and affected
states, have joined for purposes of satisfying the requirements of
Order No. 1000, including among other purposes to develop a regional
transmission plan.\297\ The Commission explained that the scope of a
transmission planning region should be governed by the integrated
nature of the regional power grid and the particular reliability and
resource issues affecting individual regions.\298\ While the Commission
declined to prescribe the geographic scope of any transmission planning
region, the Commission nevertheless clarified that an individual public
utility transmission provider cannot, by itself, satisfy the regional
transmission planning requirements of either Order No. 890 or Order No.
1000.\299\ The Commission also noted that every public utility
transmission provider has already included itself in a region for
purposes of complying with Order No. 890's regional participation
principle, and encouraged public utility transmission providers to look
to existing regional processes for guidance on compliance in
formulating transmission planning regions.\300\
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\297\ Id. P 160.
\298\ Id. (citing Order No. 890, FERC Stats. & Regs. ] 31,241 at
P 527).
\299\ Id.
\300\ Id.
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234. Further, Order No. 1000 declined to require merchant
transmission developers to participate in a regional transmission
planning process, because they assume all financial risk for developing
and constructing their transmission facilities, and therefore, it is
unnecessary to require such developers to participate in a regional
transmission planning process for purposes of identifying the
beneficiaries of their transmission facilities so that they can avail
themselves of regional cost allocation.\301\ However, Order No. 1000
acknowledged that a transmission facility proposed or developed by a
merchant transmission developer has broader impacts than simply cost
recovery. Therefore, Order No. 1000 concluded that it is necessary for
a merchant transmission developer to provide adequate information and
data to allow public utility transmission providers in the transmission
planning region to assess the potential reliability and operational
impacts of the merchant transmission developer's proposed transmission
facilities on other systems in the region.\302\
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\301\ Id. P 163.
\302\ Id. P 164.
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b. Requests for Rehearing and Clarification
235. Petitioners raise a number of arguments with respect to the
regional transmission planning process, which address such topics as
whether public utility transmission providers were given too much
flexibility, the definition of a ``transmission planning region,'' the
participation of non-public utility transmission providers in regional
transmission planning processes, compliance with Order No. 890
transmission planning principles, whether there needs to be a post-plan
process, the role of state regulators in the regional transmission
planning process, Order No. 1000's treatment of merchant transmission
projects, what constitutes ``new'' transmission facilities for purposes
of Order No. 1000, and other issues.
236. Some petitioners are concerned that the Order No. 1000 does
not set out the regional transmission planning requirements in
sufficient detail. Illinois Commerce Commission contends that the
Commission erred in providing too much flexibility in the regional
planning process, and that now is the time for the Commission to
provide guidance to the industry that will reduce business uncertainty
and increase process efficiency. WIRES urges the Commission to assist
the industry with new standard procedures for regional planning,
including criteria for evaluating both major backbone projects and
transmission upgrades that have a relatively short planning and
construction cycle and that can be adapted to fill economic or
reliability needs as they arise in the ordinary course of system
operations. Regarding Order No. 1000's statement that ``public utility
transmission providers 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'' (emphasis added), Western Independent Transmission Group
requests that transmission providers should not only simply ``explain''
how they will determine which facilities to evaluate, but also should
be required to justify those determinations in their compliance
filings.
237. PPL Companies are concerned with Order No. 1000's mandate to
participate in a regional transmission planning process, arguing that
such a mandate forces utilities in non-RTO regions to join an RTO or
RTO-like process. PPL Companies claim that because this mandate may put
certain entities at odds with their state commissions, the Commission
should clarify that RTO membership remains voluntary, as does
participation in regional transmission planning.
238. Others are concerned that Order No. 1000's regional
transmission planning reforms may allow public utility transmission
providers to discriminate against other entities. Transmission Access
Policy Study Group claims that Order No. 1000 enhances the ability of
public utility transmission providers in non-RTO regions to benefit
their generation function by giving them the right to make decisions as
to which upgrades go into the regional transmission plan for purposes
of cost allocation, while transmission dependent utilities and non-
jurisdictional entities are only offered the opportunity to provide
input into the planning process. It points to the RTG Policy Statement,
which it
[[Page 32223]]
states provides for fair and nondiscriminatory governance and decision-
making procedures and which states that transmission dependent
utilities must be protected.\303\ If a non-RTO region does not provide
balanced decision-making, Transmission Access Policy Study Group argues
that there should be consequences, such as more scrutiny with respect
to transmission rates and regional cost allocation methods. PPL
Companies seek clarification that the Commission will review the voting
rules and structures of regional and interregional groups to ensure
that the effect of such structures on small utilities is not unjust,
unreasonable or unduly discriminatory.
---------------------------------------------------------------------------
\303\ Transmission Access Policy Study Group at 9 (citing RTG
Policy Statement, 58 Fed. Reg. 41,626 (Aug. 5, 1993), FERC Stats. &
Regs. ] 30,976 (1993); Southwest Regional Transmission Ass'n, 69
FERC ] 61,100, at 61,400-02 (1994); PacifiCorp, 69 FERC ] 61,099, at
61,382, n.70 (1994)).
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239. Transmission Dependent Utility Systems further argue the
Commission should clarify that more efficient and cost-effective
solutions to the effects of loop flow are among the things to be
considered in regional planning and interregional coordination
processes. Transmission Dependent Utility Systems state that although
Order No. 1000 discusses loop flows in the context of cost allocation,
it does not address the issue in the context of regional planning or
interregional coordination.
240. Several petitioners seek clarity as to what the Commission
means by a ``transmission planning region.'' \304\ Energy Future
Coalition Group asserts that the Commission must set minimum standards
for defining transmission planning regions; otherwise, such regions may
be defined in a way that is irrational and unworkable, thus hindering
the transmission development that Order No. 1000 is meant to promote.
It suggests the following: All transmission providers in the region
must be within the same interconnection; participants in the region
must be electrically contiguous; the region must have sufficient
existing internal electricity generation and consumption to justify the
planning of high voltage transmission facilities within it; and the
region must be an integrated electric system for which transmission
planning within the region can be accomplished consistent with
engineering principles and common sense. It also suggests that the
Commission specify that use of the regions approved for purposes of
Attachment K coordination of transmission plans would be presumptively
acceptable.
---------------------------------------------------------------------------
\304\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Energy Future Coalition Group; MISO Northeast; PPL Companies; and
Southern Companies.
---------------------------------------------------------------------------
241. Ad Hoc Coalition of Southeastern Utilities commends the
Commission for what it characterizes as a reaffirmation of existing
regions. However, it asserts that if the Commission changes course and
finds that planning regions in the Southeast are different from current
regions, such a finding would be counter to Order No. 890 precedent. It
also asserts that it would violate FPA section 202(a) because affected
transmission owners and providers have not agreed to engage in
transmission coordination based on a different configuration of a
region. Southern Companies raise similar arguments, noting that it is
commencing its compliance requirements with the understanding that the
SERTP is an appropriate region under Order No. 1000.
242. PPL Companies state that the geographic scope requirement
poses difficulties outside of an RTO. For example, they state that if
Louisville Gas & Electric and Kentucky Utilities prefer to have a
Kentucky-only planning group, it is unclear from Order No. 1000 whether
such a region would be sufficient for regional planning purposes. PPL
Companies further claim that regional transmission planning
requirements raise practical concerns for entities outside of RTOs,
particularly those in regions with non-public utility transmission
providers, which have the discretion, not a mandate, to comply. PPL
Companies thus seek clarification that a region can be comprised of a
single system or single state where a broader scope is either difficult
or impossible to attain.
243. MISO Northeast seeks clarification that an RTO/ISO may have
more than one transmission planning region for purposes of developing
regional transmission plans, noting that there are three distinct
subregions in MISO. MISO Northeast states that while the Commission
does not require any changes to existing regions, limiting the number
of transmission planning regions in an RTO/ISO to one would have the
effect of prescribing the geographic scope of a transmission planning
region, which the Commission said it would not do in Order No. 1000.
244. Several petitioners take issue with Commission's statement in
Order No. 1000 that, ``if a non-public utility transmission provider
makes the choice to become part of the transmission planning region and
it is determined by the transmission planning process to be a
beneficiary of certain transmission facilities selected in the regional
transmission plan for purposes of cost allocation, that non-public
utility transmission provider is responsible for the costs associated
with such benefits.'' \305\
---------------------------------------------------------------------------
\305\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 629.
---------------------------------------------------------------------------
245. Large Public Power Council contends that unless non-public
utility transmission providers vote on which proposed transmission
projects should be selected in the regional transmission plan for
purposes of cost allocation, the Commission should allow non-public
utility transmission providers to participate in all aspects of
regional transmission planning without being allocated costs pursuant
to the regional cost allocation method. Large Public Power Council
argues that to do otherwise will substantially disrupt existing
planning processes by discouraging non-public utility transmission
providers from participating out of concern that they will be allocated
costs, detrimentally affecting system efficiency, cost, and
reliability.
246. MEAG Power contends that it would be problematic for it to
enter into an open-ended commitment to pay costs that are allocated per
a regional plan before the regional planning and cost allocation
protocols have been developed and determined. Moreover, MEAG Power
states that this will deter it from continuing to participate in the
current SERTP planning effort on a voluntary basis if in doing so it
would be bound to an unknown amount of allocated transmission costs.
MEAG Power requests clarification that its choice to continue to
participate in SERTP does not bind it to a cost allocation result under
Order No. 1000 Otherwise, it states it will be compelled by its Board's
policy to withdraw from SERTP as well as SIRPP before the provisions of
Order No. 1000 take full effect.
247. Transmission Dependent Utility Systems request that the
Commission clarify or grant rehearing to specify that those
stakeholders who have not meaningfully participated in the regional
planning or interregional coordination, the development of regional and
interregional cost allocation methods, or in the determination of
beneficiaries, will have no costs for such projects allocated to them.
Transmission Dependent Utility Systems argue this clarification will
ensure participation of load-serving customers and is consistent with
Cost Allocation Principle 2.
248. Sacramento Municipal Utility District states that it
participates in both
[[Page 32224]]
the California Transmission Planning Group and the WestConnect planning
processes, but would have little incentive to participate in either if
doing so would expose it to costs for transmission over which it does
not take any service and could result in duplicative charges.
249. Bonneville Power seeks clarification that it may independently
decide, using an open and transparent process consistent with its
statutory authorities, whether it will receive the benefits of, and pay
for, a transmission project. It requests clarification that the
regional planning process determination would not be binding on it, but
that, instead, it and transmission developers could use the cost
allocation analysis as input to their negotiations and other required
statutory processes. Bonneville Power argues that this clarification is
appropriate because its governing statutes do not permit it to
participate in mandatory cost allocation, explaining that its
Administrator must determine its cost allocation responsibilities and
cannot delegate them to the regional planning process.\306\ Bonneville
Power argues that it also must retain the right to determine whether or
not to commit funds to a project until conclusion of a review of a
project under the National Environmental Policy Act. In the
alternative, Bonneville Power requests rehearing, arguing that the
Commission failed to adequately consider and address its comments
addressing Bonneville Power's statutory authorities related to
mandatory cost allocation.
---------------------------------------------------------------------------
\306\ Bonneville Power at 13-15 (citing Northwest Power Act, 16
U.S.C. Sec. 839f(b) (2006); Transmission System Act, 16 U.S.C.
Sec. 838b (2006); Pacific Northwest Generating Coop. v. DOE,
Bonneville Power Admin., 580 F.3d 792, 823 (9th Cir. 2009)).
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250. With respect to Order No. 1000's discussion of compliance with
Order No. 890 transmission planning principles and related issues, Ad
Hoc Coalition of Southeastern Utilities argues that the Southeast
transmission planning regions already comply with Order No. 890's
planning principles. Ad Hoc Coalition of Southeastern Utilities asserts
that Order No. 890 and the subsequent compliance orders make it clear
that the nine planning principles apply to regional planning processes.
However, it asserts that certain statements in Order No. 1000, such as
the statement that some regions are not exchanging sufficient data,
imply that all or some of the nine planning principles do not apply
under Order No. 890 to the existing regional planning processes.\307\
If the Commission assumes or concludes that utilities in the Southeast
are not exchanging sufficient information, then Ad Hoc Coalition of
Southeastern Utilities contends that such an assumption or conclusion
would be in error and not supported by substantial evidence.
---------------------------------------------------------------------------
\307\ Ad Hoc Coalition of Southeastern Utilities at 48 (citing
Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 151-52).
---------------------------------------------------------------------------
251. With regard to the openness and transparency transmission
planning principles, Transmission Dependent Utility Systems want the
Commission to clarify that information cannot be withheld from load-
serving entities based on common rationales offered by transmission
owners, such as claims of discrimination against non-load-serving
entity customers, violation of tariff confidentiality provisions, or
violation of the Commission's Standards of Conduct. They argue that if
these concerns are legitimate, they can be adequately addressed by
confidentiality agreements or through other appropriate means.
Transmission Dependent Utility Systems also want the Commission to
confirm that such disclosure will not be deemed a violation of the
Standards of Conduct.
252. With respect to the requirement that public utility
transmission providers develop a regional transmission plan, Illinois
Commerce Commission argues that the Commission erred in not requiring
each transmission provider to file its regional transmission plan (as
well as associated cost allocations), contending that the regional and
interregional stakeholder processes that Order No. 1000 requires are
not sufficient to ensure notice to the public and an opportunity to be
heard. Illinois Commerce Commission states that the failure to
establish a process for Commission review of regional transmission
plans and associated cost allocations burdens ratepayers and
exacerbates the problem associated with delegating authority to
transmission providers.\308\
---------------------------------------------------------------------------
\308\ As noted above, Illinois Commerce Commission also believes
that Order No. 1000 provides too much flexibility to transmission
providers.
---------------------------------------------------------------------------
253. Transmission Access Policy Study Group argues that Order No.
1000 should have required a timely post-plan process to ensure that the
plan is acted upon, and argues that if a transmission developer has
made a commitment to construct facilities, then it should not have the
option to abandon the project, thus leaving others that counted on the
upgrade responsible for the costs. It contends that the steps Order No.
1000 did take, such as Web site posting requirements and the
reliability protections addressed in the context of Order No. 1000's
nonincumbent reforms, are inadequate. Additionally, Transmission Access
Policy Study Group argues that Order No. 1000 should have made clear
that the Web site posting requirement it did require must be made on a
timely basis, such as a specified time after the regional transmission
plan is posted.
254. Some state regulators raise concerns about the role they are
intended to play in the regional transmission planning process.\309\
NARUC argues that, while prior Commission orders and the DOE-funded
interconnectionwide planning processes properly recognize the essential
role of state regulators, Order No. 1000 improperly lumps state
regulators with all other stakeholders. Illinois Commerce Commission
also points out that Order No. 1000 does not require transmission
providers to establish any unique role or provide any special weight in
the process for state regulators. Wisconsin PSC asserts that there is
no rational basis for the casual and undefined potential role that
Order No. 1000 implies that states would have in the regional and
interregional transmission planning processes. It asserts that states
and state commissions are different from other stakeholders in
materially important ways, such as their authority to authorize
utilities to build and the ability to collect an allocated share of the
cost of transmission facilities. It also claims that this treatment of
the states is at odds with Order No. 890's express emphasis that
``planning must be coordinated with state regulators * * *''.\310\
Given this, Wisconsin PSC suggests the following changes to help
enhance state participation: (1) More focus on reducing planning delays
in a project's preconstruction phase by coordinating with state
regulators; (2) minimizing overlap between state and regional
transmission planning procedures relative to evaluation of project need
or sponsor qualification; and (3) where feasible, required compliance
with applicable state laws by a transmission developer before any
transmission line is selected for eligibility for regional cost
sharing. North Carolina Agencies state that the Commission should
recognize the unique and indispensible role that state regulatory
authorities play, rather than demoting them to one of many
stakeholders, as suggested in Order No. 1000.
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\309\ See, e.g., NARUC; Florida PSC; Illinois Commerce
Commission; and Wisconsin PSC.
\310\ Wisconsin PSC at 9 (citing Order No. 890, FERC Stats. &
Regs. ] 31,241 at P 574 (2007)).
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255. Further, Illinois Commerce Commission contends that the
[[Page 32225]]
Commission failed to recognize that state regulators may be limited in
their ability to actively engage in transmission planning processes
given the prohibition against pre-judging cases that may subsequently
come before them for siting, certification, or rate recovery. Illinois
Commerce Commission suggests that Commission attendance in a meeting of
the states to discuss this issue may be useful to reconcile the
Commission's expectations and the practical realities borne by state
regulators in this regard.
256. Florida PSC states that it is unclear how the Order No. 1000
transmission planning process overlay will interact and coexist with
existing planning processes. Florida PSC also asserts that
participating in the planning processes and monitoring neighboring
interregional agreements would require additional state commission
resources during a time of constrained state budgets. Illinois Commerce
Commission likewise contends that the level of participation the
Commission is encouraging is beyond most states' current capabilities.
It states that the Commission must go beyond Order No. 890 initiatives
to facilitate enhanced participation by state authorities in regional
and interregional planning processes. Illinois Commerce Commission also
seeks clarification that, where regional state committees have been
formed, it will be that committee (with Commission review) that decides
on its budget for participation in the planning process, and such
budget shall not be subject to veto by the transmission provider or any
stakeholder group.
257. Some petitioners seek rehearing or clarification of Order No.
1000's discussion of the role of merchant transmission developers in
the regional transmission planning process.\311\ APPA asks that the
Commission reconsider its decision to allow merchant developers merely
to provide information to transmission planners and instead require
merchant transmission developers to participate fully in regional and
interregional transmission planning processes. APPA argues that
requiring such developers to participate in regional and interregional
planning processes will give transmission planners the opportunity to
evaluate all projects side-by-side and then develop the set of projects
that will best serve the needs of all loads in a region, while
presenting the best economics and minimizing adverse impacts on the
environment.
---------------------------------------------------------------------------
\311\ See, e.g., APPA; National Rural Electric Coops; and
Transmission Dependent Utility Systems.
---------------------------------------------------------------------------
258. National Rural Electric Coops seek clarification that Order
No. 1000 does not create a special class of public utilities, i.e.,
merchant transmission developers, who are excused from obligations
imposed on other public utility transmission providers. National Rural
Electric Coops argue that the creation of a preferred class
distinguished solely by their method of cost recovery does not square
with the purpose of Order No. 1000 to ensure that all public utility
transmission providers be treated comparably in the transmission
planning process. They contend that the method of cost recovery is not
a valid reason for excusing public utility merchant developers from the
regional planning requirements generally applicable to public utility
transmission providers.
259. Transmission Dependent Utility Systems seek rehearing of the
determination that merchant transmission developers may opt out of
participation in regional transmission planning processes if they
assume all financial risk. Transmission Dependent Utility Systems argue
that financial arrangements have no bearing on the ability of affected
load-serving entities to reliably and economically serve their native
loads, that the failure to mandate merchant participation in regional
transmission planning therefore conflicts with FPA section 217(b)(4),
and that the internalization of risk by a merchant developer cannot
justify excusing it from compliance with other planning obligations.
They add that requiring merchant developers only to share information
with public utility transmission providers fails to ensure that load-
serving transmission customers will be able to obtain information about
proposed merchant projects, evaluate their effects, and provide input
regarding their development. Transmission Dependent Utility Systems
seek clarification that if a merchant developer does not fully
participate in a regional transmission planning process, it should be
obligated to internalize the costs of any adverse reliability effects
on the grid posed by its project or any need for upgrades caused by a
change in flows, adding that the failure to require merchant developers
to internalize all related costs of their transmission projects would
violate cost causation principles by forcing transmission customers to
pay for the costs of upgrades caused, but not paid for, by merchant
transmission developers.
260. Petitioners raise concerns about Order No. 1000's conclusion
that public utility transmission providers could apply flexible
criteria when determining which transmission projects are in the
regional transmission plan. PSEG Companies argue that the Commission
introduced vague criteria into the planning process that will result in
an opaque and confusing, rather than a formulaic, approach.\312\ They
claim that an opaque approach will allow transmission providers to
unofficially represent policymaking bodies and impose their costs on
customers, who must pay for unneeded projects.
---------------------------------------------------------------------------
\312\ PSEG Companies at 50 (citing PJM Interconnection, L.L.C.,
119 FERC ] 61,265 at P 24 (2007) (directing PJM to file a formulaic
approach with respect to planning for economic transmission
projects)).
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261. Finally, some petitioners request guidance on what constitutes
a ``new'' transmission facility for purposes of Order No. 1000. Western
Independent Transmission Group seeks clarification of the Commission's
statement that Order No. 1000 applies to new transmission facilities.
It states that Order No. 1000 does not provide sufficient guidance as
to how transmission providers should define evaluation and reevaluation
for purposes of determining what facilities are subject to Order No.
1000. It contends that, in the absence of Commission guidance,
transmission providers will have excessive discretion to determine
which facilities are subject to Order No. 1000. Western Independent
Transmission Group seeks clarification regarding the extent of
transmission planning entities' discretion and Commission guidance as
to how such discretion should be exercised without restricting
independent developers' access to the grid.
262. LS Power requests that the Commission clarify that all
projects that are approved on or after the compliance date shall be
subject to Order No. 1000, regardless of the status of the planning
cycle. It explains that such a requirement would not burden the
regional planning process as the transmission planning entity has ample
warning regarding the requirement and can tailor its planning process
to incorporate Order No. 1000 for all projects not yet approved as of
the compliance date.
c. Commission Determination
263. Order No. 1000's regional transmission planning reforms are
intended to ensure that there is an open and transparent regional
transmission planning process that complies with Order No. 890's
transmission planning principles and produces a regional transmission
plan. There, we stated that
[[Page 32226]]
such transmission planning will expand opportunities for more efficient
and cost-effective transmission solutions for public utility
transmission providers and stakeholders, which, in turn, will help
ensure that the rates, terms, and conditions of Commission-
jurisdictional services are just and reasonable and not unduly
discriminatory or preferential.\313\
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\313\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 146.
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264. For the most part, petitioners do not argue against the
soundness of Order No. 1000's basic regional transmission planning
requirements although, as discussed above, some petitioners question
the need for these reforms as applied to their specific regions of the
country,\314\ while some assert that the Commission lacks the legal
authority to undertake these reforms, as discussed earlier in this
section.\315\ However, most of the petitioners' requests as to the
actual regional transmission planning requirements go to specific
issues, such as the flexibility afforded in Order No. 1000 to public
utility transmission providers, the definition of a transmission
planning region, the participation of non-public utilities and the role
of state regulators in the regional transmission planning process,
compliance with certain transmission planning principles, the treatment
of merchant transmission developers, and the definition of ``new''
transmission facilities under Order No. 1000.
---------------------------------------------------------------------------
\314\ See discussion supra at section II.B.
\315\ See discussion supra at section III.A.
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265. In this section, we affirm Order No. 1000's regional
transmission planning reforms. We also provide clarifications on many
of the issues raised by petitioners, including an issue that generated
a number of requests for rehearing and clarification, namely, the
participation of non-public utility transmission providers in the
regional transmission planning process. We believe the discussion
herein will assist public utility transmission providers, in
consultation with stakeholders, in developing their Order No. 1000
compliance filings by providing more clarity as to what the
Commission's requirements are with respect to Order No. 1000's regional
transmission planning reforms.
266. Some petitioners, such as Illinois Commerce Commission, assert
that Order No. 1000's regional transmission planning reforms provide
too much flexibility to public utility transmission providers. We
disagree. Rather, we believe that Order No. 1000 sets forth an approach
that balances the need to ensure that specified regional transmission
planning requirements are satisfied with our belief that the various
regions of the country differ significantly in resources, industry
organization, market design, and other ways so that a one-size-fits-all
approach to regional transmission planning would not be appropriate.
Specifically, Order No. 1000 requires public utility transmission
providers to develop a regional transmission planning process that
complies with the Order No. 890 transmission planning principles and
that produces a regional transmission plan. Within these parameters,
public utility transmission providers, in consultation with
stakeholders, have the flexibility to ensure that their respective
regional transmission planning process is designed to accommodate the
unique needs of that particular region. We will then evaluate each of
the Order No. 1000 compliance filings to ensure that they satisfy these
requirements.
267. For the same reasons, we decline to adopt standard procedures
in the regional transmission planning process for evaluating backbone
transmission facilities or for addressing transmission upgrades that
have a short planning and construction cycle and that can be adapted to
fill economic or reliability needs as they arise in the ordinary course
of system operations, as suggested by WIRES. As the Commission found in
Order No. 1000, each public utility transmission provider is required
to amend its OATT to describe a transparent and not unduly
discriminatory process for evaluating whether to select a proposed
transmission facility in the regional transmission plan for purposes of
cost allocation. This process must comply with the Order No. 890
transmission planning principles, ensuring transparency and the
opportunity for meaningful stakeholder input. The evaluation process
must culminate in a determination that is sufficiently detailed for
stakeholders to understand why a particular transmission facility was
selected or not selected in the regional transmission plan for purposes
of cost allocation.\316\ Accordingly, we do not find that standardized
procedures such as those suggested by WIRES are necessary or
appropriate. Moreover, by requiring an open and transparent
transmission planning process that produces a regional transmission
plan, Order No. 1000 will provide the Commission and interested parties
with a record that we believe will be able to highlight whether public
utility transmission providers are engaging in undue discrimination
against others, such as transmission-dependent utilities and non-
jurisdictional entities.
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\316\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 328.
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268. As discussed in greater detail in the section of Order No.
1000 addressing nonincumbent reforms,\317\ we agree with Western
Independent Transmission Group that public utility transmission
providers should both explain and justify the nondiscriminatory
evaluation process proposed in their compliance filings. Additionally,
Commission review and approval of a not unduly discriminatory
evaluation process will address Transmission Access Policy Study
Group's concern that Order No. 1000's regional transmission planning
reforms may empower public utility transmission providers at the
expense of other stakeholders, as well as its concern that the regional
transmission planning governance process should be fair and not unduly
discriminatory for all participants, including transmission dependent
utilities.
---------------------------------------------------------------------------
\317\ See id. at section III.B.3.
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269. PPL Companies assumes that a region will have formal voting
rules and structures to carry out these evaluations and decide which
proposed new transmission facilities are in the regional transmission
plan and selected for cost allocation, and it requests that we review
the voting rules and structures of each region's transmission planning
process to ensure that they do not disadvantage smaller utilities.
While Order No. 1000 does not necessarily require formal voting rules,
we will review any rules submitted to ensure that they are fair to all
participants. More important, we believe that adherence to the seven
Order No. 890 transmission planning principles, as adopted in Order No.
1000, will ensure fair treatment of all regional planning participants,
and we will review the process in every compliance filing, whether or
not it has formal voting rules and stakeholder governance structure,
for compliance with the transmission planning principles for (1)
coordination, (2) openness, (3) transparency, (4) information exchange,
(5) comparability, (6) dispute resolution, and (7) economic planning.
If public utility transmission providers in a transmission planning
region, in consultation with stakeholders, decide to establish formal
stakeholder governance procedures, such as voting measures, they should
include these in their Order No. 1000 compliance filings.
270. We agree with PPL Companies that RTO membership is and remains
voluntary. However, regional
[[Page 32227]]
transmission planning under Order No. 1000 is not voluntary for public
utility transmission providers.\318\ We disagree that by mandating a
regional transmission planning process we are forcing utilities in non-
RTO areas to join an RTO-like organization. The transmission planning
function of Order No. 1000 is but one of nine essential characteristics
and functions of an RTO under Order No. 2000, which include having an
independent grid operator for the entire region, among other operating
functions. Here, Order No. 1000's transmission planning requirements
involve the consideration of whether more efficient or cost-effective
alternatives to solutions identified in individual local transmission
plans exist and whether they will be selected in a regional
transmission plan for purposes of cost allocation. As discussed in
Order No. 1000 and here, we find that such transmission planning
activities are wholly within the Commission's statutory authority, and
that such reforms are necessary to implement at this time.
---------------------------------------------------------------------------
\318\ We address PPL Companies' legal arguments regarding
mandatory transmission planning requirements above. See discussion
supra at section III.A.1.
---------------------------------------------------------------------------
271. In response to Transmission Dependent Utility Systems, we do
not believe that it is necessary that we require that the regional
transmission planning process and interregional transmission
coordination procedures specifically address loop flows. We believe
that such concerns will necessarily be evaluated by the public utility
transmission providers in the regional transmission planning process as
they plan for the region's reliability and economic needs, as well as
the transmission needs driven by Public Policy Requirements. Likewise,
if loop flow affects more than one transmission planning region, these
issues may be addressed as part of Order No. 1000's interregional
transmission coordination.
272. With respect to questions from some petitioners concerning
transmission planning regions,\319\ we affirm Order No. 1000's
determination that ``the scope of a transmission planning region should
be governed by the integrated nature of the regional power grid and the
particular reliability and resource issues affecting individual
regions.'' \320\ We also affirm Order No. 1000's determination that the
Commission will not prescribe the size or scope of a transmission
planning region in a generic proceeding except to provide that a single
public utility transmission provider by itself may not be a
transmission planning region, consistent with Order No. 890.\321\ We
find that Order No. 1000 appropriately provided flexibility in this
regard, and that this flexibility will permit public utility
transmission providers and others the opportunity to form or join a
transmission planning region that best meets their needs and the needs
of their transmission customers.
---------------------------------------------------------------------------
\319\ See, e.g., PPL Companies; MISO Northeast; and Energy
Future Coalition Group.
\320\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 160
(citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 527).
\321\ Id.
---------------------------------------------------------------------------
273. In response to Southern Companies and Ad Hoc Coalition of
Southeastern Utilities, we reiterate that public utility transmission
providers may look to the transmission planning regions that were
accepted by the Commission in the Order No. 890 compliance phase in
forming a transmission planning region for purposes of Order No. 1000.
274. We appreciate petitioners' concerns about Order No. 1000's
expectations regarding the participation of non-public utility
transmission providers in the regional transmission planning process.
After reviewing the requests for rehearing and clarification on this
topic, we provide additional clarifications to the discussion in Order
No. 1000 regarding the participation of non-public utility transmission
providers in the regional transmission planning process.
275. As discussed more fully below, public utility transmission
providers in each transmission planning region must have a clear
enrollment process that defines how entities, including non-public
utility transmission providers, make the choice to become part of the
transmission planning region.\322\ In addition, each public utility
transmission provider (or regional transmission planning entity acting
for all of the public utility transmission providers in its
transmission planning region) must include in its OATT a list of all
the public utility and non-public utility transmission providers that
have enrolled as transmission providers in its transmission planning
region. A non-public utility transmission provider that makes the
choice to become part of a transmission planning region by enrolling in
that region would be subject to the regional and interregional cost
allocation methods for that region.\323\ Any non-public utility
transmission providers that do not make the choice to become part of
the transmission planning region will nevertheless be permitted to act
as stakeholders in the regional transmission planning process.\324\ In
sum, we believe that the requirement to have a clear enrollment process
for transmission providers in a transmission planning region, including
non-public utility transmission providers that make the choice to join
that region, along with the maintenance of a list of such enrollees,
provides certainty regarding who is enrolled in a region and therefore
who is a potential beneficiary that may be allocated costs.
---------------------------------------------------------------------------
\322\ While Order No. 1000 did not address issues relating to
stakeholder procedures, we note that those that make the choice to
become part of a transmission planning region could be provided with
voting rights upon enrollment if the regional transmission planning
process has a voting mechanism for selecting transmission projects
in the regional transmission plan for purposes of cost allocation.
See, e.g., Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 252
(stating that ``[w]ithin an RTO or ISO, stakeholder processes can be
used to determine whether to pursue either economic or reliability
upgrades and, thus, voting mechanisms such as those suggested by
PSEG could be adopted if stakeholders desire.'').
\323\ We note that many of the issues raised by petitioners that
are addressed in this part of the order also implicate reciprocity
issues. Requests for rehearing and clarification regarding Order No.
1000's conclusions regarding reciprocity are addressed in section
V.B, infra.
\324\ The term ``stakeholder'' is intended to include any party
interested in the regional transmission planning process. See Order
No. 1000, FERC Stats. & Regs. ] 31,323 at n.143.
---------------------------------------------------------------------------
276. In response to petitioners such as MEAG Power, we clarify that
participation in the development of the regional transmission planning
process and regional cost allocation method that a public utility
transmission provider will submit to the Commission to comply with
Order No. 1000 does not obligate a non-public utility transmission
provider to choose to join the transmission planning region by
enrolling and thus be eligible to be allocated costs under its regional
cost allocation method. As such, a non-public utility transmission
provider will not be considered to have made the choice to join a
transmission planning region and thus eligible for cost allocation
until it has enrolled in the transmission planning region. However, the
regional transmission planning process is not required to plan for the
transmission needs of such a non-public utility transmission provider
that has not made the choice to join a transmission planning region. If
the non-public utility transmission provider is a customer of a public
utility transmission provider in the region, that public utility
transmission provider must plan for that customer's needs as it would
for the needs of any customer. That non-public utility transmission
provider's ability to participate as a stakeholder in the regional
transmission planning process should be the same as
[[Page 32228]]
for any other similarly situated stakeholder customer.
277. While we acknowledge concerns raised by petitioners such as
MEAG Power and Large Public Power Council about how non-public utility
transmission providers make the choice to join a transmission planning
region, we conclude that these concerns are best addressed in the first
instance through participation in the development of the regional
transmission planning process and cost allocation method that its
neighboring public utility transmission provider(s) will rely on to
comply with Order No. 1000. Each non-public utility transmission
provider may decide whether or not to enroll in the region as a
transmission provider as such development nears completion.
Participation in the development of regional processes will not in
itself make the participant subject to regional cost, absent
enrollment. We encourage MEAG Power and other non-public utility
transmission providers to raise their concerns with all participants in
the development of the regional transmission planning process and cost
allocation method as they are developing the compliance filings.\325\
If non-public utility transmission providers believe that their
concerns have not been adequately addressed, they may raise their
concerns when the neighboring public utility transmission providers in
the region submit their compliance filing to the Commission.
---------------------------------------------------------------------------
\325\ See, e.g., Order No. 1000, FERC Stats. & Regs. ] 31,323 at
P 117 (``[N]on-jurisdictional entities, unlike public utilities, may
choose to join a regional transmission planning process and, to the
extent they choose to do so, they may advocate for those processes
to accommodate their unique limitations and requirements.'').
---------------------------------------------------------------------------
278. We decline to adopt Large Public Power Council's suggestion
that there either be voting mechanisms in place or allow non-public
utility transmission providers to participate in all aspects of
regional transmission planning without being allocated costs pursuant
to the regional cost allocation method. The enrollment process that we
are requiring here should address these concerns in part. Additionally,
as noted above, non-public utilities--including non-public utility
transmission providers that also are load-serving entities or have
other stakeholder interest in the regional transmission system--can
still participate as stakeholders in the regional transmission planning
process, even if they do not enroll in the regional transmission
planning process. As stakeholders, non-public utility transmission
providers will have an opportunity to express their views and concerns
as part of the process.
279. We clarify for Bonneville Power that the Commission in Order
No. 1000 did not require it, or any other non-public utility
transmission provider, to enroll or otherwise participate in a regional
transmission planning process. As discussed above, it will be
Bonneville Power's decision whether or not to enroll as a transmission
provider in a transmission planning region and become subject to that
region's cost allocation method. Additionally, with respect to
Bonneville Power's concerns regarding its perceived conflict between
its statutory authorities and Order No. 1000's cost allocation
requirements, we believe that any such perceived conflict is best
addressed in the first instance through participation in the
development of the regional transmission planning process and cost
allocation method that its neighboring public utilities will rely on to
comply with Order No. 1000.
280. We reaffirm Order No. 1000's statement that many public
utility transmission providers may need to make only modest changes to
their regional transmission planning processes to comply with Order No.
1000.\326\ Thus, if public utility transmission providers believe that
the regional transmission planning process in which they participate
already complies with the Order No. 890 transmission planning
principles, such as Ad Hoc Coalition of Southeastern Utilities'
statement that existing regional processes in the Southeast are in
compliance with the data exchange transmission planning principle, they
should make the case for such assertions in their Order No. 1000
compliance filings.
---------------------------------------------------------------------------
\326\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at n.142
(``[E]xisting regional transmission planning processes that many
utilities relied upon to comply with the requirements of Order No.
890 may require only modest changes to fully comply with these Final
Rule requirements.'').
---------------------------------------------------------------------------
281. In response to Transmission Dependent Utility Systems, we
reiterate our determination in Order No. 890 that public utility
transmission providers should provide sufficient information to
``enable customers, other stakeholders, or an independent third party
to replicate the results of planning studies and thereby reduce the
incidence of after-the-fact disputes regarding whether planning has
been conducted in an unduly discriminatory fashion.'' \327\ Thus, as we
stated in Order No. 890 and subsequent orders on compliance, public
utility transmission providers should provide the basic methodology,
criteria, and processes used to develop transmission plans sufficient
for stakeholders to be able to replicate its transmission plans, and
describe the methods it will use to disclose the criteria, data, and
assumptions that underlie its transmission system plans. The
information should be of sufficient detail to allow a customer to
replicate the results of the planning studies.\328\ Additionally, in
discussing the openness principle in Order No. 890, the Commission
required that ``transmission providers, in consultation with affected
parties, develop mechanisms, such as confidentiality agreements and
password-protected access to information, in order to manage
confidentiality and CEII concerns.'' \329\ Subject to our review of
public utility transmission providers' compliance filings, we believe
that these basic requirements should permit stakeholders to access and
review information that is relevant to transmission planning, while at
the same time protecting information that is commercially sensitive or
that is otherwise considered confidential under Commission
regulations.\330\
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\327\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 471.
\328\ Id.
\329\ Id. P 460.
\330\ The Commission has addressed the issue of access to
confidential material in Order No. 890 compliance proceedings. In
Entergy Services, Inc., 130 FERC ] 61,264, at PP 55-57 (2010), for
example, the Commission accepted compliance revisions proposed by
the Entergy Services, Inc. (Entergy) that would permit stakeholders
to be certified to obtain CEII material by following certain
procedures located on Entergy's Web site and the SIRPP Web site.
Further, the Commission accepted revisions that allowed stakeholders
to have access to resource-specific information if it was provided
in the SIRPP and was needed to participate in the SIRPP or to
replicate interregional studies. The Commission also found
acceptable provisions regarding processing requests for CEII data.
The Commission found that while Entergy and transmission owners had
broad discretion over this process, as some protestors argued, that
discretion was not unbounded because Entergy, its Independent
Coordinator of Transmission, and transmission owners would develop
procedures to review requests for access to CEII data, and
protestors could thus raise concerns during that development
process. The Commission noted that any party denied access to
information could raise objections through the dispute resolution
process.
---------------------------------------------------------------------------
282. Regarding Transmission Dependent Utility Systems' request that
the Commission confirm that information disclosure will not be deemed a
violation of the Standards of Conduct, we reiterate our determinations
on the transparency principle in Order No. 890, where we addressed
similar concerns about the Standards of Conduct. There, we stated that
the ``simultaneous disclosure of transmission planning information can
alleviate * * * Standards of Conduct
[[Page 32229]]
concerns.'' \331\ Further, Order No. 890 stated that ``transmission
providers should make as much transmission planning information
publicly available as possible, consistent with protecting the
confidentiality of customer information,'' noting that it will be
necessary for market participants ``to have access to basic
transmission planning information'' to consider future resource
options.\332\ These principles apply to the Order No. 1000 regional
transmission planning process. To the extent that an interested party
believes that necessary information is being unreasonably withheld for
unduly discriminatory purposes, we will review on a case-by-case basis.
---------------------------------------------------------------------------
\331\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 476 &
n.270.
\332\ Id. P 476.
---------------------------------------------------------------------------
283. With respect to questions about Order No. 1000's discussion as
to whether public utility transmission providers can use flexible
criteria or bright-line metrics when determining which transmission
facilities are in the regional transmission plan, we affirm that public
utility transmission providers, in consultation with stakeholders, may
apply either flexible criteria or bright-line metrics. As we explained
in Order No. 1000, the comments in the record indicated that flexible
criteria may be more appropriate than the bright-line metrics we had
previously required in one earlier decision.\333\ We leave it to public
utility transmission providers, in consultation with stakeholders, in
each transmission planning region to determine what type of criteria
they will use, consistent with Order No. 1000's overarching goal of
providing flexibility to meet regional needs. Thus, we clarify that we
were not necessarily endorsing flexible criteria over bright-line
criteria.
---------------------------------------------------------------------------
\333\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 223
(citing PJM Interconnection, L.L.C., 119 FERC ] 61,265 (2007)).
---------------------------------------------------------------------------
284. However, we reject PSEG Companies' argument that, by making
this decision, the Commission will introduce opaqueness and confusion
into the transmission planning process and that it will allow public
utility transmission providers to unofficially represent policymaking
bodies. We continue to find that there is merit in using a flexible
approach because it may capture certain transmission projects that
might be unnecessarily excluded with a bright-line approach. We believe
that this approach is reasonable, particularly in light of the many
comments that were supportive of a flexible approach. And, again, we
are not mandating such an approach, and proponents of bright-line
metrics can advocate for use of those metrics during the compliance
process. We also find PSEG Companies' argument that this approach would
allow public utility transmission providers to unofficially represent
policymaking bodies to be speculative and unsupported. We therefore
reject that argument. However, if PSEG Companies believe that, in a
specific case, that is the case, it may file a complaint under section
206.
285. In response to Illinois Commerce Commission, we decline to
establish a generic requirement in Order No. 1000 for the filing of
regional transmission plans with the Commission. We believe doing so is
unnecessary given the requirements of Order No. 1000, which requires
public utility transmission providers to participate in a regional
transmission planning process that produces a regional transmission
plan and complies with Order No. 890 transmission planning
principles.\334\ We will evaluate compliance filings to ensure that
public utility transmission providers satisfy these requirements, but
we do not see a need to mandate the additional requirement of filing
regional transmission plans that result from the regional transmission
planning process. Our concern is with ensuring that there is an open
and transparent regional transmission planning process. We are not
dictating substantive outcomes of that process.\335\
---------------------------------------------------------------------------
\334\ Id. P 146.
\335\ Id. P 113.
---------------------------------------------------------------------------
286. Similarly, we do not require under Order No. 1000 that public
utility transmission providers file with the Commission associated cost
allocation determinations. Again, we believe that this is unnecessary
under Order No. 1000. There, the Commission required public utility
transmission providers to have an ex ante cost allocation method on
file with and approved by the Commission.\336\ This cost allocation
method is required to 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. Customers,
stakeholders, and others have ``notice'' at the time the compliance
filings are made, when the Commission acts on those filings, and as the
open and transparent regional transmission planning process results in
the selection of a transmission facility in the regional transmission
plan for purposes of cost allocation. However, consistent with the
regional flexibility provided in Order No. 1000, 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.
---------------------------------------------------------------------------
\336\ Id. PP 499-500.
---------------------------------------------------------------------------
287. Moreover, we disagree with Illinois Commerce Commission that
the Commission is delegating authority to public utility transmission
providers. As discussed above, the Commission will evaluate compliance
filings to ensure that they comply with Order No. 1000 and 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.
288. We deny Transmission Access Policy Study Group's request for a
post-plan process to ensure transmission facilities are actually
constructed. As we explained in Order No. 1000, the package of
transmission planning and cost allocation reforms adopted is designed
to increase the likelihood that transmission facilities in regional
transmission plans will move from the planning stage to construction.
Additionally, as acknowledged by Transmission Access Policy Study
Group, a public utility transmission provider already is required to
make available information regarding the status of transmission
upgrades identified in transmission plans, including posting
appropriate status information on its Web site.\337\ To the extent that
an entity has undertaken a commitment to build a transmission facility
in a regional transmission plan, that information should be included in
such a posting.\338\ We continue to believe that this obligation,
together with the other reforms found in Order No. 1000, is adequate
without placing further obligations on public utility transmission
providers.
---------------------------------------------------------------------------
\337\ Id. P 159 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 472).
\338\ Id. P 159 & n.155.
---------------------------------------------------------------------------
289. Moreover, we are providing public utility transmission
providers, in consultation with stakeholders, the flexibility to design
a regional transmission planning process that meets regional needs. As
part of the stakeholder process to develop the regional transmission
planning processes in compliance with Order No. 1000, concerned
stakeholders have the ability to participate and seek changes to those
individual processes, subject to Commission review on compliance.
[[Page 32230]]
Additionally, we decline to prescribe specific timing parameters for
the Web site posting requirement that we directed in Order No.
1000.\339\ Again, if stakeholders would like to see such timing
requirements as part of the Web site postings, they may seek to do so
as part of the compliance process. However, the Web site postings
should provide the information we require in a complete and transparent
manner so that it will be fully accessible and useful to interested
stakeholders such that they can see the status of various transmission
facilities included in the regional transmission plan.
---------------------------------------------------------------------------
\339\ Id. P 159.
---------------------------------------------------------------------------
290. Regarding concerns about the role of state utility regulators
in the regional transmission planning process, we support states'
efforts to take an active role in the regional transmission planning
process and encourage proposals that seek to establish a formal role
for state commissions in the regional transmission planning process as
well as proposals to establish cost recovery for state regulators'
participation. However, for the reasons noted below, we will not
require one formal method for how states will participate in the
process.
291. We recognize that state utility regulators play an important
and unique role in transmission planning processes, given that the
states often have authority over transmission, permitting, siting, and
construction, and that many state regulatory commissions require
utilities to engage in integrated resource planning. We also expect
that state utility regulators will play an active role in working with
public utility transmission providers and other stakeholders in the
Order No. 1000 compliant regional transmission planning processes.
292. That being said, the Commission finds that it would be
premature in a generic proceeding to mandate any particular role for
state regulators in regional transmission planning processes. Instead,
we believe the best place for a state to determine the role it is to
play is in the Order No. 1000 compliance process that will develop a
regional transmission planning process that will be filed for
Commission review. This is appropriate because individual states can be
the best advocates for the role they wish to take in that process. For
example, in large, multistate regions, states may seek to join a
committee of state regulators that, in their view, may be a more
effective vehicle for collective action than any single state could do
individually. On the other hand, some states may feel that its best to
have a more independent role if, for example, they believe that joining
a formalized committee of state regulators may dilute their ability to
participate in the regional transmission planning process. Some states
may have a stronger interest in transmission planning issues than
others.
293. We understand and appreciate the concerns expressed by NARUC
and others that Order No. 1000 may appear to lump state utility
regulators with all other stakeholders. That was not the Commission's
intent. We understand that state regulators play a crucial role in
transmission planning and that the role of state regulators is unique
and distinctly different from the roles played by other stakeholders in
transmission planning. We agree with Wisconsin PSC that the differences
between state utility regulators and other stakeholders may well lead
to a regional transmission planning process to treat state utility
regulators differently than other stakeholders. However, for the
reasons discussed next, we decline to adopt the various suggestions
made by Wisconsin PSC and others to establish the same formal state
commission role in every transmission planning region through a generic
rulemaking proceeding, although all the regions are free to use the
same formal process for state participation if they choose to do so.
With respect to Illinois Commerce Commission's specific concerns about
the roles state regulators might be allowed to play consistent with
state law, we encourage it and other state regulators to raise such
concerns during the compliance process.
294. We are aware of the wide range of views expressed by state
utility commissions and others, both in rehearing petitions and
previously in comments on the Proposed Rule, regarding the appropriate
role of the states in regional transmission planning. Some state
commissions argue for a strong role in shaping regional transmission
plans, while others are concerned that their states' laws limit their
ability to participate in forming plans that may come before them in
regulatory proceedings. Respecting this range of views the Commission
believes that each state commission, or the state commissions
collectively in a region, is in the best position, in the first
instance and in consultation with the transmission providers subject to
their jurisdiction, to define the appropriate role for the state
commissions in a particular region. This role will take into account
the authorities and restrictions conferred by their own states'
statutes and their own policy preferences. Thus, the Commission
believes it would be inappropriate for us to define the role of all
state commissions in every regional transmission planning process in a
single generic proceeding, both because a state commission's authority
and responsibility is established by its own state's laws--not by this
Commission--and because a one-size-fits-all state role would not
accommodate the wide range of views expressed by state commissions.
295. Instead, we believe the best place to determine the role any
state commission plays is through the development of each region's
transmission planning process. This is appropriate because individual
state commissions can be the best advocates for the role they wish and
are able to play in that process. We believe that, in a multistate
region, the state commissions may want to establish a committee of
state regulators, which may be more effective by acting collectively
rather than individually. On numerous occasions, the Commission has
expressed strong support for such regional state committees, and we
continue to do so here. But we have not prescribed that states act
though regional state committees. Some state commissions may want an
independent role in regional transmission planning. Others may believe
they lack authority under their states' laws to engage in planning
facilities that are outside the state's borders. Finally, some states
may have a stronger interest in regional transmission planning issues
than others that simply have little interest in participating actively.
296. In response to Illinois Commerce Commission and Florida PSC's
concerns regarding funding for state regulator participation in the
regional transmission planning process, we affirm the approach taken in
Order No. 1000. This approach adopted Order No. 890's requirement that
public utility transmission providers propose a mechanism for recovery
of planning costs in their compliance filings, including relevant cost
recovery for state regulators, to the extent requested.\340\
Accordingly, we encourage public utility transmission providers to
engage respective state regulators regarding such provisions in their
compliance filings.
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\340\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 162
(quoting Order No. 890, FERC Stats. & Regs. ] 31,241 at n.339 & P
586).
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297. With respect to arguments raised by petitioners concerning
Order No. 1000's discussion of the role of merchant transmission
developers in the regional transmission planning
[[Page 32231]]
process, we deny rehearing. As the Commission found in Order No. 1000,
because a merchant transmission developer assumes all financial risk
for developing and constructing its transmission facility, it is
unnecessary to require such a developer to participate in a regional
transmission planning process for purposes of identifying the
beneficiaries of its transmission facility that would otherwise be the
basis for securing eligibility to use a regional cost allocation method
or methods. However, because a merchant developer's transmission
facility may nevertheless have an impact on a region's transmission
network, we will continue to require a merchant transmission developer
to provide adequate information and data, as explained in more detail
in Order No. 1000, to allow public utility transmission providers in
the transmission planning region to assess the potential reliability
and operational impacts of the merchant transmission developer's
proposed transmission facilities on other systems in the region. We
will allow public utility transmission providers in each transmission
planning region, in consultation with stakeholders, in the first
instance to propose what information would be required. Public utility
transmission providers should include these requirements in their
filings to comply with Order No. 1000.\341\
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\341\ Id. P 163.
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298. In response to APPA and Transmission Dependent Utility
Systems, we believe that by requiring merchant transmission developers
to provide information regarding their projects, including information
regarding reliability and operational impacts, public utility
transmission providers and stakeholders will have sufficient
information to analyze how a merchant transmission facility may impact
the transmission planning region. In short, we believe that Order No.
1000's information sharing requirement balances the need for public
utility transmission providers and stakeholders in transmission
planning regions to know about the impacts of potential merchant
transmission facilities in their regions with our view that it is
unnecessary to require a specific degree of participation by merchant
transmission developers in the regional transmission planning process
when they are not establishing a cost-based rate base to be allocated
to other beneficiaries of that facility.
299. We disagree with National Rural Electric Coops that we are
establishing a ``special'' class of public utilities by requiring
merchant transmission developers to comply only with an informational
requirement, rather than being subject to the full panoply of
requirements that will be applicable to all other public utility
transmission providers. However, it should be noted that merchant
transmission developers are those for which the costs of constructing
the proposed transmission facilities will be recovered through
negotiated rates instead of cost-based rates, so that this fact alone
serves to distinguish them from other developers.\342\ As noted above,
merchant transmission developers are not seeking to allocate the costs
associated with their merchant transmission facilities to other
entities. Thus, we affirm our decision in Order No. 1000.
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\342\ Id. P 119.
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300. We also decline Transmission Dependent Utility Systems'
request that we clarify that merchant transmission developers not
participating in the regional transmission planning process should be
obligated to internalize the costs of any adverse reliability effects
on the grid posed by its transmission facility or any need for upgrades
caused by a change in power flows. Every new facility affects the
facilities around it, whether it is a merchant facility or a cost-based
facility, just as the actions of one region may have positive or
negative affects on neighboring regions. A generic proceeding on
internalizing the costs of all new facilities, whether merchant or
otherwise, is beyond the scope of Order No. 1000, and may not be suited
for a blanket determination in any generic proceeding as such a
determination would likely require an evaluation of the specific facts
and circumstances of each particular new facility. The Commission
reiterates, however, that Order No. 1000 provides that a merchant
transmission developer has to pay for upgrades on neighboring
systems.\343\
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\343\ Id. P 165.
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301. Finally, in response to those petitioners seeking
clarification of what constitutes a ``new'' transmission facility, we
will affirm the Commission's approach taken in Order No. 1000.\344\
Order No. 1000 purposely does not define what type of evaluation or
reevaluation of transmission facilities needs to occur to determine
whether a previously approved facility may be subject to Order No.
1000. That is because we understand that different transmission
planning regions may use different processes based on their unique
needs and characteristics. We intentionally did not prescribe what such
an evaluation or reevaluation must look like, and we leave it to public
utility transmission providers, in consultation with stakeholders, to
develop proposals addressing this issue as part of their Order No. 1000
compliance filings. If a stakeholder believes that these proposals are
unduly discriminatory or preferential (e.g., they favor incumbent
transmission owners to the detriment of nonincumbent transmission
developers), it should raise these concerns during the development of
the Order No. 1000 compliance filing and, if it is not successful at
that stage, it may raise the issue before the Commission after the
compliance filing is submitted. For these reasons, we decline to
provide the clarifications requested by Western Independent
Transmission Group and LS Power.
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\344\ Id. P 65.
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3. Consideration of Transmission Needs Driven by Public Policy
Requirements
a. Final Rule
302. Order No. 1000 directed public utility transmission providers,
in consultation with stakeholders, to amend their OATTs to describe
procedures that provide for the consideration of transmission needs
driven by Public Policy Requirements in the local and regional
transmission planning processes.\345\ By considering transmission needs
driven by Public Policy Requirements, the Commission explained that it
meant: (1) The identification, with stakeholders, of transmission needs
driven by Public Policy Requirements; and (2) the evaluation of
potential solutions, including those proposed by stakeholders, to meet
those needs.\346\ The Commission emphasized that it would allow local
and regional flexibility in designing these procedures.\347\
Additionally, to ensure that requests to include transmission needs are
reviewed in a fair and non-discriminatory manner, Order No. 1000
required public utility transmission providers to post on their Web
sites an explanation of which transmission needs driven by Public
Policy Requirements will be evaluated for potential solutions in the
local or regional transmission planning process, as well as an
explanation of why other suggested transmission needs will not
[[Page 32232]]
be evaluated.\348\ The Commission further explained that Order No. 1000
did not establish an independent requirement to satisfy such Public
Policy Requirements such that the failure of a public utility
transmission provider to comply with a Public Policy Requirement
established under state law would constitute a violation of its
OATT.\349\
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\345\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 203.
\346\ Id. PP 205-11.
\347\ Id. P 208.
\348\ Id. P 209.
\349\ Id. P 213.
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303. The Commission did not require public utility transmission
providers to consider in the local and regional transmission planning
processes any transmission needs that go beyond those driven by state
or federal laws or regulations or to specify additional public policy
principles or public policy objectives.\350\ However, the Commission
reiterated and clarified that Order No. 1000 does not preclude any
public utility transmission provider from considering in its
transmission planning process transmission needs driven by additional
public policy objectives not specifically required by state or federal
laws or regulations.\351\
---------------------------------------------------------------------------
\350\ Id. P 214.
\351\ Id. P 216.
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b. Requests for Rehearing and Clarification
304. Several petitioners filed requests for rehearing and
clarification regarding Order No. 1000's requirement that public
utility transmission providers include in their OATTs language
providing for the consideration of transmission needs driven by Public
Policy Requirements. Some petitioners assert that the Commission has
not spelled out with sufficient detail what is required of public
utility transmission providers.\352\ ELCON, AF&PA, and the Associated
Industrial Groups, as well as PSEG Companies, contend that Order No.
1000 provides virtually no practical guidance as to how disparate state
policies are to be reconciled. PSEG Companies also contend that the
Commission's reforms may undermine competitive wholesale energy markets
by driving market outcomes, explaining that predictions about
generation additions and retirements that will occur in a competitive
market are too speculative for a transmission provider to rely upon
and, if a transmission provider were to make such judgments, then it
would be a market maker or market influencer.
---------------------------------------------------------------------------
\352\ See, e.g., Coalition for Fair Transmission Policy; ELCON,
AF&PA, and the Associated Industrial Groups; and PSEG Companies.
---------------------------------------------------------------------------
305. Ad Hoc Coalition of Southeastern Utilities is concerned that
Order No. 1000's public policy planning requirements will be confusing
and counterproductive and are likely to result in skewed decision-
making. Coalition for Fair Transmission Policy argues that any
construct of benefits associated with public policy-driven transmission
projects would require speculation and deviate from industry norms that
use models to project system conditions and dynamics for planning
purposes. Long Island Power Authority argues that the process for
identifying transmission needs driven by Public Policy Requirements is
incomplete because it is necessary to identify what parties are subject
to the Public Policy Requirements and whether such parties have a need
for a transmission solution to meet those requirements.
306. Sacramento Municipal Utility District explains that current
transmission planning processes take into account state renewable
energy goals, adding that, to the extent that Public Policy
Requirements spur development of new projects that create demand for
new transmission, such projects would be incorporated into existing
planning processes, even if those processes do not expressly reference
the Public Policy Requirement that created the demand. Ad Hoc Coalition
of Southeastern Utilities argue that Order No. 1000 fails to account
for the fact that, at least in the Southeast, existing practices take
into account Public Policy Requirements.
307. A number of petitioners seek rehearing or clarification on
several other issues related to Order No. 1000's requirement that local
and regional transmission planning processes consider transmission
needs driven by Public Policy Requirements. APPA, for example, seeks
clarification that the term ``Public Policy Requirements'' is intended
to include duly enacted laws, ordinances, and regulations passed by
units of state and local government regulating public power systems,
such as city councils, utility district boards, and other governing
bodies. MISO Northeast argues that the Commission should limit the
definition of ``Public Policy Requirements'' to those requirements that
create transmission-related benefits.
308. AEP seeks clarification that transmission providers are
required to include specific, evaluated solutions to all transmission
needs in the transmission plan, explaining that it is concerned that
transmission providers may simply identify possible solutions to needs
driven by Public Policy Requirements without including solutions that
address such needs in an actionable transmission plan. As an example,
AEP states that PJM is considering the ``FYI to Market'' approach,
where PJM identifies projects that might respond to certain public
policy needs and lets the market determine, without any PJM
involvement, which projects are built.
309. Southern Companies contend that Order No. 1000's requirement
that transmission needs driven by Public Policy Requirements must be
considered in transmission planning processes is vague. Specifically,
they claim that Order No. 1000's directive that public utility
transmission providers post on their Web sites an explanation of which
public policy considerations are and are not considered in the
transmission planning process is impermissibly vague and overbroad. In
support, Southern Companies explain that their native load has numerous
federal and state legal requirements driving their load projections.
310. American Transmission seeks clarification on issues related to
Order No. 1000's direction that the consideration of transmission needs
driven by Public Policy Requirements applies to local, as well as
regional, transmission planning processes. American Transmission seeks
clarification that it is necessary and appropriate for it to amend its
local planning process to include provisions for public policy-driven
transmission projects.\353\ It explains that it is a transmission-
owning member of MISO, which has a Commission-approved regional
planning process, but that it also has a Commission-approved local
planning process, through which transmission projects are identified
and included in the Midwest ISO MTEP process.
---------------------------------------------------------------------------
\353\ American Transmission at 8-9 (citing what it terms as an
inconsistency between paragraph 203 and footnote 185 of Order No.
1000).
---------------------------------------------------------------------------
311. While others raise concerns about the reach of Order No. 1000
on this issue, AWEA argues that transmission planners should be
required to do more than ``consider'' state and federal requirements,
stating that the Commission recognized that when a transmission
provider focuses only on the needs of its franchised or contract-load
customers, it creates opportunities for undue discrimination. It
suggests that the Commission require transmission providers to
undertake scenario studies to plan and direct the build-out of the
transmission system for those entities with signed interconnection
agreements. It also suggests that the Commission require that scenarios
account for transmission that may be necessary to accommodate
[[Page 32233]]
individual or multiple RPS requirements or other state and federal
requirements, and that transmission providers then would present these
analyses to stakeholders and include recommended projects and
anticipated costs under each scenario. Otherwise, it seeks
clarification regarding the following: (1) That transmission providers
must actively address public policy considerations within their local
and regional planning processes; (2) the requirements imposed on
transmission providers in meeting the requirement to consider public
policy goals; and (3) that a transmission provider has an independent
duty to identify needs, rather than being passive if no participant
raises any concerns or needs.
312. Some petitioners raise concerns that the requirements will put
transmission planners into the role of policymakers. Coalition for Fair
Transmission Policy argues that, under the top-down planning permitted
in Order No. 1000, the regional planning group would be placed in the
position of making decisions that affect how utilities and other
entities with the responsibility to meet Public Policy Requirements
would meet those requirements. Coalition for Fair Transmission Policy
asserts that Order No. 1000 thus authorizes submission of regional
transmission planning processes that would reduce those with public
policy obligations and state regulators to mere stakeholders in the
regional transmission planning process. It argues that, with respect to
transmission needs driven by Public Policy Requirements, regional
transmission plans can be developed only through a bottom-up process.
PPL Companies argue that requiring Public Policy Requirements in the
transmission planning process could become a justification to unduly
discriminate against ``non-renewable'' generation, which would violate
the Commission's open access policies. They also assert that, to the
extent public utility transmission providers are mandated to consider
transmission needs driven by Public Policy Requirements in local and
regional transmission planning processes, the Commission should clarify
that such considerations need not, and cannot, trump the FPA's
requirement that rates be just and reasonable.
313. Transmission Access Policy Study Group raises a similar
concern, pointing to Order No. 1000's statement regarding the
consideration of public policy goals not codified in laws and
regulations. Florida PSC argues that provisions allowing transmission
providers to consider additional public policy objectives not
specifically required by state or federal laws or regulations should be
struck. Instead, Florida PSC argues that transmission planning
decisions should be based on meeting the policy requirements of state
and federal law. It also states that it is unclear whether there will
be enough flexibility to adjust planning decisions to respond to
changes in uncodified public policies. Transmission Access Policy Study
Group believes that allowing public utility transmission providers to
consider such goals would allow them to substitute their own agenda for
that of state and federal legislatures and regulators.
314. Transmission Access Policy Study Group raises the example that
a public utility transmission provider's definition of a ``public
policy'' may be influenced by the potential for incentive rate recovery
or that it may define ``public policy'' to advance its own generation
interests. It claims that, despite Order No. 1000's statement that
public utility transmission providers always had the ability to plan
for any transmission system needs that it foresees, public utility
transmission providers in non-RTO regions have never before been
authorized to allocate costs for transmission projects aimed at policy
objectives not grounded in law or regulation.\354\ It argues that
planning for these goals should be grounded in terms of satisfying
needs identified by load-serving entities, and requests that the
Commission at least provide guidance that any plans developed based on
public utility transmission providers' own public policy vision should
be structured to ensure their usefulness by supporting multiple likely
power supply scenarios should the original vision prove faulty. It
believes this approach is more rational for integrating public policies
into the planning process and will help focus planning on constructing
broadly supported upgrades needed under multiple potential power supply
and public policy scenarios.\355\
---------------------------------------------------------------------------
\354\ Transmission Access Policy Study Group also cites to Order
No. 1000's reference to PJM's inability to go beyond specific
interconnection requests in its planning mechanism as a reason for
requiring the consideration of transmission needs driven by Public
Policy Requirements, claiming that this shows that the authorization
to go beyond public policies embodied in state or federal laws or
regulations may not be the status quo in some RTO regions.
\355\ Transmission Access Policy Study Group at 18-19 (citing
the CapX 2020 project, planning processes in MISO and New England,
and California ISO's ``least regrets'' planning criteria).
---------------------------------------------------------------------------
315. Some state electric regulatory agencies are concerned about
the role they will play in the process to identify and evaluate
transmission needs driven by Public Policy Requirements.\356\ Illinois
Commerce Commission asserts that the Commission should have clarified
that, when state commissions in a region, either acting individually or
via committee, decide that a unique role or special weight should be
given to state authorities in the regional planning process regarding
the consideration of transmission needs driven by Public Policy
Requirements, then the transmission provider should be required by the
Commission to defer to that decision. It maintains that by leaving the
role of state authorities in the regional planning process up to the
transmission providers, the Commission allows for the possibility that
transmission providers can thwart the will of regionally organized
state authorities. It also seeks clarification that the ``committee of
regulators'' envisioned for the purpose of identifying transmission
needs driven by Public Policy Requirements would not need to consist
solely of personnel employed by state regulatory commissions, but could
include other state authorities as well. It further seeks clarification
that the engagement of such a committee will be at the discretion of
the regional state committee, not at the transmission provider's
discretion. It asks that the Commission clarify how its statement that
authorizes use of ``a committee of state regulators'' to ``identify
those transmission needs for which potential solutions will be
evaluated in the transmission planning processes'' fits with the
requirement that public utility transmission providers ``have in place
processes that provide all stakeholders the opportunity to provide
input into what they believe are transmission needs driven by Public
Policy Requirements.''
---------------------------------------------------------------------------
\356\ See, e.g., Illinois Commerce Commission; and New York PSC.
---------------------------------------------------------------------------
316. Similarly, New York PSC requests clarification that when state
regulators play a formal role in the planning process, their
determinations regarding transmission needs driven by state public
policies will be entitled to deference.
c. Commission Determination
317. We affirm Order No. 1000's reforms regarding the consideration
of transmission needs driven by Public Policy Requirements. We
recognize that Order No. 1000 could have been more clear regarding what
the Commission intended, as evidenced by many of the petitioners'
arguments suggesting that Order No. 1000 requires the
[[Page 32234]]
consideration of Public Policy Requirements themselves, which is not
the case. In this section, we clarify what the Commission intended by
these reforms. We believe that these clarifications will be helpful in
dispelling some of the misconceptions about this requirement that
appear in many of the petitioners' requests for rehearing and
clarification.
318. Order No. 1000 requires that public utility transmission
providers amend their OATTs to provide for the consideration of
transmission needs driven by Public Policy Requirements. Order No. 1000
did not require that Public Policy Requirements themselves be
considered. This is a critical distinction. As discussed more fully
below in response to requests for rehearing on this issue, we are not
placing public utility transmission providers in the position of being
policymakers or allowing them to substitute their public policy
judgments in the place of legislators and regulators. Transmission
needs driven by Public Policy Requirements, and not the Public Policy
Requirements themselves, are what must be considered under Order No.
1000.
319. First, we discuss the elements of Order No. 1000's requirement
regarding the consideration of transmission needs driven by Public
Policy Requirements. Order No. 1000 defined ``Public Policy
Requirements'' as public policy requirements established by state or
federal laws and regulations.\357\ Order No. 1000 explained that
``state or federal laws and regulations'' means ``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.'' \358\ We grant APPA's clarification
that Public Policy Requirements established by state or federal laws or
regulations includes duly enacted laws or regulations passed by a local
governmental entity, such as a municipal or county government. This is
the intent of the word ``within'' in Order No. 1000's explanation that
``state or federal laws or regulations,'' meant ``enacted statutes * *
* and regulations promulgated by a relevant jurisdiction, whether
within a state or at the federal level.'' \359\ In response to MISO
Northeast, we will not revise the definition of Public Policy
Requirements to limit it to those that provide transmission-related
benefits. Order No. 1000 does not require the consideration of Public
Policy Requirements: Rather, it requires the consideration of
transmission needs driven by Public Policy Requirements. We also will
not exclude any particular state or federal law or regulation from the
definition of Public Policy Requirements.
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\357\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 2.
\358\ Id.
\359\ Id. (emphasis added).
---------------------------------------------------------------------------
320. Next, we discuss another key component of Order No. 1000's
requirement, namely, the term ``consideration'' in reference to the
requirement that public utility transmission providers amend their
OATTs to provide for the consideration of transmission needs driven by
Public Policy Requirements. By ``consideration,'' Order No. 1000
explained that this included: (1) The identification of transmission
needs driven by Public Policy Requirements; and (2) the evaluation of
potential solutions to meet those identified needs.\360\ Order No. 1000
further explained that, with respect to the identification of
transmission needs driven by Public Policy Requirements, the process
must permit stakeholders with an opportunity to provide input and offer
proposals regarding the transmission needs that they believe should be
so identified.\361\ Order No. 1000 also stated that not every suggested
need will be identified such that solutions for the need will be
evaluated.\362\ In response to AEP, we reiterate that Order No. 1000
provides only that public utility transmission providers must consider
transmission needs driven by Public Policy Requirements. Order No. 1000
does not require that every potential transmission need proposed by
stakeholders must be selected for further evaluation. We find that this
approach is a fair balance that allows interested stakeholders to
submit their views on what is driving their transmission needs while
allowing the process itself determine what transmission needs are
identified for which solutions must be evaluated.
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\360\ Id. P 205.
\361\ Id. P 209.
\362\ Id.
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321. Similarly, in response to AWEA, we are not requiring anything
more than what we directed in Order No. 1000, namely, the two-part
identification and evaluation process. As with other Order No. 1000
transmission planning reforms, our concern is that the process allows
for stakeholders to submit their views and proposals for transmission
needs driven by Public Policy Requirements in a process that is open
and transparent and satisfies all of the transmission planning
principles set out in Order Nos. 890 and 1000, and that there is a
record for the Commission and stakeholders to review to help ensure
that the identification and evaluation decisions are open and fair, and
not unduly discriminatory or preferential. However, we reiterate that
not every proposal by stakeholders during the identification stage will
necessarily be identified for further evaluation. The OATT revisions
that public utility transmission providers submit as part of their
Order No. 1000 compliance filings will set forth the process for
permitting stakeholders to provide input and for determining which
proposed transmission needs will be identified for evaluation.
322. We are also not prescribing how active a public utility
transmission provider should itself be in identifying transmission
needs driven by Public Policy Requirements, although it certainly may
take a more proactive approach if it, in consultation with its
stakeholders, so chooses. Even if a public utility transmission
provider takes a less active approach on this issue, our expectation is
that interested stakeholders will participate and suggest transmission
needs driven by Public Policy Requirements.\363\ An open and
transparent transmission planning process will identify those
transmission needs that should be evaluated, regardless of whether they
are suggested by the public utility transmission provider or by an
interested stakeholder.
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\363\ We emphasize that, although a public utility transmission
provider is not obligated to proactively identify transmission needs
driven by Public Policy Requirements, it still must consider the
transmission needs driven by Public Policy Requirements raised by
other stakeholders in the transmission planning process.
---------------------------------------------------------------------------
323. In response to Coalition for Fair Transmission Policy, we
recognize that consideration of transmission needs driven by Public
Policy Requirements could create challenges in defining beneficiaries,
but we fail to see how these challenges are appreciably different from
those involved in determining beneficiaries of reliability or economic
projects. In those cases as well, the determination of beneficiaries
will often turn on informed forecasts or predictions regarding future
needs and demands to be placed on the transmission system. In fact,
given that the Commission is only requiring the consideration of
transmission needs driven by Public Policy Requirements that are
established by state or federal laws or regulations,\364\ it may very
well be the case that the determination of beneficiaries of
transmission facilities to
[[Page 32235]]
address transmission needs driven by Public Policy Requirements is
easier to define than for other types of transmission facilities. In
any event, we want public utility transmission providers, in
consultation with stakeholders, to make those determinations in the
first instance. We also disagree with Coalition for Fair Transmission
Policy's argument that these reforms can only be implemented through
bottom-up transmission planning. Coalition for Fair Transmission Policy
has not persuaded us that these reforms cannot be implemented through
either a ``top-down'' or ``bottom up'' process, particularly given the
significant flexibility we are providing to public utility transmission
providers to comply with these requirements.
---------------------------------------------------------------------------
\364\ As discussed above, the Commission clarifies that this
requirement was meant to include local laws or regulations as well.
---------------------------------------------------------------------------
324. Regarding American Transmission's request for clarification,
we note that in Order No. 1000, footnote 185, we stated that ``[t]o the
extent public utility transmission providers within a region do not
engage in local transmission planning, such as in some ISO/RTO regions,
the requirements of this Final Rule with regard to Public Policy
Requirements apply only to the regional transmission planning
process.'' \365\ That statement only applies to public utility
transmission providers that do not engage in local transmission
planning. If a public utility transmission provider does engage in
local transmission planning, regardless of whether or not it is in an
ISO/RTO region, then the requirements of Order No. 1000 regarding
Public Policy Requirements apply to both the local and regional
transmission planning processes. Therefore, if American Transmission
engages in local and regional transmission planning, then it must
revise its local transmission planning process to reflect this aspect
of Order No. 1000.
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\365\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at n.185.
---------------------------------------------------------------------------
325. Southern Companies find the requirement that public utility
transmission providers post on their Web sites an explanation of which
transmission needs have been identified for evaluation and an
explanation of why other suggested transmission needs will not be
evaluated to be vague and overbroad. We clarify as follows. Public
utility transmission providers are not required to research and post on
their Web sites what they perceive to be every transmission need that
is conceivably driven by a Public Policy Requirement and then explain
why it will not evaluate each one. Public utility transmission
providers are only obligated to (a) post an explanation of those
transmission needs driven by Public Policy Requirements that have been
identified for evaluation and (b) post an explanation of how other
transmission needs driven by Public Policy Requirements introduced by
stakeholders were considered during the identification stage and why
they were not selected for further evaluation. For example, if public
utility transmission providers or stakeholders in a transmission
planning region submit what they believe are ten transmission needs
driven by Public Policy Requirements, and five of those ten are
identified for evaluation, then the public utility transmission
providers must (a) post an explanation of why the five were evaluated
and (b) post an explanation of why the other five were not evaluated.
326. Having provided additional clarifications and information as
to what Order No. 1000 does require, i.e., the consideration of
transmission needs driven by Public Policy Requirements, we now turn to
discussing what Order No. 1000 does not require, i.e., the
consideration of Public Policy Requirements themselves, as well as
otherwise allowing public utility transmission providers to become
policymakers, as some petitioners appear to believe. Order No. 1000
does not require public utility transmission providers to amend their
OATTs to provide for the consideration of Public Policy Requirements.
Nor do we believe that anything in Order No. 1000's reforms on this
issue will lead to that outcome.
327. It is not the function of the transmission planning process to
reconcile state policies. If the utilities in one state are required,
for example, to procure wind resources and the utilities in another
state are required to shut down old fossil units and construct new
fossil units, it is not the transmission providers' function to decide
on the merits of these federal or state requirements or to decide
between wind and coal resources. It is their function to help both sets
of utilities comply with the laws they each face by considering in the
transmission planning process, but not necessarily including in the
regional transmission plan, the new transmission facilities needed by
both sets of utilities to meet their obligations, and also to determine
if these diverse objectives can be met more efficiently or cost-
effectively through regional transmission planning than through
individual utility planning.
328. Additionally, in establishing this process, we are not
requiring public utility transmission providers to make any substantive
determinations as to what Public Policy Requirements may qualify under
these reforms or to identify them in their OATTs. If they choose to do
so, then such proposals must be vetted through the local and regional
transmission planning process, as discussed in Order No. 1000.
329. For these reasons, we reject assertions that we are allowing
public utility transmission providers to assume the role of policymaker
in their transmission planning processes with respect to considering
transmission needs driven by Public Policy Requirements. We also
disagree with Ad Hoc Coalition of Southeastern Utilities that these
reforms may lead to skewed decision-making. Our intent is to help
develop a path to allow public utility transmission providers to
consider transmission needs driven by Public Policy Requirements, just
as they consider reliability-driven and economic-driven transmission
needs, but we are not mandating that any particular transmission
facility identified to address identified transmission solutions be
built.
330. Further, we disagree with PSEG Companies' argument that, by
requiring the development of a process, we are somehow getting ahead of
the states' own public policy efforts. Nothing in the development of
this process preempts or conflicts with state-level public policy
efforts. Indeed, Order No. 1000 and state-level Public Policy
Requirements should be complementary--Order No. 1000's intent is to
establish a space in the transmission planning process to identify
transmission needs driven by Public Policy Requirements and to evaluate
potential solutions to identified needs.
331. We also decline to require that regional transmission plans
support multiple likely power supply scenarios should a region's public
policy vision not come to fruition, as requested by Transmission Access
Policy Study Group. It may well be the case that evaluating different
power supply scenarios will be an effective way of identifying 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. Stakeholders may advocate for such a requirement in
the development of Order No. 1000 compliance filings and, to the extent
such language is included in the
[[Page 32236]]
compliance filing, the Commission will consider that language.\366\
---------------------------------------------------------------------------
\366\ Similarly, we will not require the adoption of a ``least
regrets'' process or processes that resulted in the development of
transmission projects such as the CapX2020 project; however, the
public utility transmission providers in each region are free to
develop such processes and submit them in their compliance filing
for Commission consideration.
---------------------------------------------------------------------------
332. Just as Order No. 1000 did not intend for public utility
transmission providers to consider Public Policy Requirements, Order
No. 1000 also does not convert public utility transmission providers
into policymakers with respect to the consideration of public policy
objectives that are not codified in federal or state laws or
regulation. On this matter, Order No. 1000 stated: ``[T]he Final Rule
does not preclude any public utility transmission provider from
considering in its transmission planning process transmission needs
driven by additional public policy objectives not specifically required
by state or federal regulations.'' \367\ Some petitioners expressed
alarm that we are permitting public utility transmission providers to
become policymakers and substitute their policy judgments in place of
legislators and regulators. This was not our intent, and we take this
opportunity to provide some clarifications on this matter.
---------------------------------------------------------------------------
\367\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 216.
---------------------------------------------------------------------------
333. We reiterate the observations we made in Order No. 1000. A
public utility transmission provider ``has, and always had, the ability
to plan for any transmission system needs that it foresees. Our
recognition of this ability is not intended to limit or expand in any
way the option that a public utility transmission provider has always
had to plan for facilities that it believes are needed if it chooses to
do so.'' \368\ All this statement was intended to convey was that, even
absent the requirements in Order No. 1000, public utility transmission
providers take a number of different factors into account in developing
their transmission plans. While Order No. 1000 established a
requirement for certain factors that must be considered in transmission
planning, as the quoted sentence states, it does not expand what public
utility transmission providers have always been entitled to do. If, for
example, a state law that has been identified as a Public Policy
Requirement requires utilities to meet a 10 percent renewable portfolio
standard and that state's governor urges them to meet a 20 percent
standard, Order No. 1000 requires consideration of transmission needed
to meet the 10 percent but neither requires utilities to, nor prohibits
them from, considering a 20 percent standard, as some petitioners
apparently urge us to do.
---------------------------------------------------------------------------
\368\ Id. (emphasis added).
---------------------------------------------------------------------------
334. Order No. 1000 concluded that it is appropriate to require
public utility transmission providers, in consultation with
stakeholders, to design the appropriate procedures for identifying and
evaluating the transmission needs that are driven by Public Policy
Requirements in their area, subject to guidance the Commission provided
in Order No. 1000 and our review on compliance.\369\ Additionally, in
response to Long Island Power Authority, we anticipate that the process
for identifying transmission needs driven by Public Policy Requirements
can identify what parties are subject to the Public Policy Requirements
and whether such parties have a need for a transmission solution to
meet those requirements.
---------------------------------------------------------------------------
\369\ Id. P 208.
---------------------------------------------------------------------------
335. With respect to the contention raised by Sacramento Municipal
Utility District, Ad Hoc Coalition of Southeastern Utilities, and
others that existing transmission planning processes already account
for state renewable energy goals, we note that we are not endorsing,
nor does the Public Policy Requirement include, any particular state or
federal law or regulation as special or ``preferred.'' Further, as we
have noted elsewhere, we understand that some regions may already be in
compliance with many of the requirements of Order No. 1000 and thus may
need to make only modest changes to comply. Compliance filers must
explain how their process gives all stakeholders a meaningful
opportunity to submit what they believe are transmission needs driven
by Public Policy Requirements, and allow an open and transparent
transmission planning process to determine whether to move forward
regarding those needs.
336. Further, we disagree that we have not justified this reform
generically, as suggested by Ad Hoc Coalition of Southeastern
Utilities, which argues that there is no need for this reform in the
Southeast. As discussed above and in Order No. 1000, we concluded that
there was a need for the Commission to act under FPA section 206 to
remedy a deficiency that we found in existing transmission planning
processes. There was no formal requirement for public utility
transmission providers to consider transmission needs driven by Public
Policy Requirements, despite the fact that the record indicates that in
recent years there has been significant activity at the federal and
state levels in enacting laws and regulations that will potentially
impact transmission needs.\370\ The lack of a formal requirement in
public utility transmission providers' OATTs to address this issue is,
in our view, unjust, unreasonable, and unduly discriminatory.\371\ We
affirm our conclusion that these reforms are necessary on a nationwide
basis.
---------------------------------------------------------------------------
\370\ See, e.g., Order No. 1000, FERC Stats. & Regs. ] 31,323 at
PP 45-47.
\371\ Id. PP 82-83. See also discussion supra at section II.C
(explaining need for Order No. 1000's reforms).
---------------------------------------------------------------------------
337. Finally, some state regulators question their role in this
process. We agree with petitioners that state regulators play an
important and unique role in the transmission planning process, given
their oversight over transmission siting, permitting, and construction,
as well as integrated resource planning and similar processes.
Additionally, they may be in the best position of determining how
state-level public policy requirements are satisfied. Nonetheless, for
the reasons discussed fully above, the Commission will not require as
part of this generic rulemaking proceeding a particular status for
state regulators in the transmission planning process.\372\ To do so
would ignore the wide range of roles that state regulators themselves
tell us that they are permitted to take under their various state laws.
---------------------------------------------------------------------------
\372\ See discussion supra at section III.A.2.
---------------------------------------------------------------------------
338. However, as we also explained in Order No. 1000 and above, our
expectation is that state regulators should play a strong role and that
public utility transmission providers will consult closely with state
regulators to ensure that their respective transmission planning
processes are consistent with state requirements. We believe this will
be particularly true in the case of state-level Public Policy
Requirements, where state regulators are likely to have unique insights
as to how transmission needs driven by those state-level Public Policy
Requirements should be satisfied. Thus, we leave it to state regulators
and public utility transmission providers, in consultation with
stakeholders, in each transmission planning region to determine the
appropriate role of state regulators in the transmission planning
process generally and in the consideration of transmission needs driven
by Public Policy Requirements in particular.
339. In response to Illinois Commerce Commission, we are not
prescribing how any committee of state regulators should be comprised.
We note that existing committees of state regulators have been
effective representatives of
[[Page 32237]]
state regulators, and any region that wants to form such a committee
may want to look to these and other similar organizations in other
regions of the country as possible models for organizing its own
similar committees for purposes of regional transmission planning under
Order No. 1000.
B. Nonincumbent Transmission Developers
340. This section of Order No. 1000 addressed the removal from
Commission-jurisdictional tariffs and agreements of provisions that
contain a federal right of first refusal \373\ 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 to be evaluated by public utility transmission providers in
the regional transmission planning process. The Commission further
required that the developer of any transmission facility selected in
the regional transmission plan have a comparable opportunity to
allocate the cost of such transmission facility through a regional cost
allocation method or methods.\374\
---------------------------------------------------------------------------
\373\ We continue to use the phrase ``federal right of first
refusal'' to refer only to rights of first refusal that are created
by provisions in Commission-jurisdictional tariffs or agreements.
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 253 n.231.
\374\ Id. P 225.
---------------------------------------------------------------------------
1. Legal Authority
a. Final Rule \375\
---------------------------------------------------------------------------
\375\ We address legal arguments related to the need for our
nonincumbent transmission developer reforms in the ``Need for
Reform'' discussion. See discussion supra at section 0.
---------------------------------------------------------------------------
341. In Order No. 1000, the Commission found that a federal right
of first refusal is, in the language of FPA section 206, a ``rule,
regulation, practice, or contract'' affecting the rates for
jurisdictional transmission service. The Commission further stated that
under section 206 when the Commission finds that such rules,
regulations, practices, or contracts are unjust, unreasonable, unduly
discriminatory, or preferential, it must determine by order the just
and reasonable rate, charge, classification, rule, regulation,
practice, or contract to be thereafter observed and in force. The
Commission concluded that because federal rights of first refusal in
favor of incumbent transmission providers deprive customers of the
benefits of competition in transmission development, and associated
potential savings, these federal rights of first refusal affect the
rates for jurisdictional transmission service, and so the Commission
was compelled under FPA section 206(a) to take corrective action. The
Commission also stated that federal rights of first refusal create
opportunities for undue discrimination and preferential treatment
against nonincumbent transmission developers within existing regional
transmission planning processes, and noted that it has a responsibility
to consider anticompetitive practices and eliminate barriers to
competition.\376\
---------------------------------------------------------------------------
\376\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 286.
---------------------------------------------------------------------------
342. The Commission noted that nothing in Order No. 1000 is
intended to limit, preempt, or otherwise affect state or local laws or
regulations with respect to construction of transmission facilities,
including, but not limited, to authority over siting or permitting of
transmission facilities. The Commission therefore determined that its
reforms regarding elimination of federal rights of first refusal from
Commission-jurisdictional tariffs and agreements are not prevented or
otherwise limited by the FPA. The Commission also explained that in
directing the removal of a federal right of first refusal from
Commission-jurisdictional tariffs and agreements, it is not ordering
public utility transmission providers to enlarge their transmission
facilities under sections 210 or 211 of the FPA, nor making findings
related to its authorities under section 215 or 216.
343. The Commission also stated that, while a public utility
transmission provider may have accepted an obligation to build in
relation to its membership in an RTO/ISO, the Commission did not
believe that obligation is necessarily dependent on the incumbent
transmission provider having a corresponding federal right of first
refusal to prevent others from constructing and owning new transmission
facilities in that region.\377\ The Commission stated that, while
implementing these reforms may change the package of benefits and
burdens in place for transmission owning members of RTOs/ISOs, such
changes are necessary to correct practices that may be leading to
unjust and unreasonable rates.\378\
---------------------------------------------------------------------------
\377\ Id. P 261.
\378\ Id.
---------------------------------------------------------------------------
344. Finally, the Commission declined to address the merits of
comments arguing that section 3.09 of the ISO New England Transmission
Operating Agreement establishes a federal right of first refusal that
can be modified only if the Commission meets the Mobile-Sierra public
interest standard, explaining that it was more appropriate to address
this issue as part of the proceeding on ISO New England's compliance
filing.\379\
---------------------------------------------------------------------------
\379\ Id. P 292.
---------------------------------------------------------------------------
b. Requests for Rehearing and Clarification
i. Arguments That the Commission Does Not Have the Authority To
Eliminate a Federal Right of First Refusal
345. Several petitioners argue that the Commission acted outside of
its authority by requiring the removal of the federal right of first
refusal from Commission-jurisdictional tariffs and agreements.\380\
Some petitioners assert that section 206 only extends to behavior that
directly affects rates or the provision of jurisdictional service
rather than to any term in a jurisdictional tariff or agreement.\381\
They argue the federal right of first refusal is not a practice within
the meaning of section 206, and therefore is not a behavior that the
Commission can address under that section.\382\ Similarly, Oklahoma Gas
and Electric Company states that the Commission must show a direct and
significant effect on jurisdictional rates before it can regulate
actions indirectly affecting activity falling under state jurisdiction.
---------------------------------------------------------------------------
\380\ See, e.g., FirstEnergy Service Company; Baltimore Gas &
Electric; Southern Companies; Ad Hoc Coalition of Southeastern
Utilities; and Sponsoring PJM Transmission Owners.
\381\ See, e.g., FirstEnergy Service Company; Sponsoring PJM
Transmission Owners; Baltimore Gas & Electric; and Oklahoma Gas and
Electric Company.
\382\ See, e.g., Southern Companies; Sponsoring PJM Transmission
Owners; Baltimore Gas & Electric; and Oklahoma Gas and Electric
Company.
---------------------------------------------------------------------------
346. Petitioners also analogize the Commission's action in Order
No. 1000 with its failed attempt to regulate corporate governance and
structure, which was at issue in CAISO v. FERC.\383\ Petitioners argue
that the federal right of first refusal affects a transmission
provider's financial relationship with its customers no more than the
DC Circuit found governance to in CAISO v. FERC.\384\ According to
Baltimore Gas & Electric, the court in CAISO v. FERC explained that the
[[Page 32238]]
Commission cannot regulate ``practices'' using its section 206
ratemaking authority unless the practices ``affect rates and services
significantly * * * are realistically susceptible of specification, and
* * * are not so generally understood in any contractual arrangement as
to render recitations superfluous.'' \385\ Sponsoring PJM Transmission
Owners also note that the CAISO court explained that a more expansive
interpretation of ``practice'' would allow the Commission to regulate a
range of subjects that the court considered to be plainly beyond the
Commission's proper authority. Sponsoring PJM Transmission Owners add
that, while the costs the transmission provider incurs to construct or
procure an upgrade will be reflected in its rates, the same could be
said of a myriad of other decisions the transmission provider makes,
ranging from its hiring of staff to the procurement of outside services
and materials. Southern Companies also analogize Order No. 1000 to
CAISO v. FERC, arguing that the Commission, without evidence or a
record of systemic abuse or actual discrimination or unreasonable
decision making, is using sections 205 and 206 and a theoretical threat
of unjust and unreasonable rates or discrimination in the provision of
transmission service to replace the existing business investment
decision process with its own.\386\
---------------------------------------------------------------------------
\383\ Sponsoring PJM Transmission Owners at 5-6 (citing
California Indep. Sys. Operator Corp. v. FERC, 372 F.3d 403 (D.C.
Cir. 2004) (CAISO v. FERC)); Southern Companies at 60-61 (citing
CAISO v. FERC, 372 F.3d 395); PSEG Companies; Baltimore Gas &
Electric (citing CAISO v. FERC, 372 F.3d at 403; City of Cleveland
v. FERC, 773 F.2d 1368 (DC Cir. 1985)); Oklahoma Gas and Electric
Company at 9-10 (CAISO v. FERC, 372 F.3d at 403).
\384\ Southern Companies at 60-61 (citing CAISO v. FERC, 372
F.3d 395); Sponsoring PJM Transmission Owners at 7 (citing CAISO v.
FERC, 372 F.3d at 403 (quoting Mich. Wisc. Pipeline Co., 34 FPC ]
621,626 (1965))).
\385\ Baltimore Gas & Electric at 12 (quoting CAISO v. FERC, 372
F.3d at 403).
\386\ Southern Companies at 103-104 (citing CAISO v. FERC, 372
F.2d at 395).
---------------------------------------------------------------------------
347. Sponsoring PJM Transmission Owners also point out that the
court in CAISO v. FERC found that section 305 of the FPA, giving the
Commission authority over interlocking directorates, would not have
been necessary if it intended that the Commission could regulate
corporate governance as a practice affecting rates under sections 205
and 206 of the FPA. They contend that this same reasoning leads to the
conclusion that section 206 does not encompass the assignment of
construction responsibility. Sponsoring PJM Transmission Owners argue
that this is clear in looking at the relationship of section 7 of the
NGA to sections 4 and 5 of the NGA, which parallel sections 205 and 206
of the FPA. They assert that section 7 of the NGA, giving the
Commission the authority to regulate pipeline construction, would not
have been necessary if sections 4 and 5 of the NGA (which parallel
sections 205 and 206 of the FPA) already allowed the Commission to
regulate such construction.\387\ In addition, Sponsoring PJM
Transmission Owners state that it is significant that, when
deliberating on the FPA, Congress rejected provisions that would have
given the Commission authority to order a utility to fix the services,
equipment, or facilities it is responsible for maintaining upon
determining they were improperly maintained.\388\
---------------------------------------------------------------------------
\387\ Sponsoring PJM Transmission Owners. Similarly, Sponsoring
PJM Transmission Owners assert that section 402 of the
Transportation Act of 1920 (superseded by 49 U.S.C. 10901 (2010)),
which provided the Interstate Commerce Commission with approval
authority for railway extensions, would not have been necessary if
practices affecting rates included construction decisions.
\388\ Sponsoring PJM Transmission Owners at 11 (citing Duke
Power Co. v. Fed. Power Comm'n, 401 F.2d 930, 943 n.106 (D.C. Cir.
1968)). They add that, although the statutory interpretations of
later Congresses is not determinative of the statutory intent of an
earlier Congress, it is informative that when Congress granted
backstop siting authority to the Commission in the Energy Policy Act
of 2005, it established clear limits that constrain the exercise of
that authority. Id. (citing 16 U.S.C. 824p (2010); Piedmont Envtl.
Council v. FERC, 558 F.3d 304 (4th Cir. 2009). They also state that
section 1211 of the EPAct 2005 expressly states that the new
electric reliability provisions do not authorize the Commission to
order the construction of additional transmission facilities. Id.
(referencing 16 U.S.C. 824o(i)(2)).
---------------------------------------------------------------------------
348. Sponsoring PJM Transmission Owners also analogize the right of
first refusal to Interstate Commerce Commission v. Pennsylvania.\389\
They contend that the court in CAISO v. FERC looked to this case
because the court in Interstate Commerce Commission v. Pennsylvania
interpreted the Interstate Commerce Act upon which Part II of the FPA
is based and which likewise authorized the regulation of practices
affecting rates.\390\ Sponsoring PJM Transmission Owners assert the
court in Interstate Commerce Commission v. Pennsylvania made clear that
it was manifestly concerned about practices that directly related to
the jurisdictional service provided customers (which was rail service),
rather than the railroads' decisions regarding the means to provide
such service.\391\
---------------------------------------------------------------------------
\389\ Sponsoring PJM Transmission Owners at 9-10 (citing
Interstate Commerce Commission v. Pennsylvania, 242 U.S. 208 (1916)
(ICC v. Pennsylvania)).
\390\ Sponsoring PJM Transmission Owners at 9-10 (citing ICC v.
Pennsylvania, 242 U.S. 208)).
\391\ Sponsoring PJM Transmission Owners at 9-10 & n.20 (citing
ICC v. Pennsylvania, 242 U.S. 208; Duncan v. Walker, 533 U.S. 167,
174 (2001)).
---------------------------------------------------------------------------
349. Instead of finding that any rate is unjust and unreasonable,
Baltimore Gas & Electric argues that the Commission states that there
may be a superior alternative practice to the present federal right of
first refusal regime. Baltimore Gas & Electric asserts that this is
contrary to well-settled law, which requires that if the existing
method is just and reasonable, then that is the end of the section 206
inquiry even if an alternative method may be better.\392\ Baltimore Gas
& Electric asserts that the Commission violated this ratemaking precept
by conflating its consideration of the federal right of first refusal
mechanism for designating new transmission construction and operation
responsibility with its consideration of an alternative selection
process that the Commission prefers.
---------------------------------------------------------------------------
\392\ Baltimore Gas & Electric at 10-11 (citing Complex Consol.
Edison Co. of N.Y. v. FERC, 165 F.3d 992, 1003 (D.C. Cir. 1999);
Pub. Serv. Comm'n of N.Y. v. FERC, 642 F.2d 1335 (D.C. Cir. 1980)
cert. denied, 454 U.S. 879 (1981); Kern River Gas Transmission Co.,
Opinion No. 486-E, 136 FERC ] 61,045 (2011)).
---------------------------------------------------------------------------
350. PSEG Companies assert that elimination of the federal right of
first refusal was arbitrary and capricious because the ``remedy'' far
exceeded the purported harm. Similarly, Baltimore Gas & Electric
asserts that proportionality between the identified problem and the
remedy ``is the key,'' and that if the Commission found isolated
problems, a market-wide remedy would be inappropriate.\393\ Similarly,
Baltimore Gas & Electric asserts that the Commission must adduce hard
facts, and that the remedy should be narrowly tailored to fit the
facts.
---------------------------------------------------------------------------
\393\ PSEG Companies at 33 (quoting Public Utils. Comm'n of the
State of Cal. v. FERC, 462 F.3d 1027, 1054 (9th Cir. 2006)).
---------------------------------------------------------------------------
351. With regard to the Commission's determination that the
existence of a federal right of first refusal creates an opportunity
for undue discrimination and preferential treatment against
nonincumbent transmission developers, several petitioners argue that
the Commission cannot rely on the FPA's undue discrimination provisions
in sections 205 and 206 because these provisions only protect customers
of public utilities, and not nonincumbent transmission developers.\394\
They argue
[[Page 32239]]
that had Congress intended to grant the Commission such authority, it
would have done so.\395\ Large Public Power Council and Ad Hoc
Coalition of Southeastern Utilities note that the court, in the City of
Frankfort, stated that section 205 provisions ``regarding unlawful
preference or advantage in setting of public utility rates requires
that utility customers be treated fairly.'' \396\ They also cite Public
Service Co. of Ind. where the court stated that ``the anti-
discrimination policy in section 205(b) is violated * * * where one
consumer has its rates raised significantly above what other similarly-
situated customers are paying.'' \397\ Oklahoma Gas & Electric Company
contends that neither of the cases the Commission cites support a
different conclusion, claiming that, in Gulf States, the Commission
addressed the narrow question of whether public utilities could
``employ tariff provisions to foreclose wholesale competition,'' \398\
and that in Otter Tail, the Supreme Court held that the FPA was not
intended ``to be a substitute for, or to immunize Otter Tail from,
antitrust regulation.'' \399\
---------------------------------------------------------------------------
\394\ See, e.g., Southern Companies at 62 (citing Pub. Serv. Co.
of Ind., Inc. v. FERC, 575 F.2d 1204, 1213 (7th Cir. 1978); see St.
Michaels Util. Comm'n v. FPC, 377 f.2d 912, 915 (4th Cir. 1967));
Sponsoring PJM Transmission Owners at 12 (citing Maine Pub. Serv.
Co. v. FPC, 579 F.2d 659, 664 (1st Cir. 1978)); see also, e.g., FPC
v. Sierra Pacific Power Co., 350 U.S. 348, 355 (1956); Mun. Light
Bds. v. FPC, 450 F.2d 1341, 1348 (D.C. Cir. 1971); Baltimore Gas &
Electric; Large Public Power Council; Ad Hoc Coalition of
Southeastern Utilities at 59 (citing Pub. Serv. Co. of Ind. v. FERC,
575 F.2d 1203, 1213 (7th Cir. 1978); St. Michaels util. Comm'n v.
FPC, 377 F.2d 912, 915 (4th Cir. 1967); City of Frankfort, Ind. v.
FERC, 678 F.2d 699, 707 (7th Cir. 1982) (Frankfort v. FERC); Towns
of Alexandria, Minn. v. FPC, 555 F.2d 1020, 1028 (D.C. Cir. 1977));
Oklahoma Gas and Electric Company at 7-8 (citing St. Michaels Util.
Comm'n v. FPC, 377 F.2d at 915; Pub. Serv. Co. of Ind., Inc. v.
FERC, 575 F.2d at 1212 (stating that the intent of the statute's
undue discrimination protections ``is to protect consumers from
being placed at a competitive disadvantage with other [similar
customers]''); Frankfort v. FERC, 678 F.2d at 707 ; Towns of
Alexandria, Minn. v. FPC, 555 F.2d 1020, 1028 (D.C. Cir. 1977)).
\395\ Oklahoma Gas & Electric at 6 (citing Dunk v. Penn. Pub.
Util. Comm'n, 252 A.2d 589, 591-92 (Pa. 1969)). It also contrasts
the absence of such language in the FPA with the Natural Gas Act and
Part I of the FPA (addressing hydroelectric facilities).
\396\ Ad Hoc Coalition of Southeastern Utilities at 59 (quoting
Frankfort v. FERC, 678 F.2d at 704); Large Public Power Council at
32 (quoting Frankfort v. FERC, 678 F.2d at 707).
\397\ See, e.g., Ad Hoc Coalition of Southeastern Utilities at
59-60 (quoting Pub. Serv. Co. of Ind. v. FERC, 575 F.2d at 1213);
Large Public Power Council at 32 (quoting Pub. Serv. Co. of Ind.,
Inc. v. FERC, 575 F.2d at 1213).
\398\ Gulf States Utils. Co., 5 FERC ] 61,066 at 61,098 (1978).
\399\ Otter Tail Power Co. v. United States, 410 U.S. 366, 374-
75 (1973) (Otter Tail v. U.S.).
---------------------------------------------------------------------------
352. Petitioners also argue that the Commission lacks the authority
to remedy all instances of undue discrimination, and only is
responsible for promoting competition if anticompetitive behavior has a
direct effect on rates.\400\ In support, Sponsoring PJM Transmission
Owners argue that CAISO v. FERC demonstrates that the Commission could
not remedy a discriminatory governance structure of an independent
system operator, and that the Supreme Court has held that the
Commission does not have the authority to remedy racial discrimination
in a utility's hiring practices.\401\ Furthermore, Sponsoring PJM
Transmission Owners argue that the Commission cannot rely on the
court's affirmation of Order Nos. 436 \402\ and 888 \403\ as support
for its asserted authority to remedy any and all discrimination.
Furthermore, Sponsoring PJM Transmission Owners, similar to Oklahoma
Gas & Electric, assert that the court in Otter Tail Power Co. v. United
States concluded that the Commission lacked the authority to compel
interconnection based on antitrust considerations alone.\404\
Sponsoring PJM Transmission Owners also argue that Gulf States
Utilities Co.,\405\ cited by the Commission, did not assert
responsibility to promote competition in the abstract. Sponsoring PJM
Transmission Owners assert that this lack of authority to act solely on
antitrust considerations, in the absence of an impact on jurisdictional
services, contrasts with the Commission's authority to compel open
access as a remedy for undue discrimination in transmission access, a
jurisdictional service.\406\
---------------------------------------------------------------------------
\400\ Sponsoring PJM Transmission Owners at 14; Ad Hoc Coalition
of Southeastern Utilities at n.176 (citing Entergy Services Inc., 64
FERC ] 61,001 at ] 61,013, n.66 (1993); Cargill, Inc. v. Montfort of
Colorado, Inc., 479 U.S. 104, 115-117 (1976)).
\401\ Sponsoring PJM Transmission Owners at 12 (citing CAISO. v.
FERC, 372 F.3d 400; NAACP v. FPC, 425 U.S. 662 (1976)).
\402\ Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, Order No. 436, FERC Stats. & Regs. ] 30,665, at 31,502
(1985).
\403\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Pub. Utils.; Recovery of
Stranded Costs by Pub. Utils. and Transmitting Utils., Order No.
888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g, Order No.
888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order No. 888-
B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC
] 61,046 (1998), aff'd in relevant part sub nom. Transmission Access
Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub
nom. New York v. FERC, 535 U.S. 1 (2002)).
\404\ Sponsoring PJM Transmission Owners at 14 (citing 410 U.S.
366 (1973)).
\405\ Gulf States Util. Co., 5 FERC ] 61,066 at 61,098.
\406\ Sponsoring PJM Transmission Owners at 15 (citing
Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 686
(D.C. Cir. 2000)).
---------------------------------------------------------------------------
353. Several petitioners contend that even if the Commission had
the authority to address discrimination against nonincumbents, no undue
discrimination against nonincumbents exists for the Commission to
remedy under section 206.\407\ Instead, some petitioners argue that
Order No. 1000 institutionalizes undue discrimination against incumbent
transmission owners in violation of the FPA and APA because it mandates
similar treatment for incumbent transmission owners and nonincumbent
transmission developers when they are not similarly situated.\408\ In
support, petitioners argue that the Commission failed to consider
evidence of the full scope of risks faced by incumbent utilities.\409\
For instance, several petitioners argue that incumbents have an
obligation to serve customers and must comply with state legal and
regulatory requirements, while nonincumbents are free to pick and
choose among transmission investment options.\410\ Others argue that
incumbents are obligated to build under RTO contracts.\411\
---------------------------------------------------------------------------
\407\ See e.g., Ameren; PSEG Companies; and MISO Transmission
Owners Group.
\408\ See, e.g., MISO Transmission Owners Group 2; and Ameren.
\409\ See, e.g., Ameren; Southern Companies; and MISO
Transmission Owners Group 2.
\410\ See, e.g., Ameren; PSEG Companies; MISO Transmission
Owners Group; and Southern Companies.
\411\ See, e.g., MISO Transmission Owners Group 2; and PSEG
Companies.
---------------------------------------------------------------------------
354. Some petitioners also argue that it is unclear whether
nonincumbent developers will have the same responsibilities as
incumbent developers when operating their facilities. For instance,
petitioners question whether there is a practical enforcement mechanism
to ensure that a nonincumbent developer will build its transmission
facility and then safeguard it from threats, such as cyber
attacks.\412\ Transmission Dependent Utility Systems argue that even if
the nonincumbent developer were to be assessed penalties for
reliability violations, NERC penalties may be insufficient for a
merchant transmission developer that, in the absence of a franchised
service territory obligation, may walk away from its contractual
commitments or become financially unable to meet them.
---------------------------------------------------------------------------
\412\ See, e.g., Baltimore Gas & Electric; and Transmission
Dependent Utility Systems.
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355. In related arguments, some petitioners disagree with the
Commission's conclusion that the federal right of first refusal is not
dependent on an obligation to build.\413\ They argue that the
obligation to build under an RTO or ISO is not an ``option,'' but
rather imposes a duty of diligence in fulfilling construction
obligations. Baltimore Gas & Electric argues that the Commission has
misconstrued what a federal right of first refusal is, which it argues
is another way of saying that it has a right of notification from PJM
whenever PJM determines that transmission needs to be built in
Baltimore Gas & Electric's service area since Baltimore Gas & Electric
is required to build it. Baltimore Gas & Electric argues that the
Commission's ruling on this issue is invalid because
[[Page 32240]]
the Commission failed to appreciate what a federal right of first
refusal is. MISO states that since it does not own any transmission
facilities, it needs to rely on the transmission owners' obligation to
build under the Transmission Owners Agreement to ensure MISO's ability
to fulfill its transmission planning and expansion responsibilities as
an RTO. MISO states that its membership could be significantly eroded
and its existence could be jeopardized, as well as its rate
significantly affected, if the Commission were to modify this
fundamental element of MISO's structure as an RTO.
---------------------------------------------------------------------------
\413\ See, e.g., Baltimore Gas & Electric; and MISO.
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356. PSEG Companies contend that the elimination of the federal
right of first refusal is a taking in violation of the Fifth Amendment
to the U.S. Constitution because it renders meaningless the
contractually-based consideration transmission owners received when
they transferred control of their transmission facilities to ISOs/RTOs.
They note that takings may not only be regulatory in nature but could
include contractual takings.\414\ According to PSEG Companies, language
in the PJM Transmission Owners Agreement created the reasonable
investment-backed expectation among incumbent transmission owners that
they could participate in an RTO arrangement and commit to build
everything needed for reliability purposes while still preserving
fundamental rights, such as the right to build in their respective
zones. PSEG Companies conclude that the Commission's impairment of this
contractual right of first refusal creates unspecified economic
injuries that, without just compensation, violate the U.S.
Constitution.
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\414\ PSEG Companies at 36 (citing Tahoe-Sierra Preservation
Council, Inc. v. Tahoe Regional Planning Agency, 535 U.S. 302, 332
(2002); Armstrong v. United States, 364 U.S. 40, 49 (1960)).
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(a) Commission Determination
357. We affirm the decision in Order No. 1000 that the Commission
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.\415\
At the outset, it is important to emphasize the scope of the
Commission's requirement to eliminate federal rights of first refusal.
In Order No. 1000, the Commission required public utility transmission
providers to remove from Commission-jurisdictional tariffs and
agreements provisions that grant a federal right of first refusal to
construct transmission facilities selected in a regional transmission
plan for purposes of cost allocation.\416\ The Commission did not,
however, require public utility transmission providers to remove a
federal right of first refusal for local transmission facilities or
upgrades to an incumbent transmission provider's own transmission
facilities, and did not alter an incumbent transmission provider's use
and control of an existing right of way.\417\
---------------------------------------------------------------------------
\415\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 284.
\416\ Id. P 226.
\417\ Id.
---------------------------------------------------------------------------
358. We affirm the decision in Order No. 1000 that a federal right
of first refusal is a practice that falls squarely within the
interpretation of a practice affecting rates.\418\ To this end,
contrary to the argument of some petitioners, the Commission affirms
that the CAISO v. FERC decision supports the Commission's position. As
discussed in Order No. 1000, the court in CAISO v. FERC explained that
the Commission is empowered under section 206 to assess practices that
directly affect or are closely related to a public utility's rates and
``not all those remote things beyond the rate structure that might in
some sense indirectly or ultimately do so.'' \419\ As explained in
Order No. 1000, we meet this standard because here we are focused on
the effect that federal rights of first refusal in Commission-approved
tariffs and agreements have on competition and in turn the rates for
jurisdictional transmission services. For example, as the Commission
explained in Order No. 1000, 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.\420\ 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.\421\
This in turn can directly increase the cost of new transmission
development that is recovered from jurisdictional customers through
rates.\422\
---------------------------------------------------------------------------
\418\ Id. P 285.
\419\ CAISO v. FERC, 372 F.3d at 403.
\420\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 289.
\421\ Id. P 284.
\422\ Id.
---------------------------------------------------------------------------
359. Sponsoring PJM Transmission Owners argue that section 7 of the
NGA, which gives the Commission authority to regulate pipeline
construction, demonstrates that had Congress desired to give the
Commission authority over construction of transmission lines it would
have done so. However, Sponsoring PJM Transmission Owners misconstrue
the Commission's actions in Order No. 1000. As the Commission
explicitly stated in Order No. 1000, it is not regulating construction
of new transmission facilities because that is a matter reserved to the
states.\423\ Instead, the Commission acted under its legal authority in
section 206 to require the elimination of provisions in federally-
regulated tariffs establishing practices in the regional transmission
planning process that affect rates. The authority to authorize
construction and siting of new transmission facilities is distinct from
the authority to require public utility transmission providers to
engage in an open and transparent regional transmission planning
process designed to ensure that the more efficient or cost-effective
solutions to regional transmission needs are selected in the regional
transmission plan for purposes of cost allocation.
---------------------------------------------------------------------------
\423\ Id. P 287 (``Eliminating a federal right of first refusal
in Commission-jurisdictional tariffs and agreements does not, as
some commenters contend, result in the regulation of matters
reserved to the states, such as transmission construction, ownership
or siting.'' (emphasis added)).
---------------------------------------------------------------------------
360. Contrary to Baltimore Gas & Electric's arguments, the
Commission made a finding in Order No. 1000 that granting an incumbent
transmission provider a federal right of first refusal with respect 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.\424\ Consistent with 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 such provisions from Commission-jurisdictional
tariffs or agreements and adopt the nonincumbent transmission developer
reforms. In addition, the Commission's decision to require public
utility transmission providers to adopt the nonincumbent transmission
developer reforms was an appropriate, and adequately tailored, remedy
in light of the Commission's conclusion that it is not in the economic
self-interest of public utility transmission providers to permit new
entrants to develop
[[Page 32241]]
transmission facilities.\425\ For instance, some commenters supported
eliminating all federal rights of first refusal. On balance, however,
the Commission determined that incumbent transmission providers should
be able to maintain an existing federal right of first refusal for
certain types of new transmission projects, including a local
transmission facility and upgrades to its existing transmission
facilities. The Commission clarified that its actions were not intended
to diminish the significance of an incumbent transmission provider's
reliability or service obligations.\426\
---------------------------------------------------------------------------
\424\ Id. PP 253, 284.
\425\ Id. P 256.
\426\ Id. P 262.
---------------------------------------------------------------------------
361. In addition to affirming our decision to act to remedy unjust
and unreasonable rates, we affirm, on an independent and alternative
basis, the decision in Order No. 1000 that the elimination of any
federal rights of first refusal from Commission-jurisdictional tariffs
and agreements is necessary to address opportunities for undue
discrimination and preferential treatment against nonincumbent
transmission developers within regional transmission planning
processes.\427\ In Order No. 1000, the Commission explained that ``it
has a responsibility to consider anticompetitive practices and to
eliminate barriers to competition.'' \428\ We continue to believe, as
the Commission found in Order No. 1000, that we have a duty to consider
anticompetitive practices and to eliminate barriers to competition
consistent with the FPA.\429\
---------------------------------------------------------------------------
\427\ Id. P 286.
\428\ Id.
\429\ See Gulf States Utils. Co., 5 FERC ] 61,066 at 61,098;
Otter Tail v. U.S., 410 U.S. at 374 (``the history of Part II of the
Federal Power Act indicates an overriding policy of maintaining
competition to the maximum extent possible consistent with the
public interest.'').
---------------------------------------------------------------------------
362. Petitioners rely on City of Frankfort and Public Service Co.
of Ind. in support of their contention that section 206's prohibition
on undue discrimination only protects customers of public utilities.
However, the court did not, as petitioners would imply, set forth
limits on who the Commission may, acting under its section 206
authority, protect from unduly discriminatory practices. Instead, the
cases cited by petitioners address the applicability of section 206 in
the context of a regulated utility appearing to provide favorable rates
or terms to one customer, and the courts in those cases do not address
whether section 206 may be used as a basis for eliminating unduly
discriminatory or preferential practices between competitors. In
addition, we continue to conclude that the Commission's action is in
accordance with its responsibility to eliminate unduly discriminatory
or preferential practices in regional transmission planning processes.
363. While we agree with petitioners that argue that the Commission
does not have the authority to remedy every instance of undue
discrimination, given the FPA's emphasis on promoting competition, the
Commission has a responsibility to eliminate unduly discriminatory
practices that come within the Commission's subject matter jurisdiction
under section 201 of the FPA, which includes the transmission of
electric energy in interstate commerce.\430\ In Order No. 1000, the
Commission found that ``federal rights of first refusal create
opportunities for undue discrimination and preferential treatment
against nonincumbent transmission developers within existing regional
transmission planning processes.'' \431\ Accordingly, the Commission
has acted consistent within its authority to eliminate and remedy
practices that it found to be unduly discriminatory and
anticompetitive. In any event, the Commission has not based its
decision solely on competition concerns because, in the alternative,
the Commission acted to remedy the potential for unjust and
unreasonable rates for Commission-jurisdictional services in addition
to promoting competition among potential transmission developers.
---------------------------------------------------------------------------
\430\ 16 U.S.C. 824.
\431\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 286.
---------------------------------------------------------------------------
364. We disagree with petitioners' argument that Order No. 1000
institutionalizes undue discrimination against incumbent transmission
providers. Petitioners argue that the Commission failed to consider the
full scope of risks faced by incumbent transmission providers, and thus
erroneously concluded that incumbent transmission providers and
nonincumbent transmission developers are similarly situated. For
example, some petitioners argue that many incumbent transmission
providers have obligations to build placed on them under RTO and ISO
member agreements. However, as explained in Order No. 1000,
nonincumbent transmission developers that build a transmission facility
in an RTO or ISO and become members of that RTO or ISO will be subject
to the same relevant obligations that apply to incumbent transmission
providers that are members of an RTO or ISO.\432\ For instance,
nonincumbent transmission developers also will have an obligation to
expand their transmission facilities if directed to by the RTO or ISO
consistent with the RTO's or ISO's tariff or governing agreement.
---------------------------------------------------------------------------
\432\ Id. P 265.
---------------------------------------------------------------------------
365. Other petitioners argue that incumbent transmission providers
are not similarly situated to nonincumbent transmission developers
because incumbent transmission providers, unlike nonincumbent
transmission developers, must comply with reliability standards and
have an obligation to serve customers. They further argue that having a
federal right of first refusal is necessary to comply with these
standards and obligations. While public utility transmission providers
must comply with reliability standards and some public utility
transmission providers have an obligation to serve,\433\ we disagree
that eliminating federal rights of first refusal amounts to
discrimination in favor of nonincumbent transmission developers.
Instead, as we stated in Order No. 1000, we are merely removing
barriers to participation by all potential transmission providers in
the regional transmission planning process subject to our jurisdiction.
Moreover, as explained in Order No. 1000, all owners and operators of
bulk-power system transmission facilities, including nonincumbent
transmission developers, that successfully develop a transmission
project, are required to be registered as Functional Entities \434\ and
must comply with all applicable reliability standards.\435\ Similarly,
transmission facilities selected in a regional transmission plan for
purposes of cost allocation owned by a nonincumbent transmission
developer would be subject to any applicable open access requirements.
Accordingly, we continue to believe that the nonincumbent transmission
developer reforms will not result in undue discrimination against
incumbent transmission developers.
---------------------------------------------------------------------------
\433\ Id.
\434\ We use the term Functional Entity to refer to any user,
owner or operator of the bulk power system that is responsible for
complying with a NERC reliability standard as that term is defined
in section 215(a)(3) of the FPA.
\435\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 266
(citing 18 CFR part 39.2(a) (2011)).
---------------------------------------------------------------------------
366. Similarly, we disagree with Oklahoma Gas and Electric Company
that the nonincumbent transmission developer reforms materially alter
the business of a public utility that has been responsible for, and
entitled to earn a return from, construction of its own transmission
system. As we explained in Order No. 1000, while public utilities are
entitled to receive a reasonable
[[Page 32242]]
return on their investment, they will no longer be entitled to receive
from the Commission a preferential right to make those investments in
new transmission facilities that are selected in a regional
transmission plan for purposes of cost allocation under the provisions
of Order No. 1000.\436\ Inherent in Oklahoma Gas and Electric Company's
argument is that incumbent transmission providers have traditionally
had the opportunity to build transmission facilities for their own
transmission systems. Nothing in Order No. 1000 prohibits an incumbent
transmission provider from choosing to build new transmission
facilities that are located solely within its retail distribution
service territory or footprint and that are not selected for selection
in a regional transmission plan for purposes of cost allocation.\437\
---------------------------------------------------------------------------
\436\ Id. P 269.
\437\ Id. P 262.
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367. We are not persuaded by Baltimore Gas & Electric's argument
that a federal right of first refusal is simply the recognition of an
obligation to build. In Order No. 1000, we acknowledged that a public
utility transmission provider may have accepted an obligation to build
in relation to its membership in an RTO or ISO, but the Commission did
not agree that that obligation is necessarily dependent on the
incumbent transmission provider having a corresponding federal right of
first refusal to prevent other entities from constructing and owning
new transmission facilities located in that region.\438\ We continue to
believe that an obligation to build in relation to membership in an RTO
or ISO is not necessarily dependent on an incumbent transmission
provider having a corresponding federal right of first refusal to
prevent other entities from constructing and owning new transmission
facilities located in that region,\439\ and Baltimore Gas & Electric
has provided no evidence to the contrary. Moreover, while eliminating a
federal right of first refusal may change the benefits and obligations
associated with membership in an RTO or ISO, we affirm our finding in
Order No. 1000 that changing the benefits and obligations is necessary
to correct practices that have the potential to lead to unjust and
unreasonable rates for Commission-jurisdictional transmission
service.\440\ Similarly, we disagree with MISO that the nonincumbent
transmission developer reforms will discourage entities from
maintaining membership in an RTO or ISO, because, as explained in Order
No. 1000, there are a variety of factors that public utility
transmission providers must weight when evaluating the benefits and
burdens of RTO/ISO membership.\441\
---------------------------------------------------------------------------
\438\ Id. P 261.
\439\ Id.
\440\ Id.
\441\ Id. P 265.
---------------------------------------------------------------------------
368. We also are not convinced by PSEG Companies' argument that
requiring public utility transmission providers to eliminate a federal
right of first refusal for transmission projects that are selected in
the regional plan for purposes of cost allocation violates the Takings
Clause of the Fifth Amendment. Nor do we agree that Order No. 1000
destroys or materially impairs PSEG Companies' purported contractual
right to build in their respective service areas or zones. Although
some contractual rights are ``property'' within the meaning of the
Taking Clause,\442\ the Commission has not impaired this alleged
contractual right of first refusal. Order No. 1000 continues to permit
an incumbent transmission provider, such as PSEG Companies, to meet its
reliability needs or service obligations by choosing to build new
transmission facilities that are located solely within its retail
distribution service territory or footprint as long as the transmission
provider does not receive regional cost allocation for the
facilities.\443\
---------------------------------------------------------------------------
\442\ Connolly v. Pension Guaranty Corp., 475 U.S. 211, 224
(1986) (holding that congressional action that impinged upon
employers' contractual rights did not constitute an unconstitutional
taking).
\443\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 262.
---------------------------------------------------------------------------
369. Even assuming that Order No. 1000 impinges upon this alleged
contractual right, PSEG Companies have not met their ``substantial
burden'' to show ``whether a regulation `reaches a certain magnitude'
in depriving an owner of the use of property.'' \444\ Just as
``legislation [that] readjust[s] rights and burdens is not unlawful
solely because it upsets otherwise settled expectations,'' \445\ the
Order No. 1000 regulations regarding the federal right of first refusal
are not unconstitutional takings solely because the regulations impact
the benefits and burdens of transmission owner agreements. Furthermore,
in arguing that Order No. 1000 operates to take their property, PSEG
Companies have a burden to demonstrate the economic injury they expect
to incur if they are denied the future exclusive opportunity to build
transmission facilities in their service territory.\446\ They have not
met this burden in their rehearing request.
---------------------------------------------------------------------------
\444\ District Intown Props. Ltd. Pshp. v. District of Columbia,
198 F.3d 874, 878 (D.C. Cir. 1999) (citing Pennsylvania Coal Co. v.
Mahon, 260 U.S. 393, 413 (1922)).
\445\ Connolly, 475 U.S. at 223.
\446\ See Connolly, 475 U.S. at 225 (to determine whether there
is a ``taking,'' the Court evaluates three factors: ``(1) The
economic impact of the regulation on the claimant; (2) the extent to
which the regulation has interfered with investment-backed
expectations; and (3) the character of the governmental action).
---------------------------------------------------------------------------
370. Finally, PSEG Companies also have not argued that Order No.
1000 appropriates their alleged contractual right of first refusal for
public use. Nor could the Commission be said to be taking the federal
right of first refusal so that another entity could use it for public
purposes.\447\ Rather, we require the elimination of such provisions so
that incumbent transmission providers and nonincumbent transmission
developers will have an opportunity on a comparable basis to propose
new transmission facilities for selection in the regional transmission
plan for purposes of cost allocation.\448\ For these reasons, we find
that the elimination of federal rights of first refusal does not
constitute a taking under the Fifth Amendment's Taking Clause.
---------------------------------------------------------------------------
\447\ See Omnia, 261 U.S. at 508-13 (holding that, while
government requisition of steel frustrated a contract for delivery
of steel, the government action was not an appropriation for public
purposes that required just compensation).
\448\ Accord Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC,
475 F.3d 1277, 1284 (D.C. Cir. 2007) (finding that anti-
discrimination rules commonly burden the obligated parties and that
the burden imposed did not create an unconstitutional taking of
private property).
---------------------------------------------------------------------------
ii. Arguments That the Commission Is Inappropriately Regulating the
Construction of Transmission
371. Several petitioners argue that the Commission's reforms
impermissibly infringe on state jurisdiction to authorize construction
and operation of transmission lines.\449\ Ameren states that section
201(a) expressly provides that the Commission does not have authority
over matters that are subject to regulation by the states, and that
states have historically exercised jurisdiction over siting and
construction of transmission facilities. Ameren asserts that had
Congress wished to expand the Commission's jurisdiction, it would have
done so by adding new sections to the FPA, such as sections 215 and
216, which gave the Commission expanded authority over reliability.
Wisconsin PSC also argues that FPA sections 201 and 206 do not create a
federal right to authorize transmission line construction.\450\
According to PSEG
[[Page 32243]]
Companies, the removal of the federal right of first refusal
``immediately, directly and irreparably impacts'' the decision of who
gets to site, construct, and own transmission facilities in a
transmission owner's zone, and incumbent transmission owners will no
longer have the threshold right to build in their respective state
service territories to satisfy their obligations under state law. In
addition, Baltimore Gas & Electric argues that the federal right of
first refusal has nothing to do with the Commission's limited backstop
authority over transmission construction.\451\
---------------------------------------------------------------------------
\449\ See, e.g., Wisconsin PSC; Baltimore Gas & Electric;
Ameren; and PSEG Companies.
\450\ Wisconsin PSC at 14-15 (citing Dunk v. Pennsylvania Pub.
Util. Comm'n, 434 Pa. 41, 44-45, 252 A.2d 589, 591-92, cert. denied,
396 U.S. 839 (1969)).
\451\ Baltimore Gas & Electric at 5 (citing 16 U.S.C. 824p).
---------------------------------------------------------------------------
372. Ameren requests clarification that, in implementing the
requirement to remove any federal right of first refusal from
Commission-jurisdictional tariffs and agreements, incumbent
transmission owners that have a state certified service area or local
franchise service area retain the sole right to build infrastructure
and serve customers in that service territory. Ameren asserts the
Commission also should clarify that it does not have the authority to
preempt a state law or regulation of this type. However, Southern
Companies assert that the Commission should explicitly state that Order
No. 1000 preempts the state-mandated duty to serve native load to the
extent that a nonincumbent sponsors a transmission project needed to
fulfill that duty to serve. They argue that Order No. 1000's
requirements will impair the ability of incumbents to comply with their
state-mandated duty to serve native load, and that these provisions
might be used to argue that incumbents should be subject to
ramifications under state law for a nonincumbent's delay, abandonment,
or other possible wrong doing.
373. Other petitioners point out that, unlike the NGA, the FPA does
not grant the Commission any authority over construction or ownership
of transmission facilities.\452\ Wisconsin PSC states that Order No.
1000 confusingly implies the existence in the FPA of a federal ability
to confer a right to construct, which is not in the FPA, whereas the
FPA reserved such authority to state jurisdiction.\453\ Wisconsin PSC
argues that in Connecticut Light & Power Co. v. FERC, the Supreme Court
engages in an extensive discussion that suggests that even though the
particular facilities and activities of a person determine whether the
person is a public utility subject to the FPA, there is a limit to the
agency's jurisdiction.\454\ Southern Companies also state that the
decision to construct or invest in a transmission facility does not
belong to the Commission, except as required to grant or maintain
service for transmission service customers.\455\ They argue there is no
authority for the proposition that the Commission may require a public
utility transmission provider to plan for, construct, or fund any new
transmission facility involuntarily.
---------------------------------------------------------------------------
\452\ See, e.g., Southern Companies; and Wisconsin PSC.
\453\ Wisconsin PSC at 13-14 (citing Order No. 1000, FERC Stats.
& Regs. ] 31,323 at P 334, 340).
\454\ Wisconsin PSC at 14 (citing 324 U.S. 515, 525-27 (1945)).
\455\ Southern Companies at 102 (citing Alabama Power Co. v.
FERC, 993 F.2d 1557 (D.C. Cir. 1993)).
---------------------------------------------------------------------------
374. Some petitioners argue that existing rights of first refusal
in Commission-approved RTO/ISO tariffs and agreements were crafted and
negotiated expressly to ensure that each incumbent load-serving
transmission owner could continue to fulfill its state-imposed service
obligations.\456\ Baltimore Gas & Electric states that the federal
right of first refusal stems from the natural monopoly franchise
service obligations that retail public utilities must abide by, in part
through their Commission-jurisdictional wholesale transmission lines.
According to Baltimore Gas & Electric, Commission-jurisdictional
tariffs and agreements merely acknowledge the right of first refusal
that Baltimore Gas & Electric had before joining PJM and others had
before joining other RTOs and ISOs. Thus, Baltimore Gas & Electric
argues that there is no such thing as a federal right of first refusal
derived from a Commission tariff, but rather a right of first refusal
in a Commission tariff connotes that the transmission owner retained
its existing state-granted right of first refusal when it voluntarily
submitted itself to the regional planning process of whatever RTO or
ISO it opted to join, if any.
---------------------------------------------------------------------------
\456\ Ameren; MISO Transmission Owners Group 2; and PSEG
Companies. PSEG Companies state that their points in this regard are
buttressed by comments from Pennsylvania PUC, ITC, and SPP.
---------------------------------------------------------------------------
375. Moreover, MISO contends that the removal of such provisions
would place MISO in the role of deciding who should construct planned
transmission facilities. It states that state law, not federal, governs
the preconditions associated with the siting and construction of
transmission and the appurtenant rights associated with such
construction including, but not limited to, the right of eminent
domain. As such, MISO argues that its role under Order No. 1000 should
not be to determine who should build specific transmission projects
identified through its transmission planning process because it has not
been vested with any rights by any state legislature or state
commission regarding the construction of the facilities that may be
deemed necessary as a result of the MISO Transmission Expansion Plan
process or any other plan developed by MISO and its stakeholders.
Therefore, MISO requests that the Commission reconsider Order No.
1000's generic requirement regarding the elimination of rights of first
refusal from jurisdictional tariffs and agreements, insofar as that
requirement would entail modification of the Transmission Owners
Agreement provisions on the transmission owners' right to build, and
related tariff provisions.
376. Southern Companies argue that the Commission seeks to regulate
who has the right to construct and own transmission facilities by
regulating who is entitled to the benefits of the regional and
interregional cost allocation processes. Southern Companies argue that
nothing in section 206 confers upon the Commission authority to
require, authorize, or regulate who will construct or own transmission
facilities or sponsor a transmission project in a transmission planning
process.\457\ Similarly, Ad Hoc Coalition of Southeastern Utilities
argues that although the Commission does not directly mandate
construction according to regional plans, this distinction may prove to
be immaterial as the financially punitive effect of constructing
redundant transmission facilities makes deference to nonincumbent
transmission developers effectively mandatory.\458\ Large Public Power
Council makes a similar argument. Ad Hoc Coalition of Southeastern
Utilities and Large Public Power Council assert that this creates a
dilemma for incumbent transmission developers that must effectively
defer to the plans of nonincumbent developers but also must continue to
satisfy their service obligations while complying with potentially
costly mandatory and enforceable reliability standards.
---------------------------------------------------------------------------
\457\ Southern Companies at 60 (citing Northern Gas Co. v.
Kansas Comm'n, 372 U.S. 84, 91-93 (1963)).
\458\ Ad Hoc Coalition of Southeastern Utilities at 57 (citing
Associated Gas, 824 F.2d at 1000-01).
---------------------------------------------------------------------------
(a) Commission Determination
377. We affirm the Commission's finding in Order No. 1000 that the
nonincumbent transmission developer reforms do not result in the
regulation of matters reserved to the states, such as transmission
construction, ownership or
[[Page 32244]]
siting.\459\ As the Commission explained in Order No. 1000, the
nonincumbent transmission developer reforms are focused solely on
public utility transmission provider tariffs and agreements subject to
the Commission's jurisdiction and are not intended to limit, preempt,
or otherwise affect state or local laws or regulations with respect to
construction of transmission facilities, including but not limited to
authority over siting or permitting of transmission facilities.\460\
---------------------------------------------------------------------------
\459\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 287.
\460\ Id.
---------------------------------------------------------------------------
378. We disagree with petitioners that argue that the Commission
needs new authority in the FPA to adopt the nonincumbent transmission
developer reforms, as these arguments rest on the faulty premise that
the Commission is somehow regulating the construction of transmission
facilities. Order No. 1000 does not address transmission construction.
Instead, the nonincumbent transmission developer reforms in Order No.
1000 ensure that nonincumbent transmission developers have a comparable
opportunity to incumbent transmission developers/providers to submit
transmission projects for evaluation and potential selection in the
regional transmission plan for purposes of cost allocation. These
reforms further provide that a nonincumbent transmission developer's
project that is selected in the regional transmission plan for purposes
of cost allocation will not be subject to any federal right of first
refusal, which must be eliminated, except in certain limited
circumstances. The reforms do not, however, speak to which entity may
ultimately construct any transmission facilities. Moreover, we note
that we agree with Baltimore Gas & Electric that eliminating a federal
right of first refusal is unrelated to the Commission's authority under
section 216 of the FPA.\461\
---------------------------------------------------------------------------
\461\ 16 U.S.C. 824p (2006). Section 216 addresses the
designation and siting of transmission facilities within National
Interest Electric Transmission Corridors.
---------------------------------------------------------------------------
379. We disagree with petitioners that argue that eliminating a
federal right of first refusal preempts state law, or is otherwise
prohibited by state law. As noted above, the Commission made clear that
its reforms are focused on Commission-jurisdictional tariffs and
agreements, and are not intended to preempt state or local laws or
regulations. Moreover, as explained in greater detail below, an
incumbent transmission provider has several choices for meeting its
reliability needs and service obligations. In particular, Order No.
1000 permits an incumbent transmission provider to meet its reliability
needs or service obligations by choosing to build new transmission
facilities that are located solely within its retail distribution
service territory or footprint and that are not selected for regional
cost allocation.\462\
---------------------------------------------------------------------------
\462\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 262.
---------------------------------------------------------------------------
380. In response to Wisconsin PSC, we note that the Commission
specifically declined in Order No. 1000 to adopt the proposal in the
rulemaking that would have required public utility transmission
providers in the regional transmission planning process to provide
transmission developers a right to construct and own a transmission
facility selected in a regional transmission plan for purposes of cost
allocation.\463\ The Commission also declined to a provide transmission
developer with an ongoing right to build and own a transmission project
that it proposed but that was not selected.\464\ Because the Commission
did not adopt these proposals, we do not need to address whether the
Commission has the authority to grant them.
---------------------------------------------------------------------------
\463\ Id. P 338.
\464\ Id. P 340.
---------------------------------------------------------------------------
381. In response to Baltimore Gas & Electric's argument that
Commission-jurisdictional tariffs and agreements merely acknowledge a
right of first refusal that it had before joining PJM, we affirm the
statement in Order No. 1000 that ``[t]his Final Rule does not require
removal of references to such state or local laws or regulations from
Commission-approved tariffs or agreements.'' \465\ Accordingly, such a
right based on a state or local law or regulation would still exist
under state or local law even if removed from the Commission-
jurisdictional tariff or agreement, and nothing in Order No. 1000
changes that law or regulation, for Order No. 1000 is clear that
nothing therein is ``intended to limit, preempt, or otherwise affect
state or local laws or regulations with respect to construction of
transmission facilities.'' \466\
---------------------------------------------------------------------------
\465\ Id. P 253 n.231.
\466\ Id. P 287.
---------------------------------------------------------------------------
382. We disagree with MISO that eliminating a federal right of
first refusal would put it in the position of deciding who should
construct planned transmission facilities. Rather, the transmission
planning and cost allocation reforms in Order No. 1000 are designed to
allow the public utility transmission providers in a transmission
planning region to evaluate whether new transmission facilities would
efficiently and cost-effectively meet their transmission needs, as well
as to provide a cost allocation method for those facilities selected in
the regional transmission plan for purposes of cost allocation. We
acknowledge that a decision made to select a new transmission facility
in the regional transmission plan for purposes of cost allocation may
affect which entity ultimately constructs and owns transmission
facilities. However, we reiterate that nothing in Order No. 1000
creates any new authority for the Commission nor public utility
transmission providers acting through a regional transmission planning
process to site or authorize the construction of transmission projects.
Furthermore, Order No. 1000 does not prohibit an incumbent transmission
provider from having a federal right of first refusal for a new local
transmission facility that is not selected in a regional transmission
plan for purposes of cost allocation.
iii. Arguments That the Commission Must Meet the Mobile-Sierra Public
Interest Standard Before Requiring Federal Rights of First Refusal To
Be Removed From Agreements
383. Several petitioners argue that the Commission cannot modify a
contractual federal right of first refusal without first making a
determination that the federal right of first refusal seriously harms
the public, which they argue the Commission failed to do.\467\ MISO
Transmission Owners Group 2 argues that in Mobile-Sierra, the U.S.
Supreme Court found that the Commission must presume that the rate set
out in a freely-negotiated wholesale energy contract meets the just and
reasonable requirement, and that this presumption can be overcome only
if the Commission concludes that the contract seriously harms the
public interest. MISO Transmission Owners Group 2 also argues that
other Supreme Court precedent found that the Commission cannot base its
demand that public utility transmission providers modify existing
contracts on a finding that the existing contract provisions may lead
to rates that are unjust and unreasonable.\468\
---------------------------------------------------------------------------
\467\ See, e.g., Ameren; Sponsoring PJM Transmission Owners at
21 (citing Morgan Stanley Capital Group v. Pub. Util. Dist. No. 1 of
Snohomish City., 554 U.S. 527, 545-46 (2008)); Baltimore Gas &
Electric; PSEG Companies at 9-11, 14-15 (citing comments from
Oklahoma Gas & Electric Co., Ad Hoc Coalition of Southeastern
Utilities, North Dakota & South Dakota Commissions, Alabama PSC,
Southern Companies, Baltimore Gas & Electric Co., MidAmerican,
Pacific Gas & Electric, PJM, PSEG Companies, and Southern California
Edison); MISO; MISO Transmission Owners Group 2; Northern Tier
Transmission Group.
\468\ MISO Transmission Owners Group 2 at 32 (citing Morgan
Stanley Capital Group, Inc. v. Public Utility Dist. No. 1, 554 U.S.
527 (2008) and NRG Power Marketing, LLC v. Maine PUC, 130 S.Ct. 693
(2010)).
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[[Page 32245]]
384. Some petitioners state that the federal right of first refusal
is embodied in the PJM Transmission Owner's Agreement, and thus assert
that the Commission must make a Mobile-Sierra finding before it can
modify the agreement.\469\ PSEG Companies argue that the Commission
cannot make such a finding because nothing in Order No. 1000 or in the
rulemaking record would support such a conclusion.
---------------------------------------------------------------------------
\469\ See, e.g., Sponsoring PJM Transmission Owners; Baltimore
Gas & Electric; and PSEG Companies.
---------------------------------------------------------------------------
385. Other petitioners also argue that Order No. 1000 does not
discuss how existing contractual rights of first refusal, such as that
in the Midwest ISO Transmission Owners Agreement, seriously harm the
public interest.\470\ MISO states that while Order No. 1000 purports to
avoid addressing Mobile-Sierra issues with regard to any particular
jurisdictional agreement, the Commission erred in requiring generically
in this proceeding a modification that it cannot require specifically
for each jurisdictional agreement without determining that the
retention of such a right in the particular agreement is against the
public interest, unjust, unreasonable, or unduly discriminatory or
preferential, or otherwise anticompetitive. MISO further argues that
with respect to the public interest standard, the Commission cannot
make a generic finding as a substitute for the specific finding it must
make before declaring that the provisions of a particular agreement are
contrary to the public interest.
---------------------------------------------------------------------------
\470\ Ameren at 16 (citing Agreement of Transmission Facilities
Owners to Organize the Midwest Independent Transmission System
Operator, Inc., A Delaware Non-Stock Corporation, Third Revised Rate
Schedule FERC No. 1); MISO; MISO Transmission Owners Group 2.
---------------------------------------------------------------------------
386. In addition, PSEG Companies disagree with the statement in
Order No. 1000 that this issue can be deferred until the compliance
stage of this proceeding. Specifically, they take issue with the
Commission's conclusion that the record was insufficient to address
National Grid's comment regarding Mobile-Sierra and the ISO-NE
operating agreement, stating that if the Commission had serious
evidence of harm to the public interest then it should have had no
difficulty in articulating it in Order No. 1000. PSEG Companies assert
that it is ironic that while the Commission chose to engage in
nationwide abrogation of individual contracts in a generic rulemaking,
it seeks to avoid the required analysis on the ground that a rulemaking
proceeding is an inappropriate vehicle for such an analysis. They also
argue that the Commission's decision to defer review of the Mobile-
Sierra protections to the compliance stage has no basis in law,
explaining that the Commission is bound by law to apply the standard
before abrogating any contracts. PSEG Companies state that the
compliance stage is not the appropriate procedural stage to address
this issue because under Mobile-Sierra the Commission has the burden to
make its public interest finding and it is not the contracting parties'
burden to defend the provisions that the Commission seeks to
modify.\471\
---------------------------------------------------------------------------
\471\ PSEG Companies at 13 (citing Wisconsin Public Power, Inc.
v. FERC, 493 F.3d 239 (D.C. Cir. 2007)).
---------------------------------------------------------------------------
387. Sunflower, Mid-Kansas, and Western Farmers request a partial
stay of Order No. 1000's effectiveness, at least for RTOs that have
limited federal rights of first refusal, if the Commission does not
grant their requests for rehearing and clarification, so that RTOs are
not required to remove any federal right of first refusal provisions
until Order No. 1000 is final and non-appealable. They argue that it is
highly likely that Order No. 1000 will be appealed and that the
rehearing and appeals process may span several years. Sunflower, Mid-
Kansas, and Western Farmers assert that stakeholders will be
irreparably harmed if this portion of Order No. 1000 is effective
before the appeals process is complete, citing the time and resources
needed to modify existing tariffs and, more important, the loss of SPP
transmission owners' rights that cannot be restored if the courts rule
against the Commission on this issue.
(a) Commission Determination
388. The Commission affirms 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. We continue to find that the record in this rulemaking
proceeding is not sufficient to address the specific issues raised
regarding individual agreements. Accordingly, we reject arguments that
the Commission must address in this generic rulemaking proceeding
whether any particular agreement is protected by a Mobile-Sierra
provision. Furthermore, in response to PSEG Companies, the Commission
decided in Order No. 1000 when it will address the issue of whether a
federal right of first refusal provision is protected by Mobile-Sierra;
it did not and cannot shift the burden to defend such provisions to
contracting parties.
389. As the Commission explained in Order No. 1000, 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. We clarify, however, 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. The
Commission will first decide, based on a more complete record,
including the viewpoints of other interested parties, whether the
agreement is protected by a Mobile-Sierra provision, and if so, whether
the Commission has met the applicable standard of review such that it
can require the modification of the particular provisions.\472\ If the
Commission determines that the agreement is protected by a Mobile-
Sierra provision and that it cannot meet the applicable standard of
review, then the Commission will not consider whether the revisions
submitted to the Commission-jurisdictional tariffs and agreements
comply with Order No. 1000. However, if the Commission determines that
the agreement is not protected by a Mobile-Sierra provision or that the
Commission has met the applicable standard of review, then the
Commission will decide whether the revisions to the Commission-
jurisdictional tariffs and agreements comply with Order No. 1000 and,
if such tariffs and agreements are accepted, would become effective
consistent with the approved effective date. As a result, 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 a
Mobile-Sierra provision and whether the Commission has met the
applicable standard of review, while at the same time the Commission is
ensuring that the Order No. 1000 compliance process proceeds
expeditiously and efficiently.
---------------------------------------------------------------------------
\472\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 292.
---------------------------------------------------------------------------
390. We also deny Sunflower, Mid-Kansas, and Western Farmers'
request for a partial stay of the requirement to remove a federal right
of first refusal from Commission-jurisdictional tariffs and agreements.
In considering requests for a stay, the Commission has applied the
standards set forth in section 705 of
[[Page 32246]]
the Administrative Procedure Act,\473\ and has granted a stay ``when
justice so requires.'' \474\ In deciding whether justice requires a
stay, the Commission considers several factors, including: (1) Whether
the party requesting the stay will suffer irreparable injury without a
stay; (2) whether issuing the stay may substantially harm other
parties; and (3) whether a stay is in the public interest.\475\ The
Commission's general policy is to refrain from granting stays of its
orders to assure definiteness and finality in Commission
proceedings.\476\ If the party requesting the stay is unable to
demonstrate that it will suffer irreparable harm absent a stay, the
Commission need not examine the other factors.\477\ As the D.C. Circuit
has explained, a harm must be both certain and actual rather than
theoretical, and ``mere injuries, however substantial, in terms of
money, time and energy necessarily expended in the absence of a stay
are not enough.''\478\
---------------------------------------------------------------------------
\473\ 5 U.S.C. 705 (2006).
\474\ Id.
\475\ See, e.g., CMS Midland, Inc., 56 FERC ] 61,177 at P 61,631
(1991), aff'd sub nom. Mich. Mun. Coop. Group v. FERC, 990 F.2d 1377
(D.C. Cir.), cert. denied, 510 U.S. 990 (1993).
\476\ Id.
\477\ Id.
\478\ Wisconsin Gas Co. v. FERC, 785 F.2d 699, 674 (D.C. Cir.
1985).
---------------------------------------------------------------------------
391. Sunflower, Mid-Kansas, and Western Farmers' request for stay
fails to meet the first criterion, which requires it to show that it
will suffer irreparable injury without a stay of the requirement to
eliminate a federal right of first refusal. They argue that they must
spend time and resources to modify existing tariffs. However, we find
that this type of economic loss is not sufficient to warrant a stay.
Furthermore, while Sunflower, Mid-Kansas and Western Farmers may lose
the opportunity to exercise a federal right of first refusal, it
amounts to speculation to assert that this will necessarily cause
Sunflower, Mid-Kansas and Western Farmers to lose the opportunity to
build a transmission project that they could have exercised a federal
right of first refusal to build. They also will still have the
opportunity to submit projects for evaluation and potential selection
in the regional transmission plan for purposes of cost allocation as
well as to build local transmission projects.\479\ Thus, the harm that
Sunflower, Mid-Kansas and Western Farmers argue that they will suffer
is speculative because Sunflower, Mid-Kansas and Western Farmers cannot
point to a specific transmission project that they will lose the right
to construct and own at this time, or in the immediate future.
Accordingly, we find that Sunflower, Mid-Kansas and Western Farmers
have not shown that they will suffer irreparable harm absent a stay of
the nonincumbent transmission developer reforms in Order No. 1000.\480\
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\479\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 318.
\480\ Moreover, though unnecessary to support our denial of this
motion for stay, we note that issuing a stay here may substantially
harm other parties, thereby violating the second factor the
Commission considers in whether to grant a stay. As the Commission
has explained, greater participation by transmission developers in
the transmission planning process may lower the cost of new
transmission facilities for transmission customers, enabling more
efficient or cost-effective solutions to regional transmission
needs. Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 291.
Accordingly, because the removal of a federal right of first refusal
applies only to new transmission facilities selected in a regional
transmission plan for purposes of cost allocation, granting a stay
of the requirement to eliminate a federal right of first refusal
would delay these potential cost-saving and efficiency benefits for
all entities in the region for the duration of the stay.
---------------------------------------------------------------------------
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. Final Rule
392. In Order No. 1000, the Commission directed public utility
transmission providers to eliminate provisions in Commission-
jurisdictional tariffs and agreements that establish a federal right of
first refusal for an incumbent transmission provider with respect to
transmission facilities selected in a regional transmission plan for
purposes of cost allocation.\481\ However, Order No. 1000 also limited
the applicability of that elimination requirement in important ways.
The Commission stated that its focus was on the set of transmission
facilities that are evaluated at the regional level and selected in the
regional transmission plan for purposes of cost allocation, and that it
was not requiring removal from Commission-jurisdictional tariffs and
agreements of federal rights of first refusal as applicable to a local
transmission facility.\482\ Additionally, the Commission explained that
the reforms do not affect the right of an incumbent transmission
provider to build, own, and recover costs for upgrades to its own
transmission facilities, such as in the case of tower change outs or
reconductoring, regardless of whether an upgrade has been selected in a
regional transmission plan for purposes of cost allocation.\483\ The
Commission further noted that the reforms are not intended to alter an
incumbent transmission provider's use and control of its existing
rights-of-way, the retention, modification, or transfer of which remain
subject to the relevant law or regulation that granted the right-of-
way.\484\
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\481\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 313.
\482\ Id. P 318.
\483\ Id. P 319.
\484\ Id.
---------------------------------------------------------------------------
393. In a separate section of Order No. 1000, the Commission stated
that for purposes of Order No. 1000, ``nonincumbent transmission
developer'' refers to two categories of transmission developer: ``(1) A
transmission developer that does not have a retail distribution service
territory or footprint; and (2) a public utility transmission provider
that proposes a transmission project outside of its existing retail
distribution service territory or footprint, where it is not the
incumbent for purposes of that project.'' By contrast, the Commission
explained that an ```incumbent transmission developer/provider' is an
entity that develops a transmission project within its own retail
distribution service territory or footprint.'' \485\
---------------------------------------------------------------------------
\485\ Id. P 225.
---------------------------------------------------------------------------
394. The Commission also distinguished between a transmission
facility in a regional transmission plan and a transmission facility
selected in a regional transmission plan for purposes of cost
allocation.\486\ The Commission also defined the term ``local
transmission facility,'' which it stated is a transmission facility
located solely within a public utility's retail distribution service
territory or footprint that is not selected in the regional
transmission plan for purposes of cost allocation.\487\
---------------------------------------------------------------------------
\486\ Id. PP 63-66.
\487\ Id. PP 63-64.
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b. Requests for Rehearing and Clarification
395. Several petitioners seek rehearing or clarification regarding
the implementation of the removal of a federal right of first refusal
for projects that are selected in the regional transmission plan for
purposes of cost allocation.\488\ Northern Tier Transmission Group
requests that the Commission clarify the types of Commission-
jurisdictional agreements that are subject to Order No. 1000's federal
right of first refusal prohibition as well as the types of provisions
that constitute federal rights of first refusal. Northern Tier
Transmission Group asserts that these clarifications are necessary to
determine which bilateral
[[Page 32247]]
agreements are affected by the rule and the types of provisions that
are prohibited in future contracts. In addition, Northern Tier
Transmission Group argues that the modification of bilateral agreements
undermines the balance of the agreements, and therefore must be
accomplished in accordance with relevant Commission precedent.
---------------------------------------------------------------------------
\488\ See, e.g., Northern Tier Transmission Group; Duke; AEP;
AEP; Sunflower, Mid-Kansas, and Western Farmers; and Dayton Power
and Light.
---------------------------------------------------------------------------
396. Some petitioners seek clarification of what Order No. 1000
intends when referring to ``nonincumbent transmission developer'' and
``incumbent transmission developer/provider.'' \489\ Transmission
Access Policy Study Group and APPA state that the definitions of
nonincumbent transmission developer and incumbent transmission
developer/provider would exclude most municipal electric systems and
electric cooperatives, as well as other public power entities. For
example, Transmission Access Policy Study Group and APPA argue that
because most non-public utility transmission developers have retail
distribution service territories, they would not qualify as
nonincumbent transmission developers under the first part of the
definition. They also argue that non-public utility transmission
providers, as defined in section 201(f) of the FPA, are not public
utilities under FPA section 201(e); thus they would not qualify as
nonincumbent transmission developers under the second part of the
definition. Transmission Access Policy Study Group believes that this
limitation was inadvertent and that the Commission should correct this
error while at the same time keeping in mind that some references to
``nonincumbent transmission developer'' may in fact be intended to
apply only to jurisdictional entities.
---------------------------------------------------------------------------
\489\ See, e.g., Transmission Access Policy Study Group; and
APPA.
---------------------------------------------------------------------------
397. APPA notes that Order No. 1000 at P 227 requires incumbent
transmission developers/providers to develop a framework that includes
provisions regarding how best to address participation by nonincumbent
transmission developers. Therefore, APPA and Transmission Access Policy
Study Group are concerned that, if non-public entities do not qualify
as nonincumbent transmission developers, incumbent transmission
providers will not include provisions to address their participation.
Accordingly, they ask the Commission to make clear that non-public
utility transmission developers can be considered nonincumbent
transmission developers.
398. APPA also argues that, given these definitions, incumbent
transmission developers/providers may develop a framework that prevents
public power utilities from participating in joint ownership of
regional transmission projects. On rehearing, APPA requests that the
Commission clarify that this result was not intended and that the
Commission revise the relevant definitions to allow for participation
by public power entities in transmission projects.Otherwise, APPA
requests rehearing of this issue on the grounds that the definitions
are unduly discriminatory as applied to public power utilities and
preferential as applied to public utilities and other for-profit
entities, in violation of sections 205 and 206 of the FPA.
399. Some petitioners seek guidance or clarification regarding the
term ``footprint'' as it is used in the definitions of a ``local
transmission facility'' and ``incumbent transmission developer.'' \490\
American Transmission and ITC Companies interpret the term footprint to
be directed at entities, such as transmission-only companies, that do
not have retail distribution service territories, and thus expands the
definitions of an incumbent and a local transmission facility instead
of further defining retail distribution service territory. If the
Commission instead clarifies that the term is intended to further
define retail distribution service territory, then American
Transmission seeks rehearing of the definition of incumbent
transmission developer, arguing that it is arbitrary and capricious and
discriminatory to exclude transmission-only companies from the
definition.It argues that it should be considered an incumbent because
it is subject to the mandatory NERC reliability standards for its
facilities. As for the definition of a local transmission facility, ITC
Companies state that they have no local transmission plans and that all
transmission projects they propose are evaluated and included under the
MISO or SPP Transmission Expansion Plans and are not ``merely rolled
up.'' However, ITC Companies state that these projects may be located
solely within the footprint of one or more of the ITC Companies.
---------------------------------------------------------------------------
\490\ See, e.g., ITC Companies; LS Power; American Transmission;
Wisconsin PSC; and Edison Electric Institute.
---------------------------------------------------------------------------
400. Wisconsin PSC adds that American Transmission, for example, is
effectively an incumbent transmission provider with a footprint
equivalent to the aggregate franchise territories of its wholesale
load-serving entity customers. Wisconsin PSC asserts that categorizing
American Transmission as a nonincumbent transmission developer would
treat it as a merchant transmission developer in its home territory of
the last ten years and compel it to double up on the essentially local
planning processes as if it was a merchant, even though it currently
conducts regional planning in coordination with MISO's regional
planning.Wisconsin PSC asserts that the extra costs from such
duplicative planning would be unjust and unreasonable and therefore it
requests that the Commission clarify the categorization of nonincumbent
transmission developer to exclude transmission-only entities.
401. Duke seeks confirmation that a nonincumbent transmission
developer either becomes an incumbent transmission developer/provider
when its project is energized, if not sooner, or that the provisions of
paragraph 319 of Order No. 1000, relating to upgrades and use of
rights-of-way, apply to nonincumbents that construct projects. Also,
according to Duke, the term ``retail distribution,'' as used in the
definitions of nonincumbent transmission developer and incumbent
transmission developer/provider, modifies ``service territory'' but not
``footprint.''Thus, Duke contends that, under this interpretation, the
nonincumbent developer of an actual project will eventually have a
footprint and thus become an incumbent as to that limited footprint.
However, if the Commission clarifies that nonincumbents never become
incumbents, then it requests that the Commission nonetheless grant
nonincumbents the same rights described in paragraph 319 of Order No.
1000 as to its own facilities and rights of way and describe when those
rights would exist. It recommends that a nonincumbent obtains a federal
right of first refusal no later than energization of its facilities.At
a minimum, Duke requests detailed clarification on this issue so as to
avoid litigation on compliance.
402. Edison Electric Institute seeks clarification that public
utility transmission providers constructing new facilities in their
``footprint'' pursuant to service obligations imposed on them under
federal, state, or local law or under long-term contracts are included
in the definition of incumbent transmission providers. It notes that
some transmission facility-owning public utilities may lack a retail
distribution service territory, and that other transmission facility-
owning public utilities with retail distribution service territories
may need to construct new transmission facilities that are not fully
contained within those retail
[[Page 32248]]
distribution territories. Thus, it seeks clarification that both kinds
of transmission facility-owning public utilities continue to have the
same right to construct reliability projects not subject to regional
cost allocation where necessary to meet their reliability needs or
service obligations. It also seeks confirmation that the use of the
term ``footprint'' is intended to capture new facility construction
that may be separate from a retail distribution service territory but
is nonetheless being constructed by an incumbent transmission owning
utility to meet reliability or service obligation needs, adding that
this clarification would tie the right of an incumbent transmission
provider to choose to build facilities not submitted for regional cost
allocation to the existence of a service obligation under federal,
state, or local law or under long-term contracts. To the extent that
the Commission intended to grant this right in favor of some public
utility transmission provider service obligations and not others,
Edison Electric Institute argues that the Commission is required to
explain and justify its decision.
403. Other petitioners request clarification or rehearing as to how
to determine whether a project is considered a regional or local
project.\491\ For instance, LS Power requests clarification of how the
Commission intends to apply this local exemption. LS Power states that
the Commission did not explain how a footprint might differ from a
retail distribution area, which may have a different meaning in
different states. Also, LS Power states that while a retail
distribution area is a familiar concept, it does not provide a
geographic-based definition.For example, a utility may own a
transmission line that geographically extends beyond its retail service
area that it may believe should be part of its footprint, but that line
may cross into another transmission provider's geographical retail
distribution area which the other transmission provider considers to be
part of its footprint. LS Power also states that joint ownership of a
substation or transmission line is common, where several entities all
have rights to use the capacity of the line. LS Power also claims that
it is unclear how this definition would be applied in the context of an
RTO, where the transmission provider's footprint covers the entire
region.
---------------------------------------------------------------------------
\491\ See, e.g., Duke; and AEP.
---------------------------------------------------------------------------
404. Accordingly, LS Power requests clarification that within and
outside an RTO, a ``local transmission facility'' is one that is
located within the geographical boundaries of the retail distribution
service territory served by the public utility transmission provider as
of the effective date of Order No. 1000 and interconnecting solely to
the public utility transmission provider's existing facilities. LS
Power continues that where there are affiliated public utility
transmission providers located in adjacent and electrically connected
geographic areas, they may be treated as a single transmission owner
only if, as of the date Order No. 1000 became effective, the affiliates
have, in the past, conducted joint planning and maintained a single
transmission rate applicable to service provided by all such affiliates
regardless of the customer's location within the retail distribution
area of a single affiliate and, where located in a RTO, proffered a
single local plan to the RTO and participated in RTO affairs as a
single transmission owner (e.g., voting rights under all jurisdictional
agreements). LS Power further states that any projects connecting, in
whole or in part, to facilities owned by another transmission owner or
to jointly owned facilities would not constitute local facilities.
Last, it argues that ``local'' should be defined as of the effective
date of Order No. 1000, because the area in which an incumbent
transmission owner can claim an exemption to the elimination of the
federal right of first refusal should not be the subject of corporate
structuring.
405. Duke asserts that the primary difficulty in differentiating
regional and local projects is that there are many ways to interpret
the phrase ``transmission facilities selected in a regional
transmission plan for purposes of cost allocation.'' According to Duke,
many RTOs have adopted cost allocation approaches for all types of
projects and that even local projects ultimately are included in the
``regional plan.'' In addition, Duke asserts that a pricing zone that
consists of the retail distribution service territory of a single load-
serving entity that was also a transmission provider is an anomaly, and
that it is more likely that a typical pricing zone will consist of a
public utility transmission provider and more than one retail load-
serving entity with a service territory, such as, for instance, a non-
jurisdictional distribution and/or transmission company. Accordingly,
Duke seeks clarification that, under a zonal approach to cost
allocation, a facility whose costs are allocated under an RTO tariff to
a single RTO pricing zone, and which is located in that pricing zone,
be deemed a local facility.
406. Duke also adds that, under a non-RTO model or dominant
provider model, all the load in a single zone would be network load of
the public utility transmission provider, with any other transmission
owners receiving credits for their integrated transmission facilities.
Accordingly, Duke requests clarification that the Commission intended
that single zone facilities may be classified as local facilities, as
long as the general construct under a non-RTO model, or dominant
provider model, is met. Duke adds that any proposals for `re-zoning'
meant to evade the impact of the removal of a federal right of first
refusal can be addressed on compliance. If the Commission clarifies
that a single zone facility under no circumstances can be a local
facility, then Duke asserts that the Commission would effectively
obliterate the federal right of first refusal in virtually every ISO
and RTO, which could cause significant exoduses from ISOs and RTOs or
cause ISOs and RTOs to completely overhaul their entire cost allocation
processes.
407. Petitioners also seek clarification that a project that is
selected in the plan, but for which the costs are assigned to a single
utility, is considered a local facility for purposes of the
applicability of the requirement to remove the federal right of first
refusal.\492\ Specifically, Duke asks whether the focus is on the
result of a cost allocation method or the area over which the method is
applied such as an entire region. Duke urges the Commission to adopt
the results approach, and clarify that if any cost allocation approach
results in a single zone being allocated the costs of a facility, then
an RTO should be permitted to deem the facility as local and therefore,
apply a federal right of first refusal. Duke seeks clarification that
facilities that have any costs allocated outside a single zone, even if
such facilities are physically in a single zone, will be presumed to be
regional, unless they are an upgrade to existing facilities.
---------------------------------------------------------------------------
\492\ See, e.g., Duke; AEP; and Dayton Power and Light.
---------------------------------------------------------------------------
408. Dayton Power and Light also asserts that the Commission should
clarify that when all of a facility's costs are assigned to a single
utility zone, the tariff could continue to permit a federal right of
first refusal. However, Dayton Power and Light also seeks clarification
as to whether a facility that is allocated solely to one utility zone
using a regional cost allocation method should be treated differently
for purposes of a federal right of first refusal from a facility that
is allocated predominately to one utility zone, and if so, where the
break-point should be. Sunflower, Mid-
[[Page 32249]]
Kansas, and Western Farmers seek clarification (or, alternatively,
rehearing) that the definition of ``regionally funded'' excludes
projects where costs allocated to a region are not at least a majority
of the total costs.
409. In addition, ITC Companies and Xcel request clarification of
``selected in a regional transmission plan for purposes of cost
allocation'' as it applies to the transmission facilities that are
approved by MISO under its MISO Transmission Expansion Plan or by SPP
under its SPP Transmission Expansion Plan.\493\ Xcel states that Order
No. 1000 creates ambiguity by assuming that the cost allocation for
local zone projects, such as in MISO and SPP, is not identified in the
regional RTO tariff process.\494\ Xcel states that it believes that,
under Order No. 1000, the costs for a project selected in the MTEP or
STEP may permissibly be assigned to a single zone, whether that zone
includes the facilities of a single transmission owner or whether a
transmission owner has facilities that are included in other zones,
through a regional cost allocation method, and that such an allocation
is not precluded by Order No. 1000.
---------------------------------------------------------------------------
\493\ ITC Companies; Xcel at 20 (citing Order No. 1000, FERC
Stats. & Regs. ] 31,323 at n.299).
\494\ Xcel at 20 (citing Order No. 1000, FERC Stats. & Regs. ]
31,323 at n.299).
---------------------------------------------------------------------------
410. ITC Companies argue that MISO cost allocation methods fall
along a continuum that on one end includes 100 percent allocation on a
systemwide basis for multi-value projects, and on the other end are
participant funded projects assumed by project sponsors. They state
that in SPP 100 percent of the costs of Base Plan Upgrades 300kV and
above are allocated to a regionwide annual transmission revenue
requirement and recovered through a regionwide charge. They thus assert
that it is unclear whether certain projects would be considered
``transmission facilities selected * * * for purposes of cost
allocation'' under Order No. 1000.\495\ ITC Companies request
clarification that this term means those projects approved in a
regional transmission plan and which are also approved for 100 percent
regional cost allocation.They argue that if the Commission does not
clarify this term, if a project becomes ineligible for federal rights
of first refusal when any of the costs of that project are borne by
customers beyond the local zone or footprint in which that project is
located, the construction of more efficient, cost-effective multi-
purpose projects with broad regional benefits will be discouraged. They
maintain that incumbent transmission owners will oppose projects with
broader benefits in favor of less efficient projects for which their
rights of first refusal are preserved. They assert that projects will
be designed to avoid minor enhancements that would benefit a region,
but which would not justify a stand-alone, purely economic project.
---------------------------------------------------------------------------
\495\ ITC Companies specifically ask about the following: (1)
MISO Baseline Reliability Projects eligible for 20 percent regional
cost allocation but whose costs can be 100 percent allocated to the
host zone pursuant to power flow modeling; (2) MISO Market
Efficiency Projects eligible for 20 percent regional cost
allocation; and (3) SPP Base Plan Upgrades eligible for 33 percent
regional cost allocation.
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411. On the other hand, Western Independent Transmission Group
argues that the Commission failed to provide a reasoned explanation of
why it did not remove the federal right of first refusal for local
transmission facilities, and why it is not unduly discriminatory or
preferential to uphold the federal right of first refusal for
facilities not in a plan for purposes of cost allocation. Western
Independent Transmission Group also argues that Order No. 1000 did not
address in adequate detail the boundary between transmission projects
for which independent transmission developers have a right to compete,
and those projects that are reserved solely to the incumbent
transmission provider. According to Western Independent Transmission
Group, the most obvious instance where the Commission's failure to
address the subject may have significant competitive impacts on
transmission planning is the distinction between public policy projects
and transmission projects initiated through the generation
interconnection process. Western Independent Transmission Group argues
that, particularly in California, where the vast majority of approved
transmission projects in the most recent 2010/2011 planning cycle were
initiated through the generator interconnection process, the
Commission's unwillingness to address this issue effectively left
incumbent utilities with a total monopoly over the transmission built
in response to renewable energy development.
412. Petitioners also seek clarification of what is to be
considered an upgrade to an existing transmission facility such that
the elimination of the federal right of first refusal does not apply.
For example, Duke seeks clarification that if an incumbent transmission
owner cuts into its own existing transmission line to construct a new
345 kV substation that is needed for stability due to local growth on
its system, such a substation, even if a share of its costs are
allocated to all pricing zones in a region, would be covered by the
federal right of first refusal under the ``upgrades to its own
transmission facilities'' carve out. If not, then Duke asserts that a
region should be able to take this policy into account in implementing
Order No. 1000, such that a region could alter its cost allocation
method so that the type of project described above is not subject to
any regional cost allocation if the region decides such projects merit
a federal right of first refusal.
413. Similarly, ITC Companies seek clarification that the
prohibition on a federal right of first refusal does not apply to a
transmission upgrade that requires expansion of an existing right-of-
way in order to be expanded. ITC Companies argue that retaining a
federal right of first refusal for upgrades that require an expansion
of an existing right of way is necessary to avoid unintended and
adverse consequences that would undermine the optimal and cost-
effective development of the grid.
414. Finally, petitioners also request rehearing of the
Commission's decision to eliminate incumbent utility transmission
providers' existing rights to construct reliability projects.\496\ Xcel
believes that incumbent transmission providers, particularly franchised
utilities with an obligation to serve, should retain the right to
construct transmission projects necessary for the utility to provide
reliable service to their native load customers and to comply with NERC
mandatory reliability standards. Xcel asserts that this federal right
of first refusal does not need to be unlimited and supports the
inclusion of a 90-day election period during which the incumbent
transmission provider would be required to indicate its decision to
move forward with the designated project. Xcel contends that the
Commission's attempt to address utility providers' concerns by
eliminating certain penalty responsibilities fails to recognize that
utilities have an obligation to serve and are not merely worried about
financial penalties.
---------------------------------------------------------------------------
\496\ See, e.g., Xcel; and Edison Electric Institute.
---------------------------------------------------------------------------
c. Commission Determination
415. We affirm the 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. In response to Northern Tier Transmission Group, the phrase
``a federal right of first refusal'' refers only to rights of first
refusal that are created by provisions in
[[Page 32250]]
Commission-jurisdictional tariffs or agreements.\497\
---------------------------------------------------------------------------
\497\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 253
n.231.
---------------------------------------------------------------------------
416. In response to petitioners' concerns, we also clarify several
of the terms used in Order No. 1000, starting with the term
``nonincumbent transmission developer.'' In doing so, we first affirm
the definition of incumbent transmission developer/provider as ``an
entity that develops a transmission project within its own retail
distribution service territory or footprint.'' \498\ Given this
definition, we clarify that a ``nonincumbent transmission developer''
is any entity that is not an incumbent transmission developer/provider.
We believe that this clarification, along with the others made in this
order, addresses the concerns expressed by Transmission Access Policy
Study Group and APPA that the definitions of nonincumbent transmission
developer and incumbent transmission developer/provider in Order No.
1000 would exclude certain municipal electric systems and electric
cooperatives, as well as other public power entities.
---------------------------------------------------------------------------
\498\ Id. P 225.
---------------------------------------------------------------------------
417. However, as discussed more fully below, we find that in order
for a non-public utility to be considered a nonincumbent transmission
developer, it must satisfy the enrollment requirement if it or an
affiliate has load in the transmission planning region where it
proposes a transmission project for selection in the regional
transmission plan for purposes of cost allocation as would any other
potential transmission developer.\499\ As an initial matter, we note
that the Commission did not intend through its definition of
nonincumbent transmission developer in Order No. 1000 to exclude any
transmission developer, including a non-public utility transmission
developer, from being able to propose transmission projects and have
them evaluated and selected by a regional transmission planning process
for purposes of cost allocation, so long as that transmission developer
abides by the same requirements as those imposed on public utility
transmission providers. Allowing entities, such as non-public utility
transmission developers, the opportunity to potentially propose a
transmission project as a nonincumbent transmission developer furthers
the Commission's goal in Order No. 1000 of ensuring that all
transmission developers have a comparable opportunity to incumbent
transmission developers/providers to propose a transmission project for
selection in the regional transmission plan for purposes of cost
allocation.
---------------------------------------------------------------------------
\499\ We refer to non-public utility entities that seek to
propose projects in a regional transmission planning process as
``non-public utility transmission developers,'' which may include
both non-public utility transmission providers that already own and
operate transmission facilities and transmission-dependent non-
public utilities that may wish to develop, construct, or own
transmission facilities in the future.
---------------------------------------------------------------------------
418. However, we also recognize that it would be fundamentally
unfair and thereby may lead to an unjust and unreasonable or unduly
discriminatory or preferential result to allow a transmission
developer, whether it is a public utility transmission developer or a
non-public utility transmission developer, to seek regional cost
allocation for a proposed transmission project in a transmission
planning region in which it or an affiliate has load, but where neither
it, nor that affiliate, has enrolled in that region where its load is
located. Such a result would permit a transmission developer to
allocate the costs of its project to other entities in the region
pursuant to that region's cost allocation method--without first
enrolling itself or its affiliate in the transmission planning region
in which its load is located and potentially being allocated costs for
other transmission projects for which it is found to be a
beneficiary.\500\
---------------------------------------------------------------------------
\500\ For discussion of enrolling in a transmission planning
region, see the Regional Transmission Planning Requirements section.
See discussion supra at section III.A.2.c.
---------------------------------------------------------------------------
419. Therefore, Order No. 1000's reforms regarding the submission
and evaluation of proposals for potential selection in a regional
transmission plan for purposes of cost allocation will apply to a
transmission developer that has load or an affiliate within an area
that would normally be considered a geographic part of a transmission
planning region if the transmission developer or its affiliate
transmission provider in that area enrolls in the transmission planning
region in which that load is located. We believe that in most cases, it
should be clear where an entity's load is located and therefore the
region in which it would be expected to enroll. However, should
disputes arise over the choice of a region, we will address them on a
case-by-case basis utilizing the standard found in Order No. 890 and
Order No. 1000, which provides that ``the scope of a transmission
planning region should be governed by the integrated nature of the
regional power grid and the particular reliability and resource issues
affecting individual regions.'' \501\ We emphasize that an entity,
including a non-public utility transmission developer, that does not
have load within a transmission planning region may propose a
transmission project for evaluation and potential selection in that
region's transmission plan for purposes of cost allocation without
enrolling in that region, as long as it satisfies the transmission
planning region's other requirements for doing so, such as meeting the
qualification criteria for proposing projects found in Order No. 1000.
---------------------------------------------------------------------------
\501\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 160
(citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 527).
---------------------------------------------------------------------------
420. Turning to other terms used in Order No. 1000, we also clarify
that the phrase ``retail distribution,'' as used in the definitions of
incumbent transmission developer/provider, nonincumbent transmission
developer and local transmission facility, does not modify footprint.
Instead, the term ``footprint,'' as used in these definitions was
intended to include, but not be limited to, the location of the
transmission facilities of a transmission-only company that owns and/or
controls the transmission facilities of formerly vertically-integrated
utilities, as well as the location of the transmission facilities of
any other transmission-only company.
421. In response to Duke, we agree that a nonincumbent transmission
developer will have a footprint at the time that its transmission
facility is energized. As such, we clarify that a nonincumbent
transmission developer will then become an incumbent transmission
developer/provider for that energized transmission facility and will
thereafter have all the rights and obligations that accrue to such
entities under Order No. 1000, such as being able to maintain a federal
right of first refusal for local transmission facilities and upgrades
to those transmission facilities.
422. In response to Edison Electric Institute, we note that there
are a great variety of fact patterns that may fall under its request.
For example, Edison Electric Institute does not explain whether the new
transmission facility would go through the retail distribution service
territory of the incumbent transmission owning utility, that of another
entity, or an ``unassigned'' territory. Thus, we decline to find
generically that any particular transmission facility, whether it is
needed to meet a reliability, economic, or transmission need driven by
a Public Policy Requirement, developed outside of an existing retail
distribution service territory or footprint, should be considered a
part of that entity's footprint.
[[Page 32251]]
423. We clarify that Order No. 1000 does not require elimination of
a federal right of first refusal for a new transmission facility if the
regional cost allocation method results in 100% of the facility's cost
being allocated to the public utility transmission provider in whose
retail distribution service territory or footprint the facility is to
be located. Accordingly, we clarify 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. Although public utility transmission
providers in a transmission planning region may determine, based on
non-discriminatory evaluation criteria, that a proposed transmission
facility is likely to have regional benefits so that the transmission
facility's costs should be allocated regionally, it is not until the
cost allocation method is applied that the beneficiaries are
identified.
424. Petitioners request clarification about whether a transmission
facility is a local transmission facility if it is selected in a
regional transmission plan for purposes of cost allocation and the
costs are allocated to a single pricing zone in which the proposed
transmission facility is to be located, and that zone consists of more
than one transmission provider. In general, any regional 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. For example, 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. However, we
recognize in response to Duke's request that special consideration is
needed when a small transmission provider is located within the
footprint of another transmission provider. For instance, a regional
cost allocation method might allocate costs to an area consisting of
one transmission provider that has within its borders one or more
smaller utilities that largely depend on its transmission system but
nevertheless own a little transmission of their own, so that they too
are transmission providers. This situation is not necessarily ``a zone
consisting of more than one transmission provider'' as this term is
used in this order. If the cost of a new transmission facility is
allocated entirely to an area consisting of one transmission provider
that has one or more smaller transmission providers within its borders,
this might qualify as a local cost allocation, not a regional cost
allocation. However, as petitioners point out, 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, we 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.
Specific situations may be included in a compliance filing along with
the filed regional cost allocation method or methods.
425. We disagree with Western Independent Transmission Group's
assertion that the Commission failed to provide a reasoned explanation
of its decision not to require the elimination of a federal right of
first refusal for local transmission facilities. In Order No. 1000, the
Commission recognized that incumbent transmission providers may have
reliability needs or service obligations.\502\ Accordingly, Order No.
1000 does not prevent an incumbent transmission provider from meeting
its reliability needs or service obligations by choosing to build new
transmission facilities that are located solely within its retail
distribution service territory or footprint and that are not selected
in a regional transmission plan for purposes of cost allocation.\503\
Thus, we affirm the decision in Order No. 1000 not to require
elimination from Commission-jurisdictional tariffs and agreements a
federal right of first for a local transmission facility.\504\ We also
note in response to Western Independent Transmission Group that the
Commission found that issues related to the generator interconnection
process and to interconnection cost recovery were outside the scope of
Order No. 1000.\505\ Order No. 1000 did not establish any new
requirements with respect to the generator interconnection process, and
we are not persuaded to address the generator interconnection process
on rehearing.
---------------------------------------------------------------------------
\502\ Id. P 262. The Commission defined a local transmission
facility as a transmission facility located solely within a public
utility transmission provider's retail distribution service
territory or footprint that is not selected in a regional
transmission plan for purposes of cost allocation. An incumbent
transmission provider would retain the option of meeting its local
reliability needs or obligations to serve by building a transmission
facility in its retail distribution service territory or footprint.
Id. at P 63.
\503\ Id. In P 262 of Order No. 1000, the Commission used the
term ``submitted for regional cost allocation'' where we intended
``selected in a regional transmission plan for purposes of cost
allocation.'' We provide that clarification here.
\504\ Id. P 318.
\505\ Id. P 760.
---------------------------------------------------------------------------
426. In response to requests for clarification regarding what the
Commission considers to be an upgrade, we note that in Order No. 1000,
the term upgrade means an improvement to, addition to, or replacement
of a part of, an existing transmission facility. The term upgrades does
not refer to an entirely new transmission facility. The concept is that
there should not be a federally established monopoly over the
development of an entirely new transmission facility that is selected
in a regional transmission plan for purposes of cost allocation to
others. However, neither is the Commission eliminating the right of an
owner of a transmission facility to improve its own existing
transmission facility by allowing a third-party transmission developer
to, for example, propose to replace the towers or the conductors of a
transmission line owned by another entity.\506\ It is not feasible,
however, to list every type of improvement or addition, or name all the
parts of lines, towers and other equipment that may be replaced or
otherwise upgrades, and we will not do so here.
---------------------------------------------------------------------------
\506\ Id. P 319.
---------------------------------------------------------------------------
427. In response to ITC Companies, we clarify that the requirement
to eliminate a federal right of first refusal does not apply to any
upgrade, even where the upgrade requires the expansion of an existing
right-of-way. The issue is not whether the upgrade would be located in
an existing right-of-way, but whether the new transmission facility is
an upgrade to an incumbent transmission provider's own facilities.
Furthermore, the Commission reiterates that the nonincumbent
transmission developer reforms were not intended to alter an incumbent
transmission provider's use and control of its existing rights-of-way
under state law.\507\
---------------------------------------------------------------------------
\507\ Id.
---------------------------------------------------------------------------
428. We affirm the decision in Order No. 1000 to require the
elimination of a federal right of first refusal for reliability
projects. Allowing incumbent transmission providers to maintain a
federal right of first refusal, even with a limited 90-day election
period as proposed by Xcel, would discourage
[[Page 32252]]
transmission developers from proposing transmission projects that may
be a more efficient or cost-effective solution to meet regional
transmission needs, resulting in rates for jurisdictional transmission
services that are unjust and unreasonable or unduly discriminatory or
preferential. The fact that a particular transmission facility is
intended to meet a reliability need does not change our responsibility
to eliminate practices that result in unjust and unreasonable or unduly
discriminatory or preferential rates. Furthermore, Order No. 1000
includes several reforms that ensure that incumbent transmission
providers will be able to satisfy their reliability needs and service
obligations, even when they are relying on a nonincumbent transmission
developer's project to meet a reliability need. Specifically, Order No.
1000 includes a reevaluation requirement that requires public utility
transmission providers in a region to have procedures in place to
identify when delays in the development of a transmission facility
selected in a regional transmission plan for purposes of cost
allocation require evaluation of alternative solutions to ensure that
an incumbent transmission provider can meets its reliability needs or
service obligations.\508\ Moreover, we note again that Order No. 1000
continues to permit an incumbent transmission provider to meet its
reliability needs or service obligations by choosing to build new
transmission facilities that are located solely within its retail
distribution service territory or footprint and that are not selected
in a regional transmission plan for purposes of cost allocation.\509\
Accordingly, we disagree with petitioners that argue that a federal
right of first refusal for reliability project is necessary for
incumbent transmission providers to meet reliability needs or service
obligations.
---------------------------------------------------------------------------
\508\ Id. P 329.
\509\ Id. P 262.
---------------------------------------------------------------------------
429. In response to LS Power's concerns regarding the definition of
a local transmission facility, we clarify that a local transmission
facility is one that is located within the geographical boundaries of a
public utility transmission provider's retail distribution service
territory, if it has one, otherwise the area is defined by the public
utility transmission provider's footprint. Thus, if the public utility
transmission provider has a retail distribution service territory and/
or footprint, then only a transmission facility that it decides to
build within that retail distribution service territory or footprint,
and that is not selected in a regional transmission plan for purposes
of cost allocation, may be considered a local transmission facility. In
the case of an RTO or ISO whose footprint covers the entire region, we
clarify that local transmission facilities are defined by reference to
the retail distribution service territories or footprints of its
underlying transmission owing members. We also clarify that the extent
of a public utility transmission provider's retail distribution service
territory or footprint is not to be measured as of the effective date
of Order No. 1000, but is the retail distribution service territory or
footprint in existence during the regional transmission planning cycle.
We decline to provide any of the further clarifications regarding the
definition of a local transmission facility as requested by LS Power
and will address such matters during the compliance process based on a
more complete record.
430. Finally, in response to petitioners' concerns over which
facilities are selected in a regional transmission plan for purposes of
cost allocation, and for which a federal right of first refusal must
therefore be eliminated, we clarify 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 this
order.
3. Framework To Evaluate Transmission Projects Submitted for Selection
in the Regional Plan for Purposes of Cost Allocation
431. In Order No. 1000, the Commission required each public utility
transmission provider to revise its OATT to describe the features of an
acceptable framework for project identification and selection. The
Commission required that this framework include: (1) Qualification
criteria to submit a transmission project for selection in the regional
transmission plan for purposes of cost allocation; (2) specification of
the information that must be submitted by a prospective transmission
developer in support of the transmission project it proposes in the
regional transmission planning process and the date by which such
information must be submitted to be considered in a given transmission
planning cycle; (3) a description of a transparent and not unduly
discriminatory process for evaluating whether to select a proposed
transmission facility in the regional transmission plan for purposes of
cost allocation; and (4) provisions allowing a nonincumbent
transmission developer to have the same eligibility as an incumbent
transmission provider to use a regional cost allocation method or
methods for any sponsored transmission facility selected in the
regional transmission plan for purposes of cost allocation. Last, the
Commission declined to require public utility transmission providers to
revise their OATTs to provide a transmission developer a right to
construct and own a transmission facility and also declined to allow a
transmission developer to maintain for a defined period of time its
right to build and own a transmission project that it proposed but that
is not selected.\510\
---------------------------------------------------------------------------
\510\ Id. PP 323-40.
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a. Qualification Criteria To Submit a Transmission Project for
Selection in the Regional Transmission Plan for Purposes of Cost
Allocation
i. Final Rule
432. The Commission required each public utility transmission
provider to revise its OATT to demonstrate that the regional
transmission planning process in which it participates has established
qualification criteria that are not unduly discriminatory or
preferential for determining an entity's eligibility to propose a
transmission project for selection in the regional transmission plan
for purposes of cost allocation, whether that entity is an incumbent
transmission provider or a nonincumbent transmission developer.\511\
The Commission explained that the criteria must provide each potential
transmission developer the opportunity to demonstrate that it has the
necessary financial resources and technical expertise to develop,
construct, own, operate, and maintain transmission facilities.\512\ The
Commission found that one-size-fits-all qualification criteria would
not be appropriate, and that it is important for each transmission
planning region to have the flexibility to formulate qualification
criteria that best fits its transmission planning processes and
addresses the particular needs of the region, so long as the criteria
are fair and not unreasonably stringent when applied to either the
incumbent transmission provider or a nonincumbent transmission
developer.\513\
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\511\ Id. P 323.
\512\ Id.
\513\ Id. P 324.
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[[Page 32253]]
ii. Requests for Rehearing and Clarification
433. Several petitioners seek rehearing of the Commission's
requirement that the regional planning process develop qualification
criteria.\514\ They assert that Order No. 1000 creates an unreasonable
disparity between who establishes the criteria for a nonincumbent to be
deemed qualified to propose and construct a transmission project and
who bears the risk if such nonincumbent does not perform.\515\ They
state that each incumbent transmission provider remains responsible for
meeting its reliability and system security obligations in the event
that the nonincumbent fails to perform, but must rely on qualification
criteria developed by the region planning process. They state that this
disparity is unreasonable, arbitrary and capricious, and should be
revised to be more consistent with the model provided for in Order No.
890-A, which allows the transmission provider to establish reasonable
credit criteria.\516\ They also believe this would allow each incumbent
transmission provider that bears the greatest risk of non-performance
of a nonincumbent to better manage such risk.\517\
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\514\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Southern Companies.
\515\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Southern Companies.
\516\ Ad Hoc Coalition of Southeastern Utilities at 62 (citing
Order No. 890-A, Attachment L (Creditworthiness Procedures) to Pro
Forma OATT; Order No. 890 at P 1659); Southern Companies at 63
(citing Preventing Undue Discrimination and Preference in
Transmission Serv., Order No. 890-A, 121 FERC ] 61,297, Attachment L
(2007)).
\517\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Southern Companies.
---------------------------------------------------------------------------
434. Other petitioners request that the Commission standardize the
qualification criteria or otherwise clarify that certain criteria are
impermissible.\518\ NextEra argues that there should be a standardized
qualification requirement rather than the flexible approach adopted in
Order No. 1000 because it believes that such flexibility could permit
incumbents to devise qualification criteria that create barriers to
entry. NextEra states that, unlike other areas of Order No. 1000 that
endorse flexibility, there is no reason to believe that financial and
technical qualification criteria for new transmission entrants should
vary by region. NextEra points to the Commission's actions in
standardizing generator interconnection procedures under Order No. 2003
and credit reform rules under Order No. 741. NextEra also suggests that
the Commission look to the qualification criteria established by ERCOT
and CAISO as examples. Alternatively, NextEra states that the
Commission should initiate a negotiated rulemaking to develop consensus
criteria, which it states is the course the Commission followed in
developing Order No. 2003.
---------------------------------------------------------------------------
\518\ See, e.g., NextEra; LS Power; and New York Transmission
Owners.
---------------------------------------------------------------------------
435. LS Power requests that the Commission clarify that the
qualification criteria for entities that want to propose a project in
the regional transmission planning process are limited to financial and
technical matters. It also asks that the qualification criteria not
operate as a barrier to entry and should not include a qualification
that a new entrant be an existing public utility under state law or
have upfront siting authority. It contends that a new entrant would not
be able to achieve state public utility status at the assignment stage
because it is most often granted after the assignment of the
transmission project. LS Power similarly argues that the selection
criteria used to evaluate a project also should not require that a
project sponsor be an existing public utility under state law or have
upfront siting authority before it can be assigned a project. LS Power
contends that such selection criteria would also act as a barrier to
entry in that states most often grant public utility status and eminent
domain authority after the assignment of the transmission project.
436. APPA requests that the Commission require that the minimum
participation criteria developed by incumbent transmission developers/
providers be fair and not unreasonably stringent as applied to public
power utilities.
437. Transmission Access Policy Study Group seeks clarification
that the qualification criteria facilitate transmission dependent
utility joint ownership, and states that qualification criteria
designed for proposals submitted by a single entity could
unintentionally and needlessly foreclose beneficial project
participation by multiple joint owners.
438. New York Transmission Owners request that transmission
planning regions be permitted to require NERC registration for
nonincumbent transmission developers as a precondition to being
assigned a reliability project.
iii. Commission Determination
439. We affirm Order No. 1000's requirement that the public utility
transmission providers in each transmission planning region must
establish, in consultation with stakeholders, appropriate qualification
criteria for determining an entity's eligibility to propose a
transmission project for selection in the regional transmission plan
for purposes of cost allocation. As required under Order No. 1000,
these qualification criteria must not be unduly discriminatory or
preferential and must provide each potential transmission developer the
opportunity to demonstrate that it has the necessary financial
resources and technical expertise to develop, construct, own, operate,
and maintain transmission facilities.\519\ We disagree with petitioners
that this approach creates an unreasonable disparity between who
establishes the criteria for a nonincumbent transmission developer to
be deemed qualified to propose and construct a transmission project and
who bears the risk if such nonincumbent transmission developer does not
perform. Order No. 1000 makes clear that it is public utility
transmission providers themselves, in consultation with stakeholders,
that are responsible for complying with Order No. 1000 and that must
develop the qualification criteria for review by the Commission on
compliance.\520\
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\519\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 323.
\520\ We reiterate that ``the qualification criteria required
[in Order No. 1000] should not be applied to an entity proposing a
transmission project for consideration in the regional transmission
planning process if that entity does not intend to develop the
proposed transmission project. The Order No. 890 transmission
planning requirements allow any stakeholder to request that the
transmission provider perform an economic planning study or
otherwise suggest consideration of a particular transmission
solution in the regional transmission planning process.'' Id. P 324
n.304.
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440. The Commission declines to adopt standardized qualification
criteria, as urged by NextEra. While the Commission's acknowledges
NextEra's concern that qualification criteria could act as a barrier to
entry, the Commission believes that there may be legitimate differences
between regions that may justify differences in the qualification
criteria. Each region is faced with its own set of challenges in
building new transmission facilities, and regions should be permitted
to account for those differences in their qualification criteria. For
this same reason, the Commission will not adopt certain minimum
qualification criteria. Regarding LS Power's petition that the
qualification criteria be limited to financial and technical matters,
we point out that Order No. 1000 states that ``[t]he qualification
criteria must provide each potential transmission developer the
opportunity to demonstrate that it has the necessary financial
resources and technical expertise to develop,
[[Page 32254]]
construct, own, operate and maintain transmission facilities,'' but
also permits each transmission planning region flexibility to formulate
qualification criteria that best fit its transmission planning
processes and addresses the particular needs of the region.\521\
---------------------------------------------------------------------------
\521\ Id. PP 323-24.
---------------------------------------------------------------------------
441. We clarify in response to LS Power that it would be an
impermissible barrier to entry to require, as part of the qualification
criteria, that a transmission developer demonstrate that it either has,
or can obtain, state approvals necessary to operate in a state,
including state public utility status and the right to eminent domain,
to be eligible to propose a transmission facility. As the Commission
emphasized in Order No. 1000, and reiterates here, the qualification
criteria must be fair and not unreasonably stringent when applied to an
incumbent transmission provider and a nonincumbent transmission
developer.\522\ The Commission will review on compliance whether any
proposed qualification criterion is unreasonably stringent when applied
to nonincumbent transmission developers such that the criteria act as
an unreasonable barrier to entry.\523\
---------------------------------------------------------------------------
\522\ Id. P 324.
\523\ Importantly, Order No. 1000 did not provide transmission
developers with a right to construct; rather, it required ``that a
nonincumbent transmission developer must have the same eligibility
as an incumbent transmission developer to use a regional cost
allocation method or methods for any sponsored transmission facility
selected in the regional transmission plan for purposes of cost
allocation.'' See id. P 332.
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442. If a transmission facility is selected in the regional
transmission plan for purposes of cost allocation, the Commission
clarifies that the transmission developer of that transmission facility
must submit a development schedule that indicates the required steps,
such as the granting of state approvals, necessary to develop and
construct the transmission facility such that it meets the transmission
needs of the region. As part of the ongoing monitoring of the progress
of the transmission project once it is selected, the public utility
transmission providers in a transmission planning region must establish
a date by which state approvals to construct must have been achieved
that is tied to when construction must begin to timely meet the need
that the project is selected to address. If such critical steps have
not been achieved by that date, then the public utility transmission
providers in a transmission planning region may remove the transmission
project from the selected category and proceed with reevaluating the
regional transmission plan to seek an alternative solution.
443. We believe that there are a number of benefits to this
approach. First, it ensures that transmission developers that have the
technical and financial capability to build a transmission facility,
and meet other nondiscriminatory and non-preferential criteria, are
eligible to propose a transmission facility for evaluation and
selection, thereby increasing the universe of potential facilities
evaluated and selected to meet a region's transmission needs. Second,
it gives a nonincumbent transmission developer the opportunity to
propose a transmission facility while it seeks to obtain necessary
state approvals or otherwise seeks to comply with applicable state law
or regulation. Third, it provides the public utility transmission
providers in a transmission planning region with the ability to monitor
the development of a transmission facility selected in the regional
transmission plan for purposes of cost allocation, as well as the
ability to remove that new transmission facility if its developer is
unable to meet an established date by which the critical development
step of obtaining necessary state approvals must be achieved.
444. We also deny New York Transmission Owners' request that the
public utility transmission providers in a transmission planning region
be permitted to require a transmission developer to demonstrate that it
has registered with NERC as a precondition to being assigned a
reliability project. As the Commission explained in Order No. 1000, all
entities that are users, owners or operators of the electric bulk power
system must register with NERC for performance of applicable
reliability functions.\524\ The procedures for registering as a
Functional Entity are set by NERC and approved-by the Commission under
section 215,\525\ and it is not appropriate for the Commission to amend
or interpret those procedures here under a section 206 action by
requiring all public utility transmission providers to revise their
tariffs to provide that a potential transmission developer must
register with NERC if not otherwise required under the NERC procedures,
merely to be eligible to propose a transmission project for selection
in the regional transmission plan for purposes of cost allocation.
---------------------------------------------------------------------------
\524\ Id. P 342.
\525\ NERC, Rules of Procedures (effective March 15, 2012),
available at http://www.nerc.com/files/NERC_ROP_Effective_20120315.pdf.
---------------------------------------------------------------------------
b. Evaluation of Proposals for Selection in the Regional Transmission
Plan for Purposes of Cost Allocation
i. Final Rule
445. The Commission required 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 the regional transmission plan for purposes of
cost allocation.\526\ The Commission explained that this process must
comply with the Order No. 890 transmission planning principles,
ensuring transparency, and the opportunity for stakeholder
coordination. The Commission further explained that the evaluation
process must culminate in a determination that is sufficiently detailed
for stakeholders to understand why a particular transmission project
was selected or not selected in the regional transmission plan for
purposes of cost allocation.\527\ Finally, the Commission declined to
require public utility transmission providers to revise their OATTs to
provide a right to construct and own a transmission facility and also
declined to allow a transmission developer to maintain for a defined
period of time its right to build and own a transmission project that
it proposed but that was not selected.\528\
---------------------------------------------------------------------------
\526\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 328.
\527\ Id.
\528\ Id. P 338.
---------------------------------------------------------------------------
ii. Requests for Rehearing and Clarification
446. Western Independent Transmission Group seeks rehearing of the
Commission's rejection of its proposal to require the use of an
independent third party observer to oversee evaluation and selection of
competing transmission projects to ensure that the process is being
managed fairly and efficiently.
447. Illinois Commerce Commission argues that it is necessary for
the Commission to provide more specificity regarding the practical
means by which transmission providers can facilitate competition
between alternative proposals. It suggests that the transmission
provider identify the planning needs to be met and then solicit
developers to submit alternative plans to address those needs. Illinois
Commerce Commission explains that this formalized process would provide
a non-discriminatory and objective method for the transmission provider
to
[[Page 32255]]
evaluate alternative proposals, and argues that the Commission erred in
not requiring such a process.
448. Similarly, FirstEnergy Service Company seeks clarification
that regional transmission planning processes need only consider
proposals that respond to identified needs, such that a ``needs first''
approach is acceptable. In support, FirstEnergy Service Company argues
that a planning model that requires the regional planning process to
analyze every individual proposal would render the process less
manageable, timely, and effective. FirstEnergy Service Company also
argues that, through Order No. 890, the Commission already has put in
place the mechanisms necessary to encourage innovative transmission
proposals.
449. LS Power requests that the Commission affirmatively clarify on
rehearing that, if a region uses a sponsorship model for the assignment
of projects, the regions must treat an application for a project by a
nonincumbent transmission owner no differently from any other
applicant, and that sponsors that meet nondiscriminatory sponsorship
criteria are to be assigned construction and ownership of the projects
they sponsor unless the regional planning entity adequately justifies
assignment of the project to another entity, as PJM was required to do
in the Primary Power case.\529\ It states that without this explicit
statement, some will attempt to assign projects to non-sponsor
incumbent transmission owners on the basis of an inaccurate reading of
paragraph 338, where the Commission declined to adopt any right to
construct or ongoing sponsorship rights.
---------------------------------------------------------------------------
\529\ LS Power at 6 (Primary Power, LLC, 131 FERC ] 61,015, at P
65 (2010)).
---------------------------------------------------------------------------
450. LS Power also requests that the Commission clarify that in a
region using a sponsorship model rather than a competitive bidding
model, the process established by each public utility transmission
provider must include a specific mechanism to select, in a
nondiscriminatory manner, among competing qualified sponsors of
identical projects, or, as a backstop if no mechanism is agreed upon,
to assign such projects equally among qualified entities that have
sponsored identical projects. It explains that to the extent that only
one of the sponsors has sponsored the same project in an immediately
prior planning cycle, that the entity should have preference over those
entities newly sponsoring the project. LS Power further suggests that
the Commission should include a provision for ongoing sponsorship
rights, with some recognition or benefit to an entity for continuing to
advocate viable projects, at least between the continuing sponsor and
new sponsors of the same project. Additionally, LS Power states that
another mechanism to select among multiple sponsors of identical
projects is to select the entity that is willing to guarantee the
lowest net present value of its annual revenue requirement.
451. In addition, LS Power requests that the Commission clarify
that to meet the ``not unduly discriminatory process'' requirement, the
selection criteria must meet certain minimum standards. It states that
the Commission should clarify that when cost estimates are part of
selection criteria, costs must be scrutinized in an equal manner
whether the project is sponsored by an incumbent or independent.
iii. Commission Determination
452. The Commission affirms the 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.\530\ We
also affirm the Commission's decision not to require public utility
transmission providers to use an independent third party observer to
oversee the evaluation and selection of competing transmission
projects. In Order No. 1000, the Commission encouraged public utility
transmission providers to consider ways to minimize disputes, such as
through additional transparency mechanisms.\531\ However, the
Commission did not mandate any particular approach, and is not
persuaded now that an independent third party observer is necessary or
appropriate in all regions. Moreover, the Commission noted that the
requirements of the dispute resolution principle of Order No. 890 apply
to the regional transmission planning process.\532\ Thus, if a dispute
cannot be resolved by public utility transmission providers in the
regional transmission planning process, entities may take advantage of
that transmission planning region's dispute resolution provision.
Additionally, as noted in Order No. 1000, public utility transmission
providers in consultation with other stakeholders in a region may, if
they choose, propose to use an independent third-party observer and we
will review any such proposal on compliance.\533\
---------------------------------------------------------------------------
\530\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 328.
\531\ Id. P 330.
\532\ Id. P 330 n.306.
\533\ Order No. 1000, FERC Stats. & Regs. ] 31,323.
---------------------------------------------------------------------------
453. While Order No. 1000 permits the public utility transmission
providers in a region to adopt a ``needs first'' approach to
transmission planning such as that advocated by the Illinois Commerce
Commission and FirstEnergy Service Company, the Commission declined to
adopt a one-size-fits-all approach to transmission planning. The
Commission believes that there are many different approaches to
transmission planning and requires only that the transmission planning
process adopted by a transmission planning region satisfy the
transmission planning principles discussed in Order No. 1000 and this
order. Thus, we decline 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.
454. The Commission clarifies that the public utility transmission
providers in a transmission planning region must use the same process
to evaluate a new transmission facility proposed by a nonincumbent
transmission developer as it does for a transmission facility proposed
by an incumbent transmission developer. In Order No. 1000, the
Commission required each public utility transmission provider to adopt
a transparent and not unduly discriminatory evaluation process that
complies with the Order No. 890 transmission planning principles.\534\
However, this requirement does not preclude public utility transmission
providers in regional transmission planning processes from taking into
consideration the particular strengths of either an incumbent
transmission provider or a nonincumbent transmission developer during
its evaluation.\535\
---------------------------------------------------------------------------
\534\ Id. P 328.
\535\ See id. P 260 (``An incumbent public utility transmission
provider is free to highlight its strengths to support transmission
project(s) in the regional transmission plan, or in bids to
undertake transmission projects in regions that choose to use
solicitation processes.'').
---------------------------------------------------------------------------
455. The Commission denies LS Power's other requests for rehearing
regarding the selection of a transmission developer. The Commission
declined to address the selection of a transmission developer in Order
No. 1000. Aside from requiring the public utility transmission
providers in a region to establish criteria to assess a transmission
developer's qualifications to have its proposed transmission project
considered for selection in a
[[Page 32256]]
regional transmission plan for purposes of cost allocation, Order No.
1000 also 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. We decline to set certain minimum standards for the
criteria used to select a transmission facility in a regional
transmission plan for purposes of cost allocation other than to require
that these selection criteria be transparent and not unduly
discriminatory. We also find that this purpose is met adequately by the
transmission planning principles of Order No. 890. We also anticipate
that selection criteria will vary from transmission planning region to
transmission planning region in accordance with each transmission
planning region's needs, just as other aspects of regional transmission
planning processes will vary, and LS Power has not persuaded us that
such flexibility is inappropriate. However, we clarify that when cost
estimates are part of the selection criteria, the regional transmission
planning process must scrutinize costs in the same manner whether the
transmission project is sponsored by an incumbent or nonincumbent
transmission developer.
456. If a transmission project is selected in a regional
transmission plan for purposes of cost allocation, 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.\536\ We are not persuaded
to change this approach on rehearing. Further, we reiterate that we do
not require public utility transmission providers in a region to adopt
a provision for ongoing sponsorship rights, for the reasons set out 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.\537\
We are not persuaded to reverse our decisions on the selection of
transmission developers. While we acknowledge LS Power's concerns, we
do not believe they warrant any revision of the selection of
transmission developers at this time given the diversity of methods for
selecting transmission developers used around the nation.
---------------------------------------------------------------------------
\536\ Id. P 339.
\537\ Id.
---------------------------------------------------------------------------
c. Reevaluation of Regional Transmission Plans When There Is a Project
Delay and Reliability Compliance Obligations of Transmission Developers
i. Final Rule
457. In Order No. 1000, the Commission required each public utility
transmission provider to amend its OATT to describe the circumstances
and procedures under which public utility transmission providers in the
regional transmission planning process 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.\538\
---------------------------------------------------------------------------
\538\ Id. P 329.
---------------------------------------------------------------------------
458. The Commission also explained that if a violation of a NERC
reliability standard by an incumbent would result from a nonincumbent
transmission developer's decision to abandon a transmission facility
meant to address such a violation, the incumbent transmission provider
does not have the obligation to construct the nonincumbent's
project.\539\ Rather, the incumbent transmission provider must identify
the specific NERC reliability standard(s) that would be violated and
submit a mitigation plan to address the violation.\540\ The Commission
explained that if the incumbent public utility transmission provider
follows the NERC-approved mitigation plan, the Commission will not
subject it to enforcement action for the specific NERC reliability
standard violation(s) caused by a nonincumbent transmission developer's
decision to abandon a transmission facility.\541\
---------------------------------------------------------------------------
\539\ Id. P 344.
\540\ Id.
\541\ Id.
---------------------------------------------------------------------------
459. The Commission also noted that, when a nonincumbent
transmission developer becomes subject to the requirements of FPA
section 215 and the regulations thereunder, it will be required to
comply with all applicable reliability obligations, including
registering with NERC for performance of applicable reliability
functions.\542\ The Commission stated that if there are concerns about
when compliance with NERC registration and reliability standards would
be triggered, the appropriate forum to raise these questions and
request clarification is the NERC process.\543\
---------------------------------------------------------------------------
\542\ Id. P 342.
\543\ Id. P 343.
---------------------------------------------------------------------------
ii. Requests for Rehearing and Clarification
460. Some petitioners question whether the reevaluation requirement
set forth in Order No. 1000 are sufficient to protect incumbent
transmission providers from the repercussions related to a
nonincumbent's failure to build a project in time.\544\ For instance,
these petitioners argue that the Commission failed to protect incumbent
transmission providers from the increased risk of violations of state
reliability or resource adequacy requirements, and other state service
obligations.\545\ MISO Transmission Owners Group 2 also adds that the
incumbent utility could face civil liability, state regulatory
sanctions, and financial harm resulting from damage to its own
facilities or the facilities of another entity caused by the action of
the nonincumbent.
---------------------------------------------------------------------------
\544\ See, e.g., Southern Companies; Edison Electric Institute;
MISO Transmission Owners Group 2; and Xcel.
\545\ See, e.g., Edison Electric Institute; and MISO
Transmission Owners Group 2.
---------------------------------------------------------------------------
461. Some commenters argue that incumbent developers should not be
burdened with monitoring the status of a nonincumbent developer's
progress. Specifically, if the reevaluation requirement would obligate
incumbents to discover or address nonincumbent delays prior to being
notified by the nonincumbent, Southern Companies request rehearing of
this requirement in Order No. 1000.\546\ Southern Companies also
request rehearing of the reevaluation requirement to the extent it
could inhibit, prevent or slow an incumbent's decision to address a
delay or the implementation of its corrective plan. Similarly, Southern
California Edison requests that the Commission require regional
transmission planning entities to develop protocols for how such
transmission planning entities will: (1) Be kept apprised by
nonincumbent developers of the status of their projects; and (2) notify
the applicable incumbent transmission owner that it needs to develop a
mitigation plan because a project has been delayed or abandoned by a
nonincumbent developer. In addition, Southern Companies contend that
each incumbent transmission provider and planning authority should be
permitted
[[Page 32257]]
to reevaluate its own local transmission plan to determine whether a
nonincumbent's delay in constructing a regional facility will adversely
impact reliability on the incumbent's system. In addition, Southern
Companies argue that because the reevaluation requirement does not
protect against the need to implement operational adjustments, Order
No. 1000 fails to protect against service reliability problems and
fails to weigh the adverse impacts against the benefits that the
Commission foresees.
---------------------------------------------------------------------------
\546\ Southern Companies at 78 (citing McElroy Electronics Corp.
v. FCC, 990 F.2d 1351, 1358 (D.C. Cir. 1993)).
---------------------------------------------------------------------------
462. Ad Hoc Coalition of Southeastern Utilities and Large Public
Power Council also assert that there is no substantial evidence for
concluding, as the Commission does in paragraph 263 of Order No. 1000,
that the potential costs associated with a delayed or abandoned
nonincumbent transmission facility are remediable by a reevaluation of
the regional plan. For example, Large Public Power Council explains
that by the time construction delays place a system at risk, the damage
will have been done, since such delays will postdate the planning that
contemplated the facilities at issue, often by several years. As such,
it maintains that even if the incumbent utility can step in with
sufficient lead-time so that reliability is not threatened, and the
cost of this activity is recoverable, there is little that can be done
to save ratepayers from the associated costs, and there is no basis to
conclude that nonincumbent participation in the transmission
development process will therefore be worth it.
463. Several petitioners seek rehearing and clarification of the
Commission's decision to allow incumbent transmission providers to
implement a NERC mitigation plan to avoid an enforcement action if a
nonincumbent transmission developer abandons a project needed to meet a
reliability need. For example, Xcel asserts that Order No. 1000's
discussion of a NERC mitigation plan may involve interrupting load
under certain conditions, or implementing rolling outages. Xcel argues
that this degradation of service to end use customers is contrary to
the fundamental purposes of FPA section 215 and would also result in a
loss of revenues to the utility.
464. Transmission Dependent Utility Systems argue that Order No.
1000 sheds no light on whether its mitigation plan solution is
realistic or available and does not address who will be responsible for
maintaining power if neither the incumbent nor the nonincumbent
transmission provider can be held accountable for completion or
maintenance of reliability-driven projects. Similarly, PSEG Companies
argue that the problem of abandonment by a nonincumbent of a project
needed for reliability cannot be fixed by reliability standards or by
mitigation plans submitted in ``compliance'' with those standards. They
state that the Commission failed to recognize that NERC reliability
standards will not be applicable to a nonincumbent developer unless and
until the project is constructed and in-service.
465. Petitioners point out possible difficulties that may arise
because similar terms have distinct meanings in a public utility
transmission provider's OATT under FPA 205 and the reliability
standards under FPA 215. Several petitioners argue that it is not
always a public utility transmission provider that is responsible for
conducting a reevaluation or developing a mitigation plan.\547\ For
instance, Southern Companies argue that public utility transmission
providers do not conduct transmission planning or evaluate or
reevaluate transmission plans. Instead, Southern Companies argue that
planning authorities and transmission planners are the appropriate
entities to determine the impacts of a delay on local plans and are
responsible for meeting reliability and service obligations, including
the state-mandated duty to serve native load. Southern Companies argue
that the Commission cannot remove or dilute that responsibility by
delegating it to another entity without preempting state law. Southern
Companies state that if Order No. 1000 does not intend the term
``public utility transmission provider'' to mean Transmission Service
Provider under the NERC Functional Model, the Commission must grant
rehearing to determine what category of Registered Entity is meant, or
extend the commencement of the 12-month compliance window until NERC
has determined which category of Registered Entity is appropriate to
conduct the activities required by Order No. 1000.\548\ Furthermore,
Edison Electric Institute seeks clarification that an incumbent
transmission provider need not have a retail distribution service
territory and need not construct the new facilities entirely within its
retail distribution service territory to qualify for protection from an
enforcement action as described in paragraph 344 of Order No. 1000.
---------------------------------------------------------------------------
\547\ See, e.g., PSEG Companies; and Southern Companies.
\548\ We note that the capitalized terms refer to specific terms
used in the NERC Reliability Standards.
---------------------------------------------------------------------------
466. In addition, PSEG Companies argue that using the term
``transmission provider'' creates confusion because, under the NERC
Functional Model, the term could apply to a number of different
functions, and these different functions are very different even if in
ISO/RTO regions the ``transmission provider'' is the ISO/RTO. PSEG
Companies argue that the Commission erred by seeking to impose the
responsibility to develop a ``mitigation plan'' onto incumbent
transmission owners, and that this requirement demonstrates that the
Commission misunderstands the NERC process. Thus, according to PSEG
Companies, the process for addressing nonincumbents' abandonment of
facilities would not work as envisioned, at least in the ISO/RTO
context where the transmission owner is not responsible for planning
the system and would not be responsible for filing a mitigation plan in
the event of abandonment.
467. Other petitioners request clarification regarding the scope of
the waiver. Edison Electric Institute recommends that the Commission
use NERC terminology to clarify the scope of the waiver. Other
petitioners argue that if the waiver applies only to the incumbent
transmission provider as defined in Order No. 1000, the application is
too narrow.\549\ In addition to the incumbent transmission provider,
Edison Electric Institute argues that the protection from an
enforcement action should extend to other entities that might be found
in violation of a reliability standard, such as balancing authorities
and reliability coordinators. APPA agrees and adds that all of the
transmission providers will be adversely affected to at least some
extent due to the interconnected nature of the transmission network.
Transmission Dependent Utility Systems add that third parties with NERC
reliability obligations for certain transmission facilities, such as
municipal utilities and rural electric cooperatives, also should be
held harmless from penalties and NERC enforcement actions if a
nonincumbent transmission developer abandons or fails to maintain a
project needed to address reliability concerns. For example, even
though Southern California Edison considers CAISO to be the
transmission provider, Southern California Edison asserts that it
develops and implements NERC mitigation plans as the NERC registered
[[Page 32258]]
transmission owner and therefore should be entitled to protection.
---------------------------------------------------------------------------
\549\ See, e.g., Edison Electric Institute; Southern California
Edison; and APPA.
---------------------------------------------------------------------------
468. Southern Companies also request rehearing of Order No. 1000's
failure to explain its departure from existing policy and regulations
regarding mitigation plans. Southern Companies argue that requiring an
incumbent to submit a mitigation plan for a nonincumbent's abandonment
of necessary facilities would bestow upon the incumbent the impossible
task of ensuring that another entity will not make poor business
decisions, go bankrupt, or otherwise abandon or cancel its projects.
Furthermore, Southern Companies state that Order No. 1000 indicates the
incumbent may need to construct redundant and duplicate facilities to
guard against the potential of nonincumbent delay or abandonment of its
project. In addition, Southern Companies request rehearing to the
extent incumbents are required to propose a corrective action for
review by the regional process because such a requirement would impair
service reliability.\550\ Southern Companies also request clarification
that the costs of the delayed regional facility will not be allocated
to an incumbent that constructs a local transmission solution to meet
its reliability or service needs in the face of delay.
---------------------------------------------------------------------------
\550\ Southern Companies at 81-82 (citing Motor Vehicle Mfrs.
Assoc. of the United States, Inc. v. State Farm Mutual Auto. Ins.
Co., 463 U.S. 29, 43 (1983)).
---------------------------------------------------------------------------
469. Petitioners also argue that the protection from an enforcement
action should be applicable to any project that an incumbent relies on
to satisfy its reliability obligations, including reliability, public
policy or economic-based projects.\551\ Southern California Edison
points out that a project intended to address a NERC violation or other
reliability concerns may be dependent on another transmission project
being completed first, including a public policy or economic project.
Ameren argues that such other projects, which may have received
regional cost allocation, will almost certainly have some measure of
reliability effect because the grid is interconnected and that the
failure of any such project could cause a blackout.
---------------------------------------------------------------------------
\551\ See, e.g., Southern California Edison; Xcel; Ameren; and
Edison Electric Institute.
---------------------------------------------------------------------------
470. Some petitioners seek clarification that the protections found
in paragraph 344 will prevent the Commission, NERC, or a Regional
Entity from considering a violation that is covered by this protection,
or a mitigation plan developed to address such a violation, as a prior
violation when determining the penalty for a new violation.\552\
Moreover, Edison Electric Institute seeks clarification that the
protections described in paragraph 344 will apply to any Reliability
Standard violation, including an operationally-focused violation,
resulting from abandonment of a project by a nonincumbent transmission
developer. Edison Electric Institute asserts that it is unfair to
provide protection only for violations specifically envisioned at the
time the project was conceived. Finally, Edison Electric Institute
seeks clarification that the safe harbor provision will prevent the
Commission, NERC, or a Regional Entity from considering a violation
that is covered by this safe harbor protection or a mitigation plan
developed to address such a violation as a prior violation when
determining the penalty for a new violation.
---------------------------------------------------------------------------
\552\ See, e.g., Edison Electric Institute; and Southern
California Edison.
---------------------------------------------------------------------------
471. Southern California Edison requests that the Commission
clarify that an incumbent transmission owner will not be subject to an
enforcement action or any other sanction or penalty if it cannot follow
or implement an approved mitigation plan for reasons beyond its
control. It states that after Order No. 1000, a transmission owner may
be asked to develop a mitigation plan without much of the key
information, which means an incumbent transmission owner may not be
able to develop an infallible mitigation plan and should not be
penalized if implementation of its plan is delayed or if the plan needs
to be revised to reflect new information that becomes known to the
incumbent when the mitigation efforts are underway.
472. In addition, Southern California Edison requests that the
Commission clarify that penalties, sanctions, or enforcement actions
also will not be levied against an incumbent transmission owner for
reliability problems that arise from the actions of a nonincumbent
transmission developer in connection with delays of a transmission
facility, or the operation or maintenance thereof.
473. Southern California Edison also argues that the Commission
should clarify that, as long as the incumbent transmission owner
submits its mitigation plan to an appropriate regional entity, the
transmission owner should not face any enforcement actions, penalties
or sanctions while the mitigation plan is pending approval. Southern
California Edison states that it does not submit mitigation plans
directly to NERC, but instead initially submits its plan for approval
to the Regional Entity. Therefore, Southern California Edison states
that there will be some inevitable delay between the time that a
transmission owner submits a mitigation plan and the time that the plan
is approved by NERC, and argues that it should not be penalized for
such inevitable delay.
474. Some petitioners argue that the Commission's reevaluation and
enforcement provisions in Order No. 1000 are inconsistent with section
215 of the FPA, and fail to adequately protect incumbents.\553\ For
example, Edison Electric Institute asserts that if an incumbent
transmission provider violates state resource adequacy or reliability
requirements, it may be subject to significant monetary penalties and
other sanctions, which the Commission's grant of protection from a
section 215 enforcement action has no effect on and cannot preempt.
Edison Electric Institute argues that the Commission failed to discuss
these implications and has thus engaged in arbitrary and capricious
decision-making and should grant rehearing to remove the right of first
refusal for reliability projects.
---------------------------------------------------------------------------
\553\ See, e.g., Xcel; Southern Companies; and MISO Transmission
Owners Group 2.
---------------------------------------------------------------------------
475. Xcel argues that Order No. 1000 ignores the substantial record
evidence that the policies adopted are inconsistent with the objectives
of section 215 of the FPA and the Commission's initiatives to improve
electric system reliability through mandatory standards. Xcel contends
that forcing utility transmission providers to rely on a third party to
fulfill section 215 obligations does not constitute reasoned decision-
making. Southern Companies add that Order No. 1000's nonincumbent
requirements pose threats to reliability and economic service by
forcing disintegration of the transmission network. MISO Transmission
Owners Group 2 argues that nothing in EPAct 2005 authorizes the
Commission to provide blanket waivers of critical reliability standards
for the purposes of achieving some policy preference unrelated to the
enforcement of mandatory reliability standards.
476. Southern Companies also argue that the Commission
impermissibly uses section 206 to impose reliability requirements
instead of using its section 215 authority. Southern Companies argue
that this action violates the Whole Act Rule by making section 215's
goal of protecting reliability subservient to section 206.\554\
Accordingly, Southern
[[Page 32259]]
Companies assert that the Commission should have gone through the
Commission-approved NERC standards and enforcement processes
established pursuant to section 215 of the FPA, the Commission's
regulations, and Commission precedent, rather than unilaterally
developing these reliability-related reevaluation and enforcement
protections and imposing their requirements onto users, owners, and
operators of the bulk-power system. Southern Companies argue the
enforcement action waiver is inconsistent with, and may conflict with
existing NERC Reliability Standards.
---------------------------------------------------------------------------
\554\ Southern Companies at 77 n.251 (citing 5 U.S.C. 706).
---------------------------------------------------------------------------
iii. Commission Determination
477. The Commission affirms its decision to require each public
utility transmission provider to amend its OATT to describe the
circumstances and procedures under which public utility transmission
providers in the regional transmission planning process 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.\555\ As the
Commission explained in Order No. 1000, the focus here is on ensuring
that adequate processes are in place to determine whether delays
associated with completion of a transmission facility selected in a
regional transmission plan for purposes of cost allocation have the
potential to adversely affect an incumbent transmission provider's
ability to fulfill its reliability needs or service obligations. We
believe that if these processes are followed, incumbent transmission
providers should be able to meet reliability related requirements.
---------------------------------------------------------------------------
\555\ Order 1000, FERC Stats. & Regs. ] 31,323 at P 329.
---------------------------------------------------------------------------
478. In response to Xcel's and Southern Companies' argument that
the reevaluation requirement does not protect against the need to
implement operational adjustments, the present operationally-focused
NERC reliability standards require Functional Entities to operate so
that the portion of the system that is in service at that time will be
capable of delivering the output of generation to firm demand and
transfers within the applicable performance criteria. Accordingly, a
Functional Entity must prepare its system to operate regardless of
whether a transmission project is delayed or abandoned. Thus, the
Commission concludes that there is no need to set requirements in
addition to those already established in the applicable NERC
reliability standards.
479. In response to those petitioners concerned that they must
individually monitor the status of a nonincumbent transmission
developer's progress in developing its transmission facility selected
in the regional transmission plan for purposes of cost allocation, we
note that transmission planners and transmission developers already
routinely communicate regarding the status of the construction of a
transmission project. Consistent with applicable NERC Reliability
Standards, a Functional Entity remains responsible for complying with
all applicable Reliability Standards, such as studying performance of
its system and deciding when it must develop corrective plans to ensure
that its system responds reliably as prescribed by those
standards.\556\ As such, we emphasize that Order No. 1000 does not
change any obligations an incumbent transmission provider, as a
Functional Entity, may have under the NERC Reliability Standards to
monitor a nonincumbent transmission developer's progress in developing
its transmission facility selected in the regional transmission plan
for purposes of cost allocation. Furthermore, Order No. 1000 left it to
public utility transmission providers in a transmission planning region
to adopt procedures in their OATTs for reevaluating transmission
facilities selected in the regional transmission plan for purposes of
cost allocation. We continue to believe this approach is appropriate.
---------------------------------------------------------------------------
\556\ NERC Reliability Standards in the Facility Connection and
Transmission Planning series ensure evaluation of the reliability
impact of the new facilities connections, and coordination and
results sharing by the entities involved, as well as development of
corrective plans if reliability requirements are not met when
projects are delayed or abandon.
---------------------------------------------------------------------------
480. The Commission also affirms, with certain clarifications, its
decision in Order No. 1000 to not subject an incumbent public utility
transmission provider to a penalty for a violation of a NERC
reliability standard caused by a nonincumbent transmission developer's
decision to abandon a transmission facility if the incumbent public
utility transmission provider has identified the violation and
submitted a NERC mitigation plan to address it.\557\ The Commission
used ``enforcement action'' in Order No. 1000, but is not using this
term here because ``enforcement action'' also could imply that
Registered Entities are not going to be required to mitigate any NERC
reliability standards violations. The Commission clarifies that,
although it will not seek penalties, it will ensure that Registered
Entities implement appropriate mitigation plans.
---------------------------------------------------------------------------
\557\ Order 1000, FERC Stats. & Regs. ] 31,323 at P 344.
---------------------------------------------------------------------------
481. The Commission agrees with petitioners that argue that
entities other than incumbent public utility transmission providers may
violate a NERC reliability standard in the event that a nonincumbent
transmission developer abandons a transmission facility. In some
regions, the incumbent public utility transmission provider may not be
the entity responsible for complying with the NERC reliability
standards implicated by the abandonment of a nonincumbent transmission
developer's project. We also agree with Ameren and other petitioners
that argue that the abandonment of a nonincumbent transmission project
that is designed to meet economic needs or transmission needs driven by
a Public Policy Requirement could impact reliability. Therefore, we
clarify that the Commission will not subject a Registered Entity \558\
to a penalty for a violation of a NERC reliability standard caused by a
nonincumbent transmission developer's decision to abandon any type of
transmission facility selected in the regional transmission plan for
purposes of cost allocation if, on a timely basis, that Registered
Entity identifies the violation and complies with all of its
obligations under the NERC reliability standards to address it.
---------------------------------------------------------------------------
\558\ We use the term Registered Entity to refer an owner,
operator, or user of the Bulk Power System, or the entity registered
as its designee for the purpose of compliance, that is included in
the NERC Compliance Registry. See, North American Electric
Reliability Corporation, Compliance Monitoring and Enforcement
Program, Appendix 4C to the Rules of Procedures (effective Jan. 31,
2012), available at: http://www.nerc.com/files/Appendix_4C_CMEP_20120131.pdf.
---------------------------------------------------------------------------
482. The remaining requests for rehearing or clarification posit
enforcement situations that are uncertain or speculative. We decline to
rule on these requests for rehearing or clarification because we find
that they are premature. We believe that, with the clarifications
granted above, entities have sufficient information to understand when
the Commission will not subject a Registered Entity to enforcement
action for a violation of a NERC reliability standard caused by a
nonincumbent transmission developer's decision to abandon a
transmission facility. Furthermore, many of these petitions in effect
argue that the Commission should not have required
[[Page 32260]]
public utility transmission providers to eliminate a federal right of
first refusal from Commission jurisdictional-tariffs and agreements in
Order No. 1000. The Commission has adequately explained in Order No.
1000 and in this order the need for eliminating a federal right of
first refusal.
483. Finally, contrary to arguments by petitioners, the Commission
was not required to use its section 215 authority to adopt the
reevaluation requirements or to state the circumstances under which it
would exercise its enforcement discretion. Rather, the reevaluation
requirement is a tariff obligation not a reliability obligation under
section 215. Furthermore, in stating the circumstances under which the
Commission would exercise its enforcement discretion, the Commission
did not create new, or modify existing, NERC reliability standards. Had
the Commission done so, it would be required to adopt a reliability
standard through its authority set out in section 215. Instead, the
Commission appropriately exercised its discretion under section 215
enforcement authority to set forth a particular circumstance when it
will not e penalize a Registered Entity.
d. Recovery of Abandoned Plant Costs and Backstop Authority
i. Final Rule
484. In Order No. 1000, the Commission found that when an incumbent
transmission provider is called upon to complete a transmission project
that it did not sponsor, there would be a basis for the incumbent
transmission provider to be granted abandoned plant recovery for that
transmission facility, upon the filing of a petition for declaratory
order requesting such rate treatment or a request under section 205 of
the FPA.\559\
---------------------------------------------------------------------------
\559\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 267.
---------------------------------------------------------------------------
ii. Requests for Rehearing
485. APPA and Transmission Access Policy Study Group question the
Commission's decision to grant abandoned plant cost recovery to an
incumbent transmission provider in certain circumstances. Transmission
Access Policy Study Group and APPA argue that granting incumbent
transmission providers abandoned cost recovery under Order No. 1000 is
an unjustified deviation from Order No. 679's case-by-case approach.
Transmission Access Policy Study Group raises several questions that it
asserts highlight the need for the Commission to look at the facts of
each request for abandoned plant recovery rather than committing the
public in all circumstances to pay for unfinished projects. APPA argues
that abandoned plant cost recovery is an incentive that should be
granted on a case-by-case basis where the granting of such an incentive
is shown to be necessary and appropriate.
486. Southern California Edison also notes that Order No. 1000
states in paragraph 344 that the incumbent transmission owner does not
have an obligation to construct a transmission facility intended to
address a possible NERC violation, but then states in paragraph 267
that there may be circumstances when an incumbent may be called upon to
complete a project that it did not sponsor. Southern California Edison
requests that the Commission clarify: (1) How the statements in
paragraphs 267 and 344 should be reconciled so that they are
consistently interpreted and implemented; (2) in which situations a
transmission provider may be required to complete a transmission
facility it did not sponsor; and (3) what that completion obligation
entails.
487. Southern California Edison also seeks clarification that Order
No. 1000 does not preclude regions from applying backstop transmission
development obligations to all participating transmission owners in the
region and allows regions that impose backstop obligations to apply
them on an equivalent basis among incumbents and nonincumbents.
Southern California Edison argues that to require only incumbents to
serve as the safety-net for all nonincumbent projects would impose a
burden upon incumbents that could impede their ability to compete for
projects. On the other hand, Xcel recommends that tariffs incorporate a
backstop that reflects the incumbent utility's obligation as provider
of last resort to build transmission needed for reliability even if the
incumbent does not exercise a right of first refusal and no one else
offers to build it.
488. Southern California Edison requests clarification that the
incumbent transmission owner will be fully compensated for mitigation
costs through ``grid-wide'' rates to offset the substantial burden of
developing and implementing mitigation plans. In addition, Edison
Electric Institute seeks clarification that an incumbent transmission
provider that steps in to complete an abandoned reliability project in
the circumstances discussed in paragraph 344 of Order No. 1000, it has
no obligation to purchase the facilities, materials, or any other
assets related to the abandoned project, at cost or otherwise. It
argues that such a requirement would provide unwarranted financial
protections for nonincumbent transmission developers, and remove one of
the key incentives to complete a project once begun. Similarly,
Southern Companies argue that Order No. 1000 will discriminate in favor
of third party developers at the expense of an incumbent's native load
and OATT customers unless the Commission ensures that developers of
regional projects are held responsible and accountable for any and all
adverse effects of their construction delays or abandonments upon
incumbents, including any increased costs caused thereby.\560\
---------------------------------------------------------------------------
\560\ Southern Companies at 83-84 (citing Chicago v. FPC, 385
F.2d 629, 637 (D.C. Cir. 1967)).
---------------------------------------------------------------------------
iii. Commission Determination
489. In response to Transmission Access Policy Study Group and
APPA, we clarify that we will, consistent with Order No. 679,\561\
grant abandoned plant recovery on a case-by-case basis. Order No. 1000
did not provide a blanket grant of abandoned plant recovery, but merely
stated that where an incumbent transmission provider is called upon to
complete a transmission project that another entity has abandoned, this
would be a basis for the incumbent transmission provider to be granted
abandoned plant recovery for that transmission facility, upon the
filing of a petition for declaratory order requesting such rate
treatment or a request under section 205 of the FPA.\562\
---------------------------------------------------------------------------
\561\ Order No. 679, FERC Stats. & Regs. ] 31,222.
\562\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 267.
---------------------------------------------------------------------------
490. In response to Southern California Edison, nothing in Order
No. 1000 requires an incumbent transmission provider to construct a
nonincumbent transmission developer's transmission project selected in
the regional transmission plan for purposes of cost allocation if it
abandons a transmission facility.\563\ We note, however, that some RTOs
and ISOs may have the authority under their tariff or membership
agreements to direct a member to build a transmission facility under
certain circumstances.\564\ Further, Order No. 1000 did not address the
issue of backstop construction authority or responsibility for any
transmission project, whether undertaken initially by an incumbent or a
nonincumbent transmission developer. Accordingly,
[[Page 32261]]
this issue is beyond the scope of this proceeding, and we will not
address it on rehearing.
---------------------------------------------------------------------------
\563\ Id. P 344.
\564\ See, e.g., PJM Consolidated Transmission Owners Agreement
at section 4.2.1.We note that a nonincumbent transmission developer
that becomes a member of an RTO or ISO may be subject to an
obligation to build that applies to transmission-owning members.
---------------------------------------------------------------------------
491. In response to Southern California Edison's request that
incumbent transmission providers be compensated for the cost of
developing implementing a mitigation plan through ``grid-wide'' rates,
we did not provide a generic answer in Order No. 1000 and do not do so
here. That is, we are not deciding here whether a transmission provider
may recover, or how it may recover, the costs that result from
complying with the Reliability Standards if a nonincumbent transmission
developer delays or abandons a needed transmission project.
492. In response to Edison Electric Institute, the Commission does
not require under Order No. 1000 that an incumbent transmission
developer purchase the facilities, materials, or any other assets
related to an abandoned project that the incumbent transmission
provider determines it must complete. However, Order No. 1000 also does
not preclude an incumbent transmission developer from purchasing such
facilities, materials or other assets if it believes it is prudent to
do so.
C. Interregional Transmission Coordination
1. Interregional Transmission Coordination Requirements
a. Interregional Transmission Coordination Procedures and Geographical
Scope
i. Final Rule
493. In Order No. 1000, the Commission required each public utility
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.\565\ Furthermore, the Commission 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.\566\
---------------------------------------------------------------------------
\565\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 396.
\566\ Id. P 398.
---------------------------------------------------------------------------
494. In Order No. 1000, the Commission also required each public
utility transmission provider through its regional transmission
planning process to coordinate with the public utility transmission
providers in each of its neighboring transmission planning regions
within its interconnection to implement the interregional transmission
coordination requirements.\567\ The Commission defined an interregional
transmission facility as one that is located in two or more
transmission planning regions.\568\ The Commission declined to require,
but did not prohibit, joint evaluation of other facilities or study of
the effects in a second region of a new transmission facility proposed
to be located in a single transmission planning region.\569\ The
Commission explained that to do otherwise could have the effect of
mandating interconnectionwide transmission planning, because a
transmission facility located within one transmission planning region
can have effects on many systems in the interconnection, which could
trigger a chain of multiregional evaluation processes. Furthermore, the
Commission observed that its interregional transmission coordination
requirements will assist transmission planners in understanding and
managing the effects of a transmission facility located in one region
on a neighboring region.\570\
---------------------------------------------------------------------------
\567\ Id. P 415.
\568\ Id. P 482 n.374.
\569\ Nevertheless, consistent with Cost Allocation Principle 4,
each regional transmission planning process must identify the
consequences of a proposed new transmission facility for other
transmission planning regions. The Commission also stated that Order
No. 1000 did not affect any obligations that public utility
transmission providers may otherwise have to assess the effects of
new transmission facilities on other systems, including, but not
limited to, any other requirement of the OATT for interconnection
studies, any requirement under the NERC reliability standards, and
the requirements of Good Utility Practice. Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 416 n.351.
\570\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 416.
---------------------------------------------------------------------------
ii. Requests for Rehearing and Clarification
495. AEP asks the Commission to ensure that the interregional
coordination requirements apply to transmission needs driven by public
policy requirements. Otherwise, AEP states, planners will settle on
less efficient and less cost-effective solutions, which increase costs.
AEP argues that it is arbitrary and capricious for the Commission not
to require consideration of needs driven by public policy requirements
as part of interregional coordination, in light of its findings on the
importance of public policy considerations in the Final Rule. AEP also
argues that requiring consideration of transmission needs driven by
public policy requirements within a region but not between regions
places too much emphasis and importance on the decisions about
configuration of the planning regions given that the Commission has
declined to prescribe the geographic scope of any transmission planning
region.
496. Bonneville Power states that certain aspects of Order No. 1000
indicate that formal procedures need to cover only identification and
joint evaluation rather than planning and developing interregional
transmission facilities. If this is what the Commission meant, then
Bonneville Power requests that the Commission so clarify.
497. On rehearing, MISO Transmission Owners Group 1 and Wisconsin
PSC request that the Commission expand the definition of an
interregional transmission facility. Specifically, MISO Transmission
Owners Group 1 requests that the Commission find that transmission
facilities physically located within one region can be considered
interregional transmission facilities when they provide sufficient
benefits as determined in accordance with the applicable interregional
agreement or OATTs, and can be eligible for interregional cost
allocation pursuant to criteria set forth in that agreement or those
OATTs. Wisconsin PSC makes a similar argument. Wisconsin PSC also
requests that the Commission remove the single-region limitation, and
instead limit evaluation of a single-region project to interregional
transmission planning processes that involve no more than two
transmission planning regions. Wisconsin PSC adds that the Commission
could further limit consideration by requiring the project sponsor to
publicly identify a single-region transmission facility as benefiting
the other affected region to ensure that a project does not ``fly under
the radar.'' \571\ Both Wisconsin PSC and MISO Transmission Owners
Group 1 argue that their respective definitions eliminate the
Commission's concern
[[Page 32262]]
that expanding the scope of interregional transmission coordination
would lead to interconnectionwide transmission planning.
---------------------------------------------------------------------------
\571\ Wisconsin PSC at 6-7.
---------------------------------------------------------------------------
498. Furthermore, MISO Transmission Owners Group 1 argues that the
Commission should expand the definition because the expanded definition
would help ensure that the costs of such facilities are allocated in a
manner that is at least roughly commensurate with the benefits
received. Wisconsin PSC asserts that requiring regions to jointly
consider single-region projects in the interregional planning process
would diminish the risk of inadvertent free ridership, ensure that
intended beneficiaries of a project are allocated a share of the
project costs, and expand the set of potential cost-effective
transmission solutions to regional transmission needs. Wisconsin PSC
adds that not eliminating this exclusion may create a specific
violation of the application of the cost causation/beneficiaries pay
principles articulated in Illinois Commerce Comm'n v. FERC, which
require beneficiaries of a transmission project to pay a roughly
commensurate share of project costs.\572\
---------------------------------------------------------------------------
\572\ Wisconsin PSC at 5 (citing 576 F.3d 470 (7th Cir. 2009)).
---------------------------------------------------------------------------
499. Wisconsin PSC and MISO Transmission Owners Group 1 also argue
that it is especially important to expand the definition because MISO
has extensive seams with neighboring RTOs and other regions. Wisconsin
PSC adds that it is virtually impossible for MISO to plan a
transmission line in those areas without providing potential benefits
to PJM load. Thus, it argues that the single-region limitation would
increase the free ridership that the Commission seeks to deter.
iii. Commission Determination
500. We deny AEP's arguments that Order No. 1000's interregional
transmission coordination requirements do not adequately provide for
consideration of transmission needs driven by Public Policy
Requirements. In Order No. 1000, the Commission determined that
interregional transmission coordination neither requires nor precludes
longer-term interregional transmission planning, including the
consideration of transmission needs driven by Public Policy
Requirements.\573\ Order No. 1000 stated that whether and how to
address this issue with regard to interregional transmission facilities
is a matter for public utility transmission providers, through their
regional transmission planning processes, to resolve in the development
of compliance proposals.\574\ We clarify that Order No. 1000 does not
require or prohibit consideration of transmission needs driven by
Public Policy Requirements as part of interregional transmission
coordination. However, such considerations are required through the
regional transmission planning process, which is an integral part of
interregional transmission coordination because all interregional
transmission projects must be selected in both of the relevant regional
transmission planning processes in order to receive interregional cost
allocation. Therefore, consideration of transmission needs driven by
Public Policy Requirements is an essential part of the evaluation of an
interregional transmission project, not as part of interregional
transmission coordination, but rather as part of the relevant regional
transmission planning processes. As such, we continue to believe that
the decision of whether and how to address these issues with regard to
interregional transmission facilities in the regional transmission
planning processes is a matter for public utility transmission
providers to work out with their stakeholders in the development of
compliance proposals.\575\
---------------------------------------------------------------------------
\573\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 401.
\574\ Id. P 401.
\575\ Id.
---------------------------------------------------------------------------
501. We clarify for Bonneville Power that Order No. 1000 only
requires the development of a formal procedure to identify and jointly
evaluate interregional transmission facilities that are proposed to be
located in neighboring transmission planning regions.\576\ We
emphasize, however, that while the Commission does not require any
particular type of studies to be conducted, the purpose of identifying
and jointly evaluating interregional transmission facilities is to
determine whether they may more efficiently or cost-effectively meet
transmission needs than regional transmission facilities.\577\
---------------------------------------------------------------------------
\576\ Id. P 435.
\577\ Id. P 398.
---------------------------------------------------------------------------
502. We decline to expand the definition of an interregional
transmission facility adopted in Order No. 1000, as requested by MISO
Transmission Owners Group 1 and Wisconsin PSC. As the Commission
explained in Order No. 1000, requiring joint evaluation of the effects
of a new transmission facility proposed to be located solely in a
single transmission planning region could, in effect, mandate
interconnectionwide transmission planning. This is because transmission
facilities located in one transmission planning region often have
effects on multiple neighboring systems, which could trigger a chain of
multilateral evaluation processes.\578\ While the definitions of an
interregional transmission facility proposed by MISO Transmission
Owners Group 1 and Wisconsin PSC could help to restrict the range of
proposed new transmission facilities subject to joint evaluation, we
disagree that they are sufficient to address the Commission's concern
that expanding the definition of an interregional transmission facility
adopted in Order No. 1000 could mandate interconnectionwide
transmission planning. Adopting MISO Transmission Owners Group 1 and
Wisconsin PSC's expanded definitions of an interregional transmission
facility could still, in effect, mandate that certain transmission
projects located solely in a single transmission planning region be
planned on a multilateral, if not interconnectionwide, basis, and we
are not persuaded that such a requirement is necessary at this time.
The Commission exercised its discretion in this rulemaking to improve
regional transmission planning and bilateral interregional transmission
coordination in a manner that does not have the effect of requiring
interconnectionwide planning. Moreover, we reiterate here the
Commission's conclusion in Order No. 1000 that imposing multilateral or
interconnectionwide transmission coordination requirements at this time
could frustrate the progress being made in the ARRA-funded transmission
planning initiatives.\579\
---------------------------------------------------------------------------
\578\ Id. P 416.
\579\ Id. P 417.
---------------------------------------------------------------------------
503. We also do not believe it is necessary to expand the
definition of an interregional transmission facility, as argued by
Midwest ISO Transmission Owners Group 1 and Wisconsin PSC, in order to
ensure that the costs of a transmission facility located in a single
transmission planning region that benefits a neighboring transmission
planning region are allocated commensurately with the benefits it
provides. As we explain more fully below,\580\ these arguments fail to
take into account the relationship between the Commission's cost
allocation reforms and the other reforms contained in Order No. 1000
and the need to balance a number of factors to ensure that the reforms
achieve the goal of improved transmission planning. In particular, as
we stated in Order No. 1000, these reforms establish a closer link
between regional transmission planning and cost allocation, both of
[[Page 32263]]
which involve the identification of beneficiaries. In light of that
closer link, we continue to find that allowing one region to allocate
costs unilaterally to entities in another region would effectively
impose an affirmative burden on stakeholders to actively monitor
transmission planning processes in numerous other regions in which they
could be identified as beneficiaries and thus be subject to cost
allocation. This would essentially result in interconnectionwide
transmission planning with corresponding cost allocation, albeit
conducted in a highly inefficient manner.\581\
---------------------------------------------------------------------------
\580\ See discussion infra at section 0.
\581\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 660.
---------------------------------------------------------------------------
504. We note, however, that the public utility transmission
providers in neighboring transmission planning regions may negotiate an
agreement to share the costs of a particular transmission facility with
the beneficiaries in another transmission planning region, as they
always have been free to do.\582\ Further, nothing in Order No. 1000
precludes public utility transmission providers in consultation with
stakeholders from voluntarily developing and proposing interregional
transmission coordination procedures providing for the joint evaluation
by more than one transmission planning region of a transmission
facility located solely in one transmission planning region should the
public utility transmission providers in neighboring transmission
planning regions agree to do so.\583\ Also, we reiterate that Order No.
1000's limited requirements for bilateral interregional transmission
coordination do not prohibit either voluntary multilateral
interregional transmission coordination or planning, or the development
of stronger bilateral coordination agreements than the rule requires.
---------------------------------------------------------------------------
\582\ Id. P 658.
\583\ Id. P 416.
---------------------------------------------------------------------------
505. Finally, Wisconsin PSC specifically mentions that transmission
lines in MISO often provide potential benefits to PJM load. As the
Commission recognized in Order No. 1000, MISO and PJM developed a
cross-border cost allocation method in response to Commission
directives related to their intertwined configuration that permits
them, in certain cases, to allocate to one RTO or ISO the cost of a
transmission facility that is located entirely within the other RTO or
ISO. We reiterate here that Order No. 1000 does not require MISO and
PJM to revise their existing cross-border cost allocation method in
response to Cost Allocation Principle 4.\584\
---------------------------------------------------------------------------
\584\ Id. P 662.
---------------------------------------------------------------------------
2. Implementation of the Interregional Transmission Coordination
Requirements
a. Procedure for Joint Evaluation
i. Final Rule
506. The Commission required the developer of an interregional
transmission project to first propose its transmission project in the
regional transmission planning processes of each of the neighboring
regions in which the transmission facility is proposed to be located.
The submission of an interregional transmission project in each
regional transmission planning process will trigger the procedure under
which the public utility transmission providers, acting through their
regional transmission planning processes, will jointly evaluate the
proposed transmission project.\585\ The Commission required that joint
evaluation be conducted in the same general timeframe as, rather than
subsequent to, each transmission planning region's individual
consideration of the proposed transmission project.\586\ For an
interregional transmission facility to receive cost allocation under
the interregional cost allocation method or methods developed pursuant
to Order No. 1000, the Commission required that the transmission
facility be selected in both of the relevant regional transmission
plans for purposes of cost allocation.\587\ Finally, the Commission
directed each public utility transmission provider, through its
transmission planning region, to develop procedures by which
differences in planning criteria can be identified and resolved for
purposes of jointly evaluating a proposed interregional transmission
facility.\588\
---------------------------------------------------------------------------
\585\ Id. P 436.
\586\ Id. P 439.
\587\ Id. P 436.
\588\ Id. P 437.
---------------------------------------------------------------------------
ii. Requests for Rehearing and Clarification
507. Joint Petitioners and ITC Companies seek rehearing of the
Commission's requirement that both neighboring transmission planning
regions must agree to include a proposed interregional transmission
facility in their respective regional transmission plans for it to be
eligible for interregional cost allocation. Instead, Joint Petitioners
argue that the Commission should require the preparation and approval
of an interregional plan, or at the very least, provide a mechanism by
which a sponsor of an interregional transmission project can obtain
Commission review of a disagreement or failure to act by and among
affected planning regions. They assert that requiring each region to
include an interregional facility in its respective plan is
counterproductive because the Commission did not require the consistent
use of specific planning horizons or the performance of particular
scenario analyses for purposes of regional planning. Additionally,
Joint Petitioners contend that even if a project is determined to be
the most efficient, cost-effective project for the broader region
composed of both planning regions, either region may veto the project
because those broader benefits are not considered in the individual
regional plans.
508. WIRES states that the planning experiences of RTOs and ISOs
and the record in this proceeding contain many examples of planning
procedures and criteria that are suitable for two regions to coordinate
their planning efforts. WIRES adds that adopting these procedures,
which establish fixed timelines for decision, data exchange
requirements, planning assumptions, and standard modeling techniques,
along with clear opportunities for exceptions where necessary, would
shorten and rationalize planning processes without dictating outcomes.
WIRES asserts that technical conferences could be useful for developing
a consensus on these matters.
iii. Commission Determination
509. We deny Joint Petitioners' and ITC Companies' request for
rehearing of 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.\589\ Rather, we reaffirm this requirement. As stated above,
Order No. 1000 establishes a closer link between transmission planning
and cost allocation. As discussed more fully below in the section on
stakeholder participation,\590\ Order No. 1000 provides for stakeholder
involvement in the consideration of an interregional transmission
facility primarily through the regional transmission planning
processes.\591\ We
[[Page 32264]]
therefore conclude 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.
---------------------------------------------------------------------------
\589\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 436.
\590\ See discussion infra at section 0.
\591\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 465; see
also id. P 443.
---------------------------------------------------------------------------
510. We disagree with Joint Petitioners' contention that Order No.
1000 did not require consistency in planning horizons or scenario
analyses. In Order No. 1000, the Commission directed each public
utility transmission provider, through its transmission planning
region, to develop procedures by which differences in the data, models,
assumptions, planning horizons, and criteria used to study a proposed
interregional transmission project can be identified and resolved for
purposes of jointly evaluating an interregional transmission
project.\592\ This approach allows regions the flexibility to develop
procedures that work for them, while still addressing the concern that
joint evaluation of a proposed interregional transmission facility
cannot be effective without some effort by neighboring transmission
planning regions to harmonize differences in the data, models,
assumptions, planning horizons, and criteria used to study a proposed
transmission project.\593\ We therefore decline to adopt WIRES'
suggestion that we require that public utility transmission providers
implement certain specific planning procedures or criteria, or that we
hold a technical conference to consider such matters.
---------------------------------------------------------------------------
\592\ Id. P 437.
\593\ Id.
---------------------------------------------------------------------------
511. Moreover, we decline to require the preparation and approval
of an interregional transmission plan or to adopt a mechanism for the
Commission to review neighboring transmission planning regions'
disagreements about or failure to act on a proposed interregional
transmission facility as requested by Joint Petitioners. Joint
Petitioners have not convinced us that such measures are necessary in
this generic rulemaking. As the Commission found in Order No. 1000, the
interregional transmission coordination reforms do not require the
creation of a distinct interregional transmission planning process to
produce an interregional transmission plan or the formation of
interregional transmission planning entities. Rather, the requirement
is for public utility transmission providers to consider whether the
local and regional transmission planning processes result in
transmission plans that meet local and regional transmission needs more
efficiently and cost-effectively, after considering opportunities for
collaborating with public utility transmission providers in neighboring
transmission planning regions.\594\ However, as the Commission stated
in Order No. 1000, public utility transmission providers may
voluntarily engage in interregional transmission planning and, as
relevant, rely on such a planning process to comply with the
interregional transmission coordination requirements of Order No.
1000.\595\
---------------------------------------------------------------------------
\594\ Id. P 399.
\595\ Id.
---------------------------------------------------------------------------
512. Finally, we understand Joint Petitioners' concern that a
transmission planning region may decline to select an interregional
transmission project in its regional transmission plan for purposes of
cost allocation if the project does not sufficiently benefit that
region, even if it is the more efficient or cost-effective project for
the broader multiregional area. This is another version of the argument
made by petitioners that prefer interconnectionwide transmission
planning to regional transmission planning. However, we decline to
require interconnectionwide planning in this rulemaking for the reasons
set out in Order No. 1000 and summarized above. We understand 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--and that this feature would not necessarily apply for
interconnectionwide planning. We continue to believe however 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.
b. Stakeholder Participation
i. Final Rule
513. In Order No. 1000, the Commission did not require the
interregional transmission coordination procedures to meet the
requirements of the transmission planning principles required for local
planning (under Order No. 890) and regional planning (under Order No.
1000).\596\ The Commission explained that stakeholders will have the
opportunity to participate fully in the consideration of interregional
transmission facilities during the regional transmission planning
process, because each region must select such a facility in its
regional transmission plan for purposes of cost allocation in order for
it to be eligible for interregional cost allocation.\597\ The
Commission also required public utility transmission providers to make
transparent the analyses undertaken and determinations reached by
neighboring transmission planning regions in the identification and
evaluation of interregional transmission facilities.\598\ Last, the
Commission required that each public utility transmission provider give
stakeholders the opportunity to provide input into the development of
its interregional transmission coordination procedures and the commonly
agreed-to language to be included in its OATT.\599\
---------------------------------------------------------------------------
\596\ Id. P 465.
\597\ Id.
\598\ Id.
\599\ Id. P 466.
---------------------------------------------------------------------------
ii. Requests for Rehearing and Clarification
514. Transmission Dependent Utility Systems and PSEG Companies
argue that the Commission should have required public utility
transmission providers to provide for more stakeholder participation in
the interregional coordination process and procedures. Transmission
Dependent Utility Systems also seek clarification or, in the
alternative, argue that the Commission should require on rehearing,
that stakeholders have a meaningful opportunity to participate in the
development of the interregional coordination process before it is
submitted to the Commission in a compliance filing, whether the process
is reflected in the OATT or in a bilateral agreement.
515. In addition, Transmission Dependent Utility Systems argue that
stakeholders must be allowed to participate throughout the process to
ensure that load-serving transmission customers receive treatment
comparable to the treatment transmission providers accord their retail
and wholesale merchant functions, as required by sections 205 and
217(b)(4), Order No. 890, and the judicial requirement for reasoned
decision-making.\600\ PSEG
[[Page 32265]]
Companies argue that Order No. 1000's assumption that this issue will
be addressed under the regional processes is unsupported. They also
argue that the lack of a specific requirement for stakeholder
participation is inconsistent with some of the other interregional
coordination requirements in Order No. 1000, including requirements
related to joint evaluation of interregional projects and the
determination of beneficiaries of such projects.
---------------------------------------------------------------------------
\600\ Transmission Dependent Utility Systems at 18 (citing Motor
Vehicle Mfrs. Ass'n v. State Farm Mut. Auto Ins. Co., 463 U.S. 29,
43 (1983)).
---------------------------------------------------------------------------
516. Moreover, Transmission Dependent Utility Systems argue that
stakeholders must have a meaningful opportunity to participate in the
early stages of the process for identifying and evaluating possible
interregional solutions to transmission customer concerns. Similarly,
PSEG Companies recommend that the Commission require that interregional
coordination procedures include information on: (1) How transmission
providers will facilitate stakeholder participation; (2) how market
participants can propose ideas for cross-border projects and identify
and submit concerns about problems in one region caused by activity in
another (and how to address those concerns); and (3) how transmission
providers will accommodate and track in a transparent manner all
questions, comments, and other input from stakeholders regarding data
posted on coordination activities, as well as transmission providers'
responses.
517. Transmission Dependent Utility Systems also assert that Order
No. 1000 fails to address their larger concern, which is that the
interregional coordination processes fail to obligate public utility
transmission providers to share with stakeholders the data exchanged
among themselves, including study results, models, input data, and
assumptions used in running those studies. Transmission Dependent
Utility Systems are concerned that public utility transmission
providers may contend that the obligation to share does not include
load-serving customers. Further, Transmission Dependent Utility Systems
state the Commission should clarify that the interregional planning
data that is shared with load-serving entities must be sufficient to
allow them to replicate the interregional planning study results,
including models, base cases, data inputs, and assumptions.
Transmission Dependent Utility Systems also believe it is important
that benefit-to-cost analyses of interregional projects be transparent
and verifiable to protect customers, ensure accuracy, and minimize ex
post facto disputes regarding regional and interregional cost
allocation.
iii. Commission Determination
518. First, we clarify for Transmission Dependent Utility Systems
that each public utility transmission provider must provide
stakeholders with a meaningful opportunity to provide input into the
development of its interregional transmission coordination procedures
before those procedures are submitted to the Commission in its
compliance filing, whether those procedures are included in its OATT or
reflected in an interregional transmission coordination agreement.\601\
Accordingly, stakeholders must be afforded sufficient time to
meaningfully comment on a public utility transmission provider's
proposed interregional transmission coordination procedures as they are
being developed.
---------------------------------------------------------------------------
\601\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 466.
---------------------------------------------------------------------------
519. In response to those petitioners that raise concerns regarding
stakeholder participation in the interregional transmission
coordination process, we reiterate the Commission's statement in Order
No. 1000 that stakeholder participation in the consideration of
interregional transmission facilities is an important component of
interregional transmission coordination. Moreover, we also reiterate
that stakeholders will have the opportunity to provide input with
respect to the consideration of interregional transmission facilities
when these facilities are being considered in the regional transmission
planning process. As stated above, Order No. 1000 provides that only if
an interregional transmission facility is selected in each region's
transmission plan for purposes of cost allocation will that facility's
cost be allocated to either region.\602\ It is therefore through
participation in the regional transmission planning process that
stakeholders will have the primary opportunity to participate fully in
the consideration of interregional transmission facilities. While
nothing in Order No. 1000 prohibits an interregional transmission
coordination process from providing for more direct stakeholder
involvement in interregional transmission coordination, it may be the
case that much of the interregional transmission coordination would
occur through sharing computer modeling results regarding the effects
and benefits of a proposed interregional transmission facility, which
may be harder for a broad community of stakeholders to participate in
than would face to face meetings be. If we are being asked to require
there be in-person meetings for interregional transmission coordination
with all stakeholders attending, we would be concerned about requiring
a cumbersome process that could necessitate significant expense and
travel time to multiple neighboring regions by the large number of
stakeholders in each region. We continue to believe it is sufficient
and appropriate to allow for consideration of stakeholder interests by
requiring that any decision on interregional cost allocation be
affirmed by each of the transmission planning regions involved.
---------------------------------------------------------------------------
\602\ Id. P 465.
---------------------------------------------------------------------------
520. For similar reasons, we decline to expand the requirements of
Order No. 1000 regarding the types and sufficiency of interregional
transmission coordination information to be exchanged between regions
and provided to stakeholders. We therefore affirm Order No. 1000's
requirement that, in order to facilitate stakeholder involvement,
public utility transmission providers must, subject to appropriate
confidentiality protections and CEII requirements, make transparent the
analyses undertaken and determinations reached by neighboring
transmission planning regions in the identification and evaluation of
interregional transmission facilities.\603\
---------------------------------------------------------------------------
\603\ Id.
---------------------------------------------------------------------------
521. Further, we decline to adopt PSEG Companies' recommendation
that the Commission require the interregional transmission coordination
procedures to include information on how stakeholders in one
transmission planning region can raise issues and solutions regarding
activity in another transmission planning region. The regional
transmission planning process already provides stakeholders with the
opportunity to present such concerns, and we continue to believe that
these concerns are best addressed in the first instance through the
regional transmission planning process, particularly as the solution
may not involve an interregional transmission facility.
522. In light of this, however, we clarify that each public utility
transmission provider must describe in its OATT how its regional
transmission planning process will enable stakeholders to provide
meaningful and timely input with respect to the consideration of
interregional transmission facilities. Moreover, as requested by PSEG
Companies, we require that each public utility transmission provider
must explain in its OATT how stakeholders and transmission developers
can propose interregional transmission facilities for
[[Page 32266]]
the public utility transmission providers in neighboring transmission
planning regions to evaluate jointly. This is consistent with Order No.
1000's requirement that on compliance, public utility transmission
providers must describe the methods by which they will identify and
evaluate interregional transmission facilities.\604\
---------------------------------------------------------------------------
\604\ Id. P 398.
---------------------------------------------------------------------------
IV. Cost Allocation
523. 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'').\605\ The OATTs of all
public utility transmission providers in a region must include the same
cost allocation method or methods adopted by the region.
---------------------------------------------------------------------------
\605\ Id. 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.
---------------------------------------------------------------------------
524. The regional and interregional cost allocation methods each
must 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 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.\606\ 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.\607\ 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.\608\ 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.\609\
---------------------------------------------------------------------------
\606\ Id. PP 622-93.
\607\ Id. P 588.
\608\ Id. P 482.
\609\ Id. P 483.
---------------------------------------------------------------------------
A. Legal Authority for Cost Allocation Reforms
1. Final Rule
525. In Order No. 1000, the Commission determined that its
jurisdiction is broad enough to allow it to ensure that all
beneficiaries of services provided by specific transmission facilities
bear the costs of those benefits regardless of their contractual
relationship with the owner of those transmission facilities.\610\ The
Commission stated that this comports fully with the specific
characteristics of transmission facilities and transmission services,
and that the provisions of Order No. 1000 are necessary to fulfill the
Commission's statutory duty of ensuring rates, terms and conditions of
jurisdictional service are just and reasonable and not unduly
discriminatory or preferential.\611\
---------------------------------------------------------------------------
\610\ Id. P 531.
\611\ Id.
---------------------------------------------------------------------------
526. The Commission based its finding on the language of section
201(b)(1) of the FPA, which gives the Commission jurisdiction over
``the transmission of electric energy in interstate commerce.'' \612\
The Commission concluded that its jurisdiction therefore extends to the
rates, terms and conditions of transmission service, rather than merely
transactions for such transmission service specified in individual
agreements.\613\ Moreover, the Commission found that section 201(b)(1)
gives the Commission jurisdiction over ``all facilities'' for the
transmission of electric energy, and this jurisdiction is not limited
to the use of those transmission facilities within a certain class of
transactions.\614\ As a result, the Commission stated that it has
jurisdiction over the use of these transmission facilities in the
provision of transmission service, which includes consideration of the
benefits that any beneficiaries derive from those transmission
facilities in electric service regardless of the specific contractual
relationship that the beneficiaries may have with the owner or operator
of these transmission facilities.\615\
---------------------------------------------------------------------------
\612\ Id. P 532.
\613\ Id.
\614\ Id.
\615\ Id.
---------------------------------------------------------------------------
527. The Commission also explained that neither section 205 nor
section 206 of the FPA state or imply that an agreement is a
precondition for any transmission charges.\616\ The Commission also
concluded that cost allocation cannot be limited to voluntary
arrangements because if it were the Commission could not address free
rider problems associated with new transmission investment, and it
could not ensure that rates, terms and conditions of jurisdictional
service are just and reasonable and not unduly discriminatory.\617\
---------------------------------------------------------------------------
\616\ Id. P 533.
\617\ Id. P 535.
---------------------------------------------------------------------------
528. In addition, the Commission explained that its approach is
consistent with the concept of cost causation, because a full cost
causation analysis may involve ``an extension of the chain of
causation'' \618\ beyond those causes captured in voluntary
arrangements. The Commission explained that in order to identify all
causes, it is necessary to some degree to begin with their effects,
i.e., the benefits that they engender and then work back to their
sources.\619\ The Commission noted that this point was acknowledged in
the Seventh Circuit's characterization of cost causation in Illinois
Commerce Commission.\620\ The Seventh Circuit stated that:
---------------------------------------------------------------------------
\618\ Id. P 536 (quoting KN Energy, 968 F.2d 1295 at 1302).
\619\ Id.
\620\ Id. P 537.
To the extent that a utility benefits from the costs of new
facilities, it may be said to have ``caused'' a part of those costs
to be incurred, as without the expectation of its contributions the
facilities might not have been built, or might have been
delayed.\621\
---------------------------------------------------------------------------
\621\ Id. (quoting Illinois Commerce Commission, 576 F.3d at 476
(emphasis supplied)).
[[Page 32267]]
---------------------------------------------------------------------------
The court fully recognized that, to identify causes of costs, one
must to some degree begin with benefits.\622\
---------------------------------------------------------------------------
\622\ Id.
---------------------------------------------------------------------------
529. Last, the Commission emphasized that its cost allocation
reforms are a component of its transmission planning reforms, which
require that, to be eligible for regional or interregional cost
allocation, a proposed new transmission facility first must be selected
in a regional transmission plan for purposes of cost allocation, which
depends on a full assessment by a broad range of regional stakeholders
of the benefits accruing from transmission facilities planned according
to the reformed transmission planning processes.
2. Requests for Rehearing or Clarification
a. Petitioners' Arguments That the FPA Requires a Contract Before Costs
Are Allocated
530. Several petitioners argue that the Commission does not have
the jurisdiction to require that beneficiaries of service provided by
specific transmission facilities bear the costs of those benefits
regardless of their contractual relationship with the owner of those
facilities.\623\ They contend that the Commission's requirement to
allocate costs without regard to whether there is a contract or service
provided is inconsistent with the FPA.\624\ For example, Ad Hoc
Coalition of Southeastern Utilities and Large Public Power Council
assert that the Commission has confused the FPA's expression of
jurisdiction in section 201 with the grant of substantive authority,
and that the Commission's interpretation of what section 201 allows
would make sections 205 and 206 superfluous. They also assert that the
Commission's view of section 201 would also render section 203
superfluous and allow the Commission to compel sales or purchases of
jurisdictional facilities when the public interest required it.
---------------------------------------------------------------------------
\623\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Coalition for Fair Transmission Policy; Large Public Power Council;
National Rural Electric Coops; New York ISO at 4 (citing Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 539); New York PSC; New York
Transmission Owners; Northern Tier Transmission Group at 5 (citing
Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002)
(stating that in the absence of statutory authority authorization
for its act, an agency's action is plainly contrary to law and
cannot stand)); Sacramento Municipal Utility District; Southern
Companies at 96-97 (citing Illinois Commerce Comm'n, 576 F.3d 470
(2009); Morgan Stanley Capital Group, Inc. v. Pub. Util. Dist. No. 1
of Snohomish County, Washington et al., 554 U.S. 527, 533 (2008);
Ottertail Power Co. v. United States, 410 U.S. 366, 374 (1973); In
re Permian Basin Area Rate Cases, 390 U.S. 747, 822 (1968); United
Gas Pipeline Co. v. Mobile Gas Service Corp., 350 U.S. 332, 343
(1956)); and Vermont Agencies at 6, 10 (citing Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 532).
\624\ See, e.g., Coalition for Fair Transmission Policy;
Southern Companies; National Rural Electric Coops; and Ad Hoc
Coalition of Southeastern Utilities.
---------------------------------------------------------------------------
531. National Rural Electric Coops state that a contractual
relationship is required as a basis for a jurisdictional rate or
charge. They maintain that in providing for Commission regulation of
rates ``for or in connection with the transmission or sale of electric
energy,'' the FPA ties the Commission's rate authority directly to the
jurisdictional service provided by those public utilities.\625\ They
argue that where an entity takes no jurisdictional service from a
public utility, the Commission cannot permit the public utility to
collect charges from that entity. Several other petitioners make
similar arguments.\626\ Large Public Power Council argues that the
natural implication of terms in section 205 and 206 such as ``made,''
``demanded,'' ``received,'' ``observed,'' ``charged,'' or ``collected''
is that they pertain to rates assessed to utility customers in
connection with an agreement to take service.\627\
---------------------------------------------------------------------------
\625\ National Rural Electric Coops at 14 (quoting 16 U.S.C.
824d(a)).
\626\ See, e.g., National Rural Electric Coops; New York ISO;
Northern Tier Transmission Group; Sacramento Municipal Utility
District; Southern Companies; and Vermont Agencies.
\627\ Large Public Power Council at 35.
---------------------------------------------------------------------------
532. Large Public Power Council argues that the approach taken in
Order No. 1000 to cost allocation for new transmission development is
at odds with the Commission's requirement that interstate gas pipeline
projects be self-sustaining and not be subsidized by existing services.
Large Public Power Council states that courts have held that the
Natural Gas Act and the FPA should be interpreted similarly, and the
Commission must explain substantial discrepancies.
533. Sacramento Municipal Utility District argues that if the rates
that the Commission regulates are for transmission service, it
logically follows that only customers who receive the transmission
service can be charged for it. Vermont Agencies contend that even if
the statute were ambiguous, it would still be unreasonable to allocate
costs on the beneficiary theory because it would not follow logically
from the Commission's acknowledgement that it only regulates the
provision of transmission service.
534. Sacramento Municipal Utility District argues that the
Commission never disputed its arguments that: (1) In theory, a utility
could build a facility and then claim that because it provided a
benefit to someone remote from the facility, that entity--customer or
not--should bear some of the costs; and (2) it cannot force unwilling
customers to pay for additional service.\628\ Sacramento Municipal
Utility District argues that Order No. 1000 allows ``beneficiaries'' of
new transmission facilities to be charged even if they are not getting
a new service.\629\
---------------------------------------------------------------------------
\628\ Sacramento Municipal Utility District at 9 (citing Exxon
Mobil Corp. v. FERC, 430 F.3d 1166, 1176-77 (D.C. Cir. 2005)).
\629\ Sacramento Municipal Utility District at 9 & n.4.
---------------------------------------------------------------------------
535. National Rural Electric Coops also argue that FPA sections 205
and 206 require that costs and benefits be fairly allocated between the
two parties providing and receiving jurisdictional service. They
contend that the fact that there may be third-party beneficiaries to an
agreement does not change the analysis. They state that, even though
other utilities may look more like transmission customers than entities
that benefit indirectly from increased transmission capacity and are
not subject to jurisdictional rates, this does not mean that those
utilities have greater legal or contractual obligations.
536. Coalition for Fair Transmission Policy argues that the
Commission is incorrect in finding that it has the legal authority to
authorize public utilities to charge third party beneficiaries for
transmission facilities because the issue has not been squarely
addressed by the courts.\630\ It asserts that the matter has not
merited analysis or discussion because it is an undisputed maxim that
lawful rates are founded on privity of contracts.
---------------------------------------------------------------------------
\630\ Coalition for Fair Transmission Policy at 20 (citing Order
No. 1000, FERC Stats. & Regs. ] 31,323 at P 540).
---------------------------------------------------------------------------
537. Several petitioners disagree that free rider problems are a
basis for the cost allocation requirements established in Order No.
1000.\631\ Southern Companies argue that under Order No. 1000, the mere
potential of free riders is absolute poison to the justness and
reasonableness of a cost allocation methodology. They contend that
Order No. 1000 does not explain who these free riders may be, what
benefits might be taken without compensation, or whether in the absence
of the new transmission, they would require and financially support
their own new transmission. Southern Companies add that Order No. 1000
does not explain why complaints under section 206 are
[[Page 32268]]
insufficient for resolving free rider problems.
---------------------------------------------------------------------------
\631\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Large Public Power Council; and National Rural Electric Coops.
---------------------------------------------------------------------------
538. Southern Companies also assert that the FPA does not allow the
allocation of costs to third-party non-customers because it does not
allow the Commission to regulate cost allocations or rate structures
that apply to the conveyance of abstract nonjurisdictional ``benefits''
other than electricity. Southern Companies assert that the FPA requires
that cost allocations and rate structures must apply to the conveyance
of benefits that are the actual use of transmission facilities or
services (or support services required to provide the same). They argue
that Mobil Oil Corp. v. FPC supports this conclusion.\632\ In that
case, the court found that the Commission exceeded its authority when
it required cost allocation and rate structures for certain
nonjurisdictional liquids as part of the transportation of natural
gas.\633\
---------------------------------------------------------------------------
\632\ 483 F.2d 1238 (D.C. Cir. 1973).
\633\ Southern Companies at 100-101 (citing Mobil Oil, 483 F.2d
1238, 1248; also Office of Consumers' Counsel v. FERC, 655 F.2d
1132, 1148 (D.C. Cir. 1980)).
---------------------------------------------------------------------------
539. Sacramento Municipal Utility District argues that the
Commission is incorrect in determining that it can require non-public
utilities participating in a regional planning organization to accept
an allocation of costs for new transmission facilities approved by the
regional entity as a condition of reciprocity, even if they have no
customer relationship with the transmission provider. It also states
that the Commission's longstanding position is that without evidence
that two systems are in fact acting as one, the Commission cannot
mandate the use of a single joint rate.\634\ Sacramento Municipal
Utility District argues that if the Commission cannot mandate the use
of joint rates, it cannot mandate that an entity pay the rates charged
by a utility with which it has no contractual or tariff-based customer/
provider relationship at all.
---------------------------------------------------------------------------
\634\ Sacramento Municipal Utility District at 15 (citing Ft.
Pierce Utils. Comm'n v. FERC, 730 F.2d 778 (D.C. Cir. 1984);
Richmond Power & Light v. FERC, 574 F.2d 610 (D.C. Cir. 1978);
Alabama Power Co. v. FERC, 993 F.2d 1557 (D.C. Cir. 1993); Illinois
Power Co., 95 FERC ] 61,183, at 61,144 (2002)).
---------------------------------------------------------------------------
540. Several petitioners argue that the courts have rejected
attempts to impose cost liability without a contract for Commission-
jurisdictional service.\635\ For example, Southern Companies and
Coalition for Fair Transmission Policy argue that the entire design of
the FPA is based on the premise that those who impose charges have a
service relationship with those on whom charges are levied.\636\ They
assert that this is supported by the Supreme Court's finding in Morgan
Stanley, where it stated that ``the regulatory system created by the
FPA is premised on contractual agreements voluntarily devised by the
regulated companies.'' \637\ Coalition for Fair Transmission Policy
states that in Otter Tail Power Co. v. United States, the Supreme Court
wrote that Congress had rejected a pervasive regulatory scheme for
transmission planning and cost allocation ``in favor of voluntarily
contractual relationships.'' \638\
---------------------------------------------------------------------------
\635\ See, e.g., Coalition for Fair Transmission Policy at 19-20
(citing Morgan Stanley Capital Group, Inc. v. Public Utility
District No. 1 of Snohomish County, Washington, 554 U.S. 527, 533
(2008)); Illinois Commerce Commission; National Rural Electric
Coops; New York PSC; Ad Hoc Coalition of Southeastern Utilities; and
Large Public Power Council.
\636\ Southern Companies at 97 (citing Morgan Stanley Capital
Group Inc. v. Pub. Util. Dist. No. 1 of Snohomish County,
Washington, 554 U.S. 527, 533 (2008); Otter Tail Power Co. v. United
States, 410 U.S. 366, 374 (1973); In re Permian Basin Area Rate
Cases, 390 U.S. 747, 822 (1968); United Gas Pipeline Co. v. Mobile
Gas Service Corp., 350 U.S. 332, 343 (1956)). See also Coalition for
Fair Transmission Policy at 20-21.
\637\ Southern Companies at 97-98 (quoting Morgan Stanley, 554
U.S. at 533 (2008) (citing and quoting with approval Permian Basin
Rate Cases, 390 U.S. at 822); also citing KN Energy, Inc. v. FERC,
968 F.2d 1295, 1300 (D.C. Cir. 1992) (``[I]t has been traditionally
required that all approved rates reflect to some degree the costs
actually caused by the customer who must pay them.'') (emphasis
added); Alabama Electric Cooperative, Inc. v. FERC, 684 F.2d 20, 27
(D.C. Cir. 1982) (``Properly designed rates should produce revenue
from each class of customers which match, as closely as practicable,
the costs to serve each class or individual customer.'') (emphasis
added)). See also Coalition for Fair Transmission Policy at 20-21;
New York PSC at 6.
\638\ Coalition for Fair Transmission Policy at 20-21 (quoting
Otter Tail Power Co. v. United States, 410 U.S. 366, 374 (1973)).
---------------------------------------------------------------------------
541. Ad Hoc Coalition of Southeastern Utilities also asserts that a
utility's ability to collect rates is a matter of its contractual
relationship with its customers, and the Commission's authority is
limited to reviewing rates and, if unlawful, to remedying them. It
asserts that this is apparent on the face of the FPA, and it has been a
fundamental building block of energy law since the Supreme Court
articulated the Mobile-Sierra doctrine.\639\ Ad Hoc Coalition of
Southeastern Utilities argues that the Mobile-Sierra doctrine makes it
clear that the Commission's oversight of utility rates is subordinate
to parties' contractual rights. It argues that the Commission errs in
its attempt to distinguish Mobile-Sierra on the ground that ``we are
dealing here with conditions under which costs can be recovered in
rates, not conditions under which contracts can be altered.'' \640\
Large Public Power Council makes similar arguments and also asserts
that while the Commission has the authority to alter the terms of a
contract for service under FPA section 206, subject to the ``public
interest'' standard, it cannot establish a right to recover costs where
no contractual authority exists.
---------------------------------------------------------------------------
\639\ Ad Hoc Coalition of Southeastern Utilities at 68 (citing
United Gas Pipe Line Co. v. Mobile Corp., 350 U.S. 332 (1955
(Mobile); FPC v. Sierra Pacific Co., 350 U.S. 348 (1956) (Sierra));
see also Northern Tier Transmission Group at 6.
\640\ Ad Hoc Coalition of Southeastern Utilities at 70 (quoting
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 540).
---------------------------------------------------------------------------
542. National Rural Electric Coops state that a central holding of
the Mobile-Sierra cases was that the Commission's authority to review
and modify jurisdictional rates does not confer new rights on the
public utilities subject to the Commission's jurisdiction. They argue
that Order No. 1000 is inconsistent with Mobile-Sierra in concluding
that costs may be allocated to entities in the absence of contractual
privity because neither section 205 nor section 206 of the FPA state or
imply that an agreement is a precondition for any transmission charges.
National Rural Electric Coops maintain that it is impermissible for the
Commission to infer authority to act based on the lack of an express
Congressional denial of such authority.\641\
---------------------------------------------------------------------------
\641\ National Rural Electric Coops at 16 (citing American
Petroleum Institute v. EPA, 52 F.3d 1113 (D.C. Cir. 1995); Mobil Oil
Corp. v. FPC, 483 F.2d 1238 (DC Cir. 1973)).
---------------------------------------------------------------------------
543. Several petitioners maintain that both court and Commission
precedent show that a section 205 filing requires a customer or other
contractual relationship between the filing utility and the
ratepayer.\642\ New York Transmission Owners assert that FPA section
205 does not authorize a utility to submit (and does not authorize the
Commission to accept) a rate filing where the utility lacks a
contractual or customer relationship with the entities to which the
rate will be charged. They state that an administrative agency cannot
exceed the authority granted to it by Congress and that the agency's
role is not to preempt Congressional action or to fill gaps where it
believes federal action is needed.\643\
---------------------------------------------------------------------------
\642\ New York ISO at 4 (citing In re Permian Basin Area Rate
Cases, 390 U.S. 747, 822 (1968)). See also New York ISO at 5-9
(citing Midwest Indep. Transmission Sys. Operator, Inc., 131 FERC ]
61,173 (2010) and Commonwealth Edison Co., 129 FERC ] 61,298 (2009),
order on reh'g, 132 FERC ] 61,268 (2010)); Ad Hoc Coalition of
Southeastern Utilities at 68-69 (citing 16 U.S.C. Sec. 824d(a));
and New York Transmission Owners at 4.
\643\ New York Transmission Owners at 5-6 (citing California
Indep. Sys. Operator Corp. v. FERC, 372 F.2d 395, 398 (D.C. Cir.
2004) and Office of Consumers' Counsel v. FERC, 655 F.2d 1132, 1152
(DC Cir. 1980)).
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[[Page 32269]]
544. Ad Hoc Coalition of Southeastern Utilities asserts that there
is no Commission or court case approving an allocation of costs outside
a contractual relationship. National Rural Electric Coops state that
the Commission cited Illinois Commerce Commission for the proposition
that to identify causes of costs, one must begin with benefits, but
this statement does not address cost allocation in the absence of
contractual privity when a non-customer is shown to benefit from a
particular transmission project. They maintain that the court in
Illinois Commerce Commission strongly suggested that costs must be
recovered from customers when it noted that rates must ``reflect to
some degree the costs actually caused by the customer who must pay
them.'' \644\ Southern Companies makes similar arguments. National
Rural Electric Coops argue that Commission forbid cost allocations to
non-customers when it refused to allow MISO to charge Green Mountain
Energy Company (Green Mountain) for Seams Elimination Charge/Cost
Adjustments/Assignment (SECA) costs under MISO's tariff because Green
Mountain did not directly contract with MISO for transmission service,
even though Green Mountain purportedly benefited from the transmission
service.\645\
---------------------------------------------------------------------------
\644\ National Rural Electric Coops at 20-21 (quoting Illinois
Commerce Commission, 576 F.3d 470, 476 (7th Cir. 2009) (emphasis
added by National Rural Electric Coops)).
\645\ National Rural Electric Coops at 18 (citing MISO, 131 FERC
] 61,173 (2010) (SECA Order)).
---------------------------------------------------------------------------
545. Vermont Agencies similarly argue that if the Commission is now
asserting authority to allocate costs to non-customers, it failed to
provide a reasonable basis for its change in course.\646\ They state
that AEP recognizes that utilities, in limited circumstances, can seek
protection when they are forced to transmit for others, but an entity
cannot build a transmission facility and then seek compensation for the
benefit it provides to an entity that did not ask for it. Sacramento
Municipal Utility District states that AEP provides no basis for
charging an entity that simply benefits in some way from the new line's
existence but has not caused loop flow through unscheduled deliveries.
---------------------------------------------------------------------------
\646\ Vermont Agencies at 14-15 (citing American Elec. Power
Co., 49 FERC ] 61,377, at 62,381 (1986) (AEP); Southern Cal. Edison
Co., 70 FERC ] 61,087 (1995); Midwest Indep. Transmission Sys.
Operator, Inc., 131 FERC ] 61,173, at P 421 (2010)).
---------------------------------------------------------------------------
546. Sacramento Municipal Utility District also reiterates its
argument that the Commission relied upon cases for authority to
allocate costs to non-customers that are inapt because they all
involved situations where a customer/provider relationship
existed.\647\ It states that the Commission dismissed this argument in
Order No. 1000 by stating that the issue was not before the court in
any of those cases. It argues that the Commission did not defend its
interpretation of these cases.\648\ Moreover, Sacramento Municipal
Utility District and Vermont Agencies assert that if the rationale for
charging non-customers rests on cases the Commission now concedes are
inapplicable, saying that those cases do not preclude it from
allocating costs to non-customers does not answer just what does
authorize the Commission to do so.
---------------------------------------------------------------------------
\647\ Sacramento Municipal Utility District at 10-11 (citing
Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ] 61,168,
P 60 (2004); see also Midwest Indep. Transmission Sys. Operator,
Inc., 113 FERC ] 61,194, P 1-4, 10 (2005); Midwest Indep.
Transmission Sys. Operator, Inc., 122 FERC ] 61,084, P22 (2008);
Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361 (D.C. Cir.
2004)).
\648\ Sacramento Municipal Utility District at 11 (citing
Tennessee Gas Transmission Co. v. FERC, 789 F.2d 61, 62-63 (D.C.
Cir. 1986)).
---------------------------------------------------------------------------
547. Sacramento Municipal Utility District also argues that the
Commission's policy on cost allocation in Order No. 1000 would do more
harm than good. For example, it contends that the risk of facing
charges as an incidental beneficiary of a facility that a party did not
want and will not use may discourage, rather than promote, regional
cooperation.
b. Arguments That Order No. 1000's Cost Allocation Reforms Are
Inconsistent With the Cost Causation Principle
548. Illinois Commerce Commission contends that the Commission
misinterpreted the cost causation principle and failed to recognize the
important distinction between cost causers and beneficiaries. It
maintains that the applicable court decisions do not support equating
cost causers and beneficiaries for purposes of cost allocation. It
argues that the cost causation principle associates beneficiaries with
cost causers only to the extent that the facilities might be delayed or
not built without the revenues expected from them. Illinois Commerce
Commission asserts that costs must be allocated primarily to such cost
causers. Allocations to any other beneficiaries must be substantiated
through an appropriate process.
549. Illinois Commerce Commission asserts that Illinois Commerce
Commission makes it clear that when a line is planned to address the
reliability concerns of one subregion of an RTO, there should be no
cost allocations to others when the benefits to them are trivial or
nonexistent.\649\
---------------------------------------------------------------------------
\649\ Illinois Commerce Commission contends that this is the
case with respect to the projects at issue on remand in the PJM
Interconnection, LLC matter in Docket No. EL06-121-006.
---------------------------------------------------------------------------
550. New York ISO states that transmission facilities may provide
some greater or lesser degree of ``benefit'' to a broad range of system
users, but showing that an entity receives some incidental benefit
(based on a standard that has not yet been articulated) does not prove
that the entity is receiving transmission service over that facility
and should be assessed costs.
c. Arguments That the Commission Did Not Show That Existing Rates Are
Unjust and Unreasonable
551. FirstEnergy Service Company and California ISO argue that the
FPA does not authorize the Commission to require the filing of new
rates without first finding that the existing rate is unjust,
unreasonable, or unduly discriminatory or preferential. FirstEnergy
Service Company maintains that the Commission concludes that the
absence of clear cost allocation rules can impede the development of
transmission facilities, which may adversely affect jurisdictional
rates.\650\ FirstEnergy Service Company argues that where no
methodologies exist, the Commission cannot fulfill the basic
requirement of section 206 that it find existing contracts or rates
unjust, unreasonable, or unduly discriminatory or preferential. It
maintains that section 206 applies to rates ``demanded, observed,
charged or collected,'' not to rates that might apply to a future
jurisdictional service.\651\ FirstEnergy Service Company asserts that,
if, on the other hand, there is an existing rate that applies to cost
allocation for regional and interregional transmission facilities, then
the Commission's conclusion that the absence of a rate is inapplicable,
and the Commission does not find any such existing rates unjust or
unreasonable. California ISO makes a similar argument. It also argues
that the Commission cannot use section 206 to promote goals such as
cost-effectiveness and transmission expansion, and rates are not unjust
and unreasonable simply because another rate might be more just and
reasonable.\652\ California ISO states that its tariff already includes
provisions that ensure the construction of needed
[[Page 32270]]
projects, and it takes cost-effectiveness into consideration when
choosing projects.
---------------------------------------------------------------------------
\650\ FirstEnergy Service Company at 14 (quoting Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 579).
\651\ FirstEnergy Service Company at 18.
\652\ California ISO at 18 (citing Duke Energy Trading and
Marketing, LLC, 315 F.3d 377, 382 (D.C. Cir. 2003)).
---------------------------------------------------------------------------
552. FirstEnergy Service Company also asserts that the courts have
admonished the Commission for seeking to impose new rates without first
determining that the existing rate is unjust, unreasonable, or unduly
discriminatory or preferential.\653\ It cites Public Service Commission
of New York v. FERC in which the court disagreed with the Commission
that it could act under section 4 of the NGA rather than section 5 in
finding that an existing zone allocation in the utility's rates was
unlawful and prescribing a new allocation because the utility had
proposed a rate increase under section 4 of the NGA.\654\ FirstEnergy
Service Company states that the court reversed the Commission's
decision because the Commission did not make a finding under section 5
of the NGA. FirstEnergy Service Company also cites other cases in which
it states that the court rejected Commission filing requirements as an
impermissible attempt to avoid the strictures of sections 4 and 5 of
the NGA.\655\
---------------------------------------------------------------------------
\653\ FirstEnergy Service Company at 16 (citing Western
Resources, Inc. v. FERC, 9 F.3d 1568, 1578 (D.C. Cir. 1993); Tenn.
Gas Pipeline Co. v. FERC, 860 F.2d 446 (D.C. Cir. 1988); Northern
Natural Gas Co. v. FERC, 827 F.2d 779 (D.C. Cir. 1987); Sea Robin
Pipeline Co. v. FERC, 795 F.2d 182 (D.C. Cir. 1986); ANR Pipeline
Co. v. FERC, 771 F.2d 507 (D.C. Cir. 1985); Panhandle E. Pipe Line
Co. v. FERC, 613 F.2d 1120 (D.C. Cir. 1980)).
\654\ FirstEnergy Service Company at 16-17 (citing Public
Service Commission of New York v. FERC, 642 F.2d 487 at 1344-45).
FirstEnergy Service Company states that although the Court was
describing the NGA, the FPA and NGA are interpreted in parallel. FPC
v. Sierra Pacific Power Co., 350 U.S. 348, at 353 (1956).
\655\ FirstEnergy Service Company at 17 (citing Public Service
Commission of New York v. FERC, 866 F.2d 487 (D.C. Cir. 1989) and
Consumers Energy Co. v. FERC, 226 F.3d 777 (6th Cir. 2000)).
---------------------------------------------------------------------------
553. FirstEnergy Service Company argues that the Supreme Court has
found that the right to file new rates and contracts belongs solely to
public utilities under the FPA.\656\ It disagrees with the Commission's
assertion that it is setting standards for filings under section 205
rather than interfering with public utilities' rights to file new
rates,\657\ it argues that Order No. 1000 directs transmission
providers to amend their tariffs to include cost allocation provisions
for regional and interregional facilities. FirstEnergy Service Company
contends that the Commission may issue guidelines that will be used to
determine whether future rates for regional and interregional
facilities will be just and reasonable, but section 205 does not permit
it to compel filings of rates or contracts.
---------------------------------------------------------------------------
\656\ FirstEnergy Service Company at 13 (quoting United Gas
Pipeline Co. v. Mobile Gas Ser. Co., 350 U.S. 332 at 341).
\657\ FirstEnergy Service Company at 18 (quoting Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 547).
---------------------------------------------------------------------------
554. Ad Hoc Coalition of Southeastern Utilities argues that the
Commission cannot support its determination by simply finding that
rates will be unjust and unreasonable without a cost allocation
mechanism. As support for this position, Ad Hoc Coalition of
Southeastern Utilities argues that the Commission's authority over
practices affecting rates under section 206 is limited to practices
that directly affect rates,\658\ and effectively requires utilities to
pay transmission developers for investments that the utilities do not
use indirectly affects rates for jurisdictional service. Large Public
Power Council makes similar arguments.
---------------------------------------------------------------------------
\658\ Ad Hoc Coalition of Southeastern Utilities at 73 (citing
California Independent System Operator v. FERC, 372 F.3d at 403).
---------------------------------------------------------------------------
3. Commission Determination
555. Many petitioners object to the Commission's cost allocation
reforms in Order No. 1000 based on what they consider to be fundamental
principles concerning both the Commission's jurisdiction as well as the
nature of transmission operations and the benefits they provide. Many
of the arguments raised by petitioners share common themes, and we thus
will address them collectively as far as possible. In order to do this
comprehensively, we think it is important first to state briefly what
the Commission did, and did not, require in Order No. 1000 with respect
to cost allocation and to address some of the basic principles that
inform those decisions.
556. The cost allocation reforms in Order No. 1000 are grounded in
our determination that it is necessary to establish a closer link
between regional transmission planning and cost allocation, both of
which involve the identification of beneficiaries of new transmission
facilities. Planning of new transmission facilities in a regional
transmission planning process involves assessing how such facilities
will affect the existing transmission grid and how they will benefit
users of the grid within the relevant region.\659\ Cost allocation for
new transmission facilities that are selected in a regional
transmission plan for purposes of cost allocation similarly involves
assigning the costs of those facilities in a manner that accounts for
the identified benefits. Recognizing this relationship, the Commission
found that the lack of clear ex ante cost allocation methods that
identify beneficiaries of proposed regional and interregional
transmission facilities may be impairing the ability of public utility
transmission providers to implement more efficient or cost-effective
transmission solutions identified during the transmission planning
process. The Commission also found that linking transmission planning
and cost allocation through the regional transmission planning process
would increase the likelihood that transmission facilities in regional
transmission plans are constructed.
---------------------------------------------------------------------------
\659\ Users of the regional transmission grid could be, for
example, public utility transmission providers that may effectively
rely on transmission facilities of another transmission provider in
order to provide transmission service, whether or not there is a
service agreement between those public utility transmission
providers.
---------------------------------------------------------------------------
557. This emphasis on a closer link between regional transmission
planning and cost allocation also informs the cost allocation
principles that the Commission adopted in Order No. 1000. The
Commission found that in light of the need for a closer link between
regional transmission planning and cost allocation, allowing one region
to allocate costs unilaterally to entities in another region would
impose too heavy a burden on stakeholders to actively monitor
transmission planning processes in numerous other regions, from which
they could be identified as beneficiaries and be subject to cost
allocation. The Commission also stated that if it expected such
participation, the resulting regional transmission planning processes
could amount to interconnectionwide transmission planning with
corresponding cost allocation. The Commission stated clearly that Order
No. 1000 does not require either interconnectionwide transmission
planning or interconnectionwide cost allocation. We reaffirm these
findings here, as discussed further below with respect to Cost
Allocation Principle 4.\660\
---------------------------------------------------------------------------
\660\ See discussion infra at section 0.
---------------------------------------------------------------------------
558. Against this backdrop, we note the actions that the Commission
took in Order No. 1000 with respect to cost allocation are based on its
jurisdiction under section 201(b)(1) of the FPA over the transmission
of electric energy in interstate commerce and the facilities for such
transmission and its duty to exercise it authority under sections 205
and 206 of the FPA to ensure that Commission-jurisdictional rates are
just and reasonable and not unduly discriminatory or preferential.\661\
The nature and scope of this authority must be viewed in the context of
the specific characteristics of transmission facilities
[[Page 32271]]
and their operation, among other considerations.\662\
---------------------------------------------------------------------------
\661\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 532,
535.
\662\ As discussed further below, the Commission finds that
there is a need to balance a number of factors to ensure that the
reforms adopted in Order No. 1000 achieve the goal of improved
planning and cost allocation for transmission in interstate
commerce. See discussion infra at section 0.
---------------------------------------------------------------------------
559. Transmission operations are characterized by a number of
unique features that are essential for understanding the Commission's
position, and therefore they merit summarizing here. Electric energy
does not travel on a preset path but rather along all available
pathways in accordance with the laws of physics.\663\ Continuous
fluctuations in the demand for power and in generation operations
affect power flows throughout the transmission grid. This means that
electric energy received by an individual customer at any one time
could be delivered over any number of transmission facilities that
constitute the transmission grid. Changes in demand for or supply of
electricity at any point in the system will change flows on all the
transmission lines to varying degrees, often in ways that are not
easily controlled.\664\
---------------------------------------------------------------------------
\663\ An interconnected AC transmission grid essentially
functions as a single piece of equipment. See, e.g., Tampa Electric
Co., 99 FERC ] 61,192, at 61,796 (2002).
\664\ See, e.g., Jack A. Casazza, Transmission Access and Retail
Wheeling: The Key Questions, in Electricity Transmission Pricing and
Technology 81 (Michael Einhorn and Riaz Siddiqi eds., 1996); Narain
G. Hingorani, Flexible AC Transmission System (Facts), in id. 242;
Karl Stahlkopf, The Second Silicon Revolution, in id. 263.
---------------------------------------------------------------------------
560. The courts have recognized this fundamental fact and have
acknowledged that it has important implications for the Commission's
regulation of transmission service. The DC Circuit has stated:
* * * In order to determine a utility's cost of providing a
transmission service, the Commission typically treats a transmission
network * * * as an integrated system. In other words, all of the
individual facilities used to transmit electricity are treated as if
they were part of a single machine. The Commission takes this
approach on the ground that a transmission system performs as a
whole; the availability of multiple paths for electricity to flow
from one point to another contributes to the reliability of the
system as a whole. This principle has a strong basis in the physics
of electrical transmission for there is no way to determine what
path electricity actually takes between two points or indeed whether
the electricity at the point of delivery was ever at the point of
origin.
As a corollary, in determining permissible prices for
transmission services, the Commission treats each transmission
customer not as using a single transmission path but rather as using
the entire transmission system.\665\
---------------------------------------------------------------------------
\665\ Northern States Power Co. v. FERC, 30 F.3d 177, 179 (DC
Cir. 1994) (emphasis supplied) (Northern States); see also Western
Massachusetts Electric Company v. FERC, 165 F.3d 922, 927 (DC Cir.
1999) (stating that ``[w]hen a system is integrated, any system
enhancements are presumed to benefit the entire system'').
In other words, in the case of transmission, there is only one
service--service over the entire grid.\666\
---------------------------------------------------------------------------
\666\ We note that this principle is not, in itself,
determinative of what would constitute a just and reasonable cost
allocation method. For example, a regional cost allocation method
must satisfy the principles set forth in Order No. 1000 and affirmed
here, including that the costs of transmission facilities must be
allocated to those within the transmission planning region that
benefit from those facilities in a manner that is roughly
commensurate with estimated benefits. See, e.g., Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 622.
---------------------------------------------------------------------------
561. The Commission appreciates that these prior decisions related
to transmission rates for a single public utility transmission
provider's facilities. However, the principle underlying those
decisions is equally applicable across larger regions of the
transmission system. Given the physics of power flows, and the
ownership of transmission facilities in the United States, the actual
transmission facilities that are affected by a particular transaction
are owned by multiple, interconnected transmission providers
irrespective of whether the transaction involves a single contract for
transmission service with one of the owners of the transmission
facilities or multiple contracts with all of the owners of the
transmission facilities along a contract path. That is, the
transmission grid constitutes a common infrastructure, ``a cohesive
network moving energy in bulk.'' \667\ Entities that contract for
service on the transmission grid cannot ``choose'' to affect only the
transmission facilities for which they have entered into a contract, as
some petitioners contend. Similarly, those entities cannot claim that
they are not using or benefiting from such transmission facilities
simply because they did not enter a contract to use them.
---------------------------------------------------------------------------
\667\ Public Serv. Co. of Colo., 62 FERC ] 61,013, at 61,061
(1993).
---------------------------------------------------------------------------
562. We also note that in an interconnected electric transmission
system, the enlargement of one path between two points can provide
greater system stability, lower line losses, reduce reactive power
needs, and improve the throughput capacity on other facilities. Given
the nature of transmission operations, it is possible that an entity
that uses part of the transmission grid will obtain benefits from
transmission facility enlargements and improvements in another part of
that grid regardless of whether they have a contract for service on
that part of the grid and regardless of whether they pay for those
benefits. This is the essence of the ``free rider'' problem the
Commission is seeking to address through its cost allocation
reforms.\668\ Any individual beneficiary of a new transmission facility
has an incentive to defer investment in the anticipation that other
beneficiaries in the region will value the project enough to fund its
development. This can lead to situations in which no developer moves
forward, adversely affecting development of transmission facilities
and, as a result, rates for jurisdictional services.
---------------------------------------------------------------------------
\668\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 534-35.
---------------------------------------------------------------------------
563. The Supreme Court has stated that the Commission's
jurisdiction is ``to follow the flow of electric energy, an engineering
and scientific, rather than a legalistic or governmental, test.'' \669\
Indeed, the Supreme Court described the entire FPA as ``couched largely
in the technical language of the electric art.'' \670\
---------------------------------------------------------------------------
\669\ Connecticut Light & Power Co. v. F.P.C., 324 U.S. 515, 529
(1945) (Connecticut Light & Power Co.).
\670\ Id.
---------------------------------------------------------------------------
564. Despite these considerations, many petitioners argue that the
costs of new transmission facilities can only be allocated within a
preexisting contractual relationship. These arguments are based on the
assumption that only preexisting contracts define jurisdictional
transmission service. In relying exclusively on contracts to perform
this role, petitioners are advocating a legalistic test for assessing
the scope of the Commission's jurisdiction that is inconsistent with
the Supreme Court's interpretation of the FPA in Connecticut Light &
Power Co. Contracts do not reflect the actual flow of electric energy
on the transmission grid. Nor do contracts define or limit the benefits
that an entity receives from its use of the transmission grid. To argue
that costs for new transmission facilities can be allocated only
through preexisting contractual relations means that some entities that
will benefit from those transmission facilities simply cannot be
allocated costs roughly commensurate with the benefits that they
receive. This is inconsistent with the well-established Commission and
judicial interpretation of the FPA and contrary to the requirement that
transmission rates be just and
[[Page 32272]]
reasonable and not unduly discriminatory or preferential.\671\
---------------------------------------------------------------------------
\671\ We also note that Order No. 1000 states: ``Neither section
205 nor section 206 of the FPA state or imply that an agreement is a
precondition for any transmission charges. These statutory
provisions speak of rates and charges that are `made,' `demanded,'
`received,' `observed,' `charged,' or `collected' by a public
utility.'' Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 533.
---------------------------------------------------------------------------
565. This explains why the cost allocation provisions of Order No.
1000, which seek to allocate costs to beneficiaries in a region roughly
commensurate with benefits they receive, are consistent with the
statement in Illinois Commerce Commission that ``[a]ll approved rates
[must] reflect to some degree the costs actually caused by the customer
who must pay them.'' \672\ Petitioners argue that because the court in
Illinois Commerce Commission used the word ``customer'' in the quote
above, it suggests that costs must be recovered from entities that have
a preexisting contractual relationship with the entity seeking the cost
allocation. However, given the nature of cost causation itself, some
entities that actually cause costs would not be required to pay them if
they could utilize the absence of a contractual relationship to shield
themselves from an allocation of costs. Rather than contractual
relationships, the benefits received by users of the regional
transmission grid provide a basis for how costs should be allocated.
Petitioners' argument would inappropriately revise the Illinois
Commerce Commission court's explanation that the cost causation
principle requires that ``all approved rates [must] reflect to some
degree the costs actually caused by the customer who must pay them'' by
adding a further requirement that the customer also agree to be
responsible for such costs. The court did not, however, reach such a
conclusion. We thus reject the claim by Ad Hoc Coalition of
Southeastern Utilities that the Commission's adherence to the cost
causation principle is subordinate to parties' contractual rights.
---------------------------------------------------------------------------
\672\ Illinois Commerce Commission, 576 F.3d 470 at 476
(internal citations omitted).
---------------------------------------------------------------------------
566. Moreover, our interpretation of the court's use of
``customer'' in Illinois Commerce Commission is consistent with the
statements that the court makes immediately thereafter. The court first
notes that compliance with the principle involved is evaluated `` `by
comparing the costs assessed against a party to the burdens imposed or
benefits drawn by that party.'' ' \673\ The court did not condition its
statement on a need for a preexisting contractual relationship. Rather,
the court allowed for a full comparison of costs for any party that
imposed burdens on, and benefited from enhancement of, the network
transmission grid. Furthermore, the court follows this by stating that
``[t]o the extent that a utility benefits from the costs of new
facilities, it may be said to have `caused' a part of those costs to be
incurred, as without the expectation of its contributions the
facilities might not have been built, or might have been delayed.''
\674\ That is precisely the role that the Commission's cost allocation
reforms play within the context of its planning reforms. That the lack
of ex ante cost allocation methods that identify the beneficiaries of
proposed regional and interregional transmission facilities may be
impairing the ability of public utility transmission providers to
implement more efficient or cost-effective transmission solutions
identified in the transmission planning process.\675\
---------------------------------------------------------------------------
\673\ Id. (internal citations omitted).
\674\ Id.
\675\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 499.
---------------------------------------------------------------------------
567. Some petitioners also argue that the Supreme Court's statement
in Morgan Stanley that ``the regulatory system created by the [FPA] is
premised on contractual agreements voluntarily devised by the regulated
companies'' \676\ means that a preexisting contractual relationship is
an essential precondition of cost allocation. Given the nature of
transmission grid operations, we disagree that this statement by the
Supreme Court means that contracts, which will not fully reflect how
transmission facilities are impacted by power flows, are the only
device that defines what rates are just and reasonable and not unduly
discriminatory or preferential. We do not read the importance that the
Supreme Court ascribes to voluntary contracts in Morgan Stanley to
imply that entities that use the transmission grid are entitled to
structure their contractual arrangements so that they are shielded from
paying costs that are roughly commensurate with the benefits that they
receive. In any event, Morgan Stanley never stated that, by refusing to
sign a contract, an entity benefiting from another's improvement of the
regional transmission grid can limit its obligation to something less
than an obligation to pay for all benefits that it receives.
---------------------------------------------------------------------------
\676\ Morgan Stanley, 554 U.S. at 533.
---------------------------------------------------------------------------
568. The obligation under the FPA to pay costs allocated under a
regional or interregional cost allocation method is imposed by a
Commission-approved tariff concerning the charges made by a public
utility transmission provider for the use of the public utility
transmission provider's facility. Such use is voluntary, and it does
not become less so because it is determined in part by immutable laws
of physics. Voluntary use therefore also entails voluntary acceptance
of the terms and conditions of use set forth in the tariff, including
an applicable cost allocation.
569. We disagree with National Rural Electric Coops' argument that
Order No. 1000 is conferring new rights on public utility transmission
providers. We are not conferring new rights on public utility
transmission providers when we seek to ensure that they can allocate
the costs of their new transmission facilities to the beneficiaries of
those facilities. Nor are we claiming a power based solely on the fact
that there is not an express withholding of such power, as National
Rule Electric Coops claim. We are acting under the provisions of
section 206 of the FPA applied in accordance with the reasoning that we
have set forth both here and in Order No. 1000.
570. In response to Large Public Power Council's argument that the
references in sections 205 and 206 to rates ``made,'' ``demanded,''
``received,'' ``observed,'' ``charged,'' or ``collected'' pertain to
rates assessed to utility customers in connection with an agreement to
take transmission service, we reiterate the Commission's finding in
Order No. 1000 that ``nothing in these sections precludes flows of
funds to public utility transmission providers through mechanisms other
than agreements between the service provider and the beneficiaries of
those transmission facilities.'' \677\ As explained in further detail
above, an entity that uses the transmission grid will necessarily use
transmission facilities owned by multiple owners, and the FPA permits a
public utility transmission provider to charge for the costs of using
its transmission facilities.
---------------------------------------------------------------------------
\677\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 533.
---------------------------------------------------------------------------
571. Contrary to the claim of National Rural Electric Coops, all
cost allocation contemplated by Order No. 1000 pertains to rates ``for
or in connection with the transmission * * * of electric energy.''
Order No. 1000 does not permit a public utility transmission provider
to collect charges other than in connection with the use of the
transmission grid. In suggesting that it does, National Rural Electric
Coops misconstrues the criteria for identifying the scope of
transmission usage. That scope is defined by the transmission grid
operations, not simply the terms of individual contracts, which can
diverge
[[Page 32273]]
from the underlying transmission grid operations. It is the purpose of
the cost allocation method or methods required by Order No. 1000 to
align cost responsibility with the reality of transmission grid
operations in the case of new transmission facilities selected in the
regional transmission plan for purposes of cost allocation.\678\
---------------------------------------------------------------------------
\678\ As explained above, providing for such cost allocation
will help to ensure that rates are just and reasonable and not
unduly discriminatory or preferential as required by section 205 of
the FPA. 16 U.S.C. 824d.
---------------------------------------------------------------------------
572. Moreover, contrary to Large Public Power Council's argument,
the cost allocation provisions of Order No. 1000 do not alter any
existing contract provisions governing the use of existing transmission
facilities and, therefore, are not inconsistent with Mobile-Sierra
doctrine regarding revision of contracts. Order No. 1000 requires each
public utility transmission provider to revise its OATT to include a
method, or set of methods, for allocating the costs of new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation--not transmission facilities already in service.
573. We reject the characterization of the cost allocation
requirements of Order No. 1000 as authorizing allocation of costs to
third-party beneficiaries. Order No. 1000 authorizes allocation of
costs to entities that benefit in their own right from new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. To the extent that an entity is not required to pay
for a benefit that it receives, it is a free rider not a third party
beneficiary. The fact that a free rider benefits from a transaction
between two other entities does not make it a third party beneficiary,
which is a legal concept that refers to parties that have a right to a
benefit under a contract between two other entities. Such rights are
not at issue here.
574. We thus also disagree with National Rural Electric Coops that
Order No. 1000 suggests that charges could be imposed on ``third party
beneficiaries'' such as ``[s]teel producers, crane operators, and wind
turbine manufacturers who may find more customers for their products
and services as a result of increased transmission capacity * * *.''
\679\ We note that Regional Cost Allocation Principle 1 provides that:
---------------------------------------------------------------------------
\679\ National Rural Electric Coops at 21.
In determining the beneficiaries of interregional transmission
facilities, transmission planning regions may consider benefits
including, but not limited to, those associated with maintaining
reliability and sharing reserves, production cost savings and
congestion relief, and meeting Public Policy Requirements.\680\
---------------------------------------------------------------------------
\680\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 622.
While this statement explicitly is not intended to be an exhaustive
recitation of possible benefits, our expectation is that additional
types of benefits would be ``in connection with'' transmission of
electric energy. We do not intend that these benefits should include
such things as increased sales of goods and services used in the
construction of new transmission facilities.
575. Likewise, in response to Southern Companies, Order No. 1000
does not authorize cost allocations or rate structures that apply to
conveyance of ``benefits [that] are not the actual use of transmission
facilities or services (or support services required to provide
same).'' \681\ We see no inconsistency between the cost allocation
provisions of Order No. 1000 and Mobil Oil Corp. v. FPC, as Southern
Companies claim. In that case, the court held that the Commission had
jurisdiction over rates for the transportation of natural gas on an
interstate pipeline but not over rates for the transportation of
certain non-jurisdictional liquid hydrocarbons that were also
transported on the pipeline. The court held that the Natural Gas Act
restricted the Commission's jurisdiction to rates for natural gas
transportation.\682\ Southern Companies maintains that Order No. 1000
authorizes rates for non-jurisdictional benefits that are analogous to
the non-jurisdictional liquid hydrocarbons in Mobil Oil Corp. v. FPC.
However, Order No. 1000 does not do this. It authorizes cost allocation
for benefits consistent with Regional Cost Allocation Principle 1,
which explicitly refers to matters that are subject to Commission
jurisdiction. For the same reasons, we disagree with the claim of
Vermont Agencies that Order No. 1000 authorizes allocation of costs to
persons that benefit in some way from the existence of a transmission
facility even if they use no transmission service at all.
---------------------------------------------------------------------------
\681\ Southern Companies at 99.
\682\ Mobil Oil Corp. v. FPC, 483 F.2d 1238, 1246-47 (D.C Cir.
1973).
---------------------------------------------------------------------------
576. In response to Southern Companies regarding free riders, we
note that free riders for purposes of Order No. 1000 are entities who
do not bear cost responsibility for benefits that they receive in their
use of the transmission grid, specifically benefits they receive from
new transmission facilities selected in a regional transmission plan
for purposes of cost allocation. Such benefits include the traditional
benefits that transmission facilities can provide, such as lowered
congestion, increased reliability, and access to generation resources.
Southern Companies state that the Commission does not address whether
such entities would pursue or support new transmission facilities in
the absence of a transmission project that is entitled to cost
allocation, but this overlooks the purpose of the cost allocation
requirements of Order No. 1000. They are intended to promote regional
and interregional transmission planning that facilitates more efficient
or cost-effective transmission infrastructure development. The lack of
ex ante cost allocation methods that identify the beneficiaries of
proposed regional and interregional transmission facilities may be
impairing the ability of public utility transmission providers to
implement more efficient or cost-effective transmission solutions
identified in the transmission planning process. For this reason,
individual complaints under section 206 of the FPA would not suffice to
overcome the free rider problem because litigating complaints burdens
and unduly delays the transmission planning process. Individual
complaint procedures thus do not permit effective transmission
planning.
577. The Commission has not confused the FPA's expression of
jurisdiction in section 201 with a grant of substantive authority. Ad
Hoc Coalition of Southeastern Utilities and Large Public Power Council
argue that according to the Commission's rationale, its jurisdiction
under section 201 over transmission service and transmission facilities
would also cover the matters for which specific authority is granted in
sections 205 and 206, as well as section 203, thereby rendering those
sections superfluous. As the Commission found in Order No. 1000,
section 201 simply sets forth the facilities and transactions in
interstate commerce that are subject to the Commission's jurisdiction
under Part II of the FPA. Our authority to act in Order No. 1000 on
matters subject to our jurisdiction arises under section 206 of the
FPA, specifically our authority to establish requirements regarding
transmission planning and cost allocation which are practices affecting
rates. The Commission's jurisdiction permits that authority to be
applied in a way that follows ``the flow of electric energy, an
engineering and scientific, rather than a legalistic or governmental,
test,'' \683\ and Order No. 1000's
[[Page 32274]]
application of the principle of cost causation is a reasonable exercise
of that authority. However, such action is not based directly on
section 201. It is based on section 206, which we apply to matters that
are within the scope of our jurisdiction set forth in section 201.
Moreover, we disagree with those petitioners that argue that our
interpretation of section 201 in Order No. 1000 could render either
section 203, section 205, or section 206 of the FPA superfluous,
because as we explain above, section 201 sets forth the subject matter
over which the Commission exercises its jurisdiction pursuant to those
other sections.
---------------------------------------------------------------------------
\683\ Connecticut Light & Power Co., 324 U.S. at 529.
---------------------------------------------------------------------------
578. Contrary to Large Public Power Council's contention, the cost
allocation requirements of Order No. 1000 are not at odds with the
Commission's policy on interstate gas pipeline development regarding
subsidization of development by existing shippers. The requirements of
Order No. 1000 are based on the principle of cost causation, which
requires that costs be allocated in a way that is roughly commensurate
with benefits. The principle of cost causation is intended to prevent
subsidization by ensuring that costs and benefits correspond to each
other. Indeed, in seeking to eliminate free riders on the transmission
grid, Order No. 1000 seeks to eliminate a form of subsidization, as
free riders by definition are entities who are being subsidized by
those who pay the costs of the benefits that free riders receive for
nothing.
579. We disagree with Sacramento Municipal Utility District's
assertion that Order No. 1000 fails to prevent a utility from building
a transmission facility and then simply claiming that a remote entity
receives benefits from it and thus must bear some of the costs. Under
Order No. 1000, for a regional cost allocation method to apply to a new
regional or interregional transmission facility, the transmission
facility must first be selected in a regional transmission plan or
plans for purposes of cost allocation. This means that the public
utility transmission providers in a region, in consultation with
stakeholders, have evaluated a given facility and determined that it
provides benefits that merit cost allocation under a regional method.
As such, a developer of a transmission facility will not be entitled to
recover costs from other entities without its facility being subject to
the requirements of the regional transmission planning process,
including the selection of its facility in the regional transmission
plan for purposes of cost allocation.
580. We also disagree with Sacramento Municipal Utility District
that Order No. 1000 forces unwilling customers to pay for additional
transmission service or to be charged even if they are not getting a
new transmission service. Order No. 1000 requires that new costs be
allocated in a way that is roughly commensurate with the benefits
derived from the new transmission facilities that are eligible for cost
allocation in accordance with Order No. 1000. As discussed above,
entities that receive benefits from these facilities in the course of
their use of the transmission grid cannot be characterized as
``unwilling customers.'' New York ISO notes that benefits come in
various degrees, and it maintains that entities should not be charged
for an ``incidental benefit.'' But again, Order No. 1000 requires that
costs be allocated in a way that is roughly commensurate with benefits,
and the court stated in Illinois Commerce Commission that entities
cannot be allocated costs for benefits that are trivial in relation to
those costs.\684\ All cost allocation methods will be subject to
Commission review and approval, and issues related to the
appropriateness of a particular method or methods can be raised at that
time.
---------------------------------------------------------------------------
\684\ Illinois Commerce Commission, 576 F.3d at 476.
---------------------------------------------------------------------------
581. Sacramento Municipal Utility District's argument that joint
rates are necessary for cost recovery in the case of a regional cost
allocation under Order No. 1000, describes a false dilemma. It argues
that without evidence that two systems are in fact acting as one, the
Commission cannot mandate the use of a single joint rate, and if it
cannot mandate the use of joint rates, it cannot mandate that an entity
pay the rates charged by a utility with which it has no contractual or
tariff-based customer/provider relationship. However, our position
regarding the role of preexisting contractual relationships goes to the
problem of cost allocation, not cost recovery, which Sacramento
Municipal Utility District focuses on when it speaks of the payment of
charges and which Order No. 1000 does not address.\685\ Moreover, Order
No. 1000 requires that the tariffs of transmission providers in a
region contain the regional cost allocation method or methods, which
means that in any event, there will be a tariff basis for implementing
a cost allocation. We thus reject the claim that a regional cost
allocation could be implemented only through a joint rate.
---------------------------------------------------------------------------
\685\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 563.
---------------------------------------------------------------------------
582. Turning to arguments that Order No. 1000 represents a change
in policy expressed in prior cases, we disagree with National Rural
Electric Coops' contention that the cost allocation provisions of Order
No. 1000 are contradicted by the Commission's refusal to allow MISO to
charge Green Mountain for SECA costs under MISO's tariff because Green
Mountain did not directly contract with MISO for transmission service.
In the SECA Order, the Commission found merely that Green Mountain's
affiliate BP Energy, not Green Mountain, was responsible for paying the
SECA charges because the contract between the affiliate and Green
Mountain stipulated that BP Energy was responsible for paying MISO for
network transmission service.\686\ The Commission found that since SECA
charges were intended to be surcharges assessed to the transmission
customer taking transmission service, and BP Energy, not Green
Mountain, was taking transmission service from MISO, BP Energy was
responsible for paying the SECA charges.\687\ The Commission emphasized
on rehearing of the SECA Order that MISO's tariff specifically provided
for its transmission customers to pay SECA charges, and therefore the
fact that BP Energy was the transmission customer, not Green Mountain,
was pivotal to the Commission's conclusion that BP Energy was
responsible for the SECA charges.\688\ This conclusion was based on a
reading of the requirements of the MISO tariff, and as such, it cannot
be read as establishing general principles regarding the authority of a
public utility transmission provider to collect charges for the
transmission of electric energy, as National Rural Electric Coops
argue.
---------------------------------------------------------------------------
\686\ SECA Order, 131 FERC ] 61,173 at P 422.
\687\ Id. P 423.
\688\ 136 FERC ] 61,244 at P 205.
---------------------------------------------------------------------------
583. Vermont Agencies and Sacramento Municipal Utility District
argue that the cost allocation reforms of Order No. 1000 represent a
change in policy from the position that the Commission took in AEP, and
they maintain that the Commission has failed to explain this change in
policy. AEP dealt with unintended loop flows on existing facilities,
which the Commission viewed as an operational issue that ``in the first
instance'' was to be dealt with by ``the interconnected parties''
establishing ``mutually acceptable operating practices.'' \689\ The
Commission also stated that if the party complaining of unintended loop
flows on its facilities could show that they created ``a burden on its
system, [it] can file a transmission service rate for
[[Page 32275]]
Commission consideration which would account for any unauthorized loop
flows.'' \690\ Vermont Agencies and Sacramento Municipal Utility
District describe Order No. 1000 as containing a policy change on this
point because in their view, the Commission maintains in Order No. 1000
that ``it could allocate the costs of new transmission facilities to
entities that somehow benefit from their existence--whether or not they
take service from the utility,'' whereas AEP ``addresses the issue of
compensation where the utility is involuntarily forced to provide
service.'' \691\ However, we see no fundamental difference between AEP
and Order No. 1000 precisely because individual owners of facilities on
an interconnected grid ``can file a transmission service rate for
Commission consideration'' under AEP. Additionally, it is because such
owners will often forgo grid enlargements that benefit many owners of
other facilities who will not pay for these enlargements that Order No.
1000 seeks to ensure that the former may be compensated through a cost
allocation to the latter.
---------------------------------------------------------------------------
\689\ AEP, 49 FERC ] 61,377, at 62,381.
\690\ Id.
\691\ Vermont Agencies at 16; Sacramento Municipal Utility
District at 14.
---------------------------------------------------------------------------
584. We also disagree with Vermont Agencies and Sacramento
Municipal Utility District that Order No. 1000 represents a change in
policy because the Commission has ``rejected assessment of charges'' in
situations such as that presented in AEP.\692\ The Commission did not
reject an assessment of charges in AEP. It stated that the operational
issue in question was in the first instance to be dealt with through
mutually acceptable operating practices, but a rate filing would be
appropriate if the loop flows created a burden on the system. Moreover,
Order No. 1000 does not deal with operating problems on existing
transmission facilities but rather solely with benefits to be derived
from new transmission facilities that regional participants themselves
select as having broad regional benefits, and it deals with cost
allocation for such new facilities as integral to transmission
planning. In this respect, Order No. 1000 does not express a change a
policy position taken in AEP because AEP does not deal with planning
and cost allocation for new transmission facilities and expresses no
policy with regard to these matters.
---------------------------------------------------------------------------
\692\ Vermont Agencies at 16-17; Sacramento Municipal Utility
District at 14.
---------------------------------------------------------------------------
585. In response to Illinois Commerce Commission's argument that
beneficiaries are to be associated with cost causers only to the extent
that transmission facilities might be delayed or not built without the
revenues expected from them, we note that it is for this reason that
the cost allocation requirements of Order No. 1000 are necessary. By
allocating costs in a way that is roughly commensurate with benefits,
the requirements help to ensure that more efficient and cost-effective
transmission solutions are implemented and that this occurs without
undue delay. In addition, one of the purposes of the regional
transmission planning process is to identify the beneficiaries of a
proposed transmission facility. This addresses Illinois Commerce
Commission's concern about the substantiation of benefits through an
appropriate process.
586. We also disagree with Sacramento Municipal Utility District
that the Commission's position on cost allocation is likely to do more
harm than good by discouraging regional cooperation. On the contrary,
Order No. 1000 is intended to encourage the development of more
efficient and cost-effective transmission solutions to regional
transmission needs, which will promote considerable economic benefits
in the form of lower congestion, greater reliability, and greater
access to generation resources. Therefore, we do not believe that the
Commission's reforms will discourage cooperation when the potential
gains from cooperation are so great.
587. Finally, several petitioners also argue that the Commission
must first find an existing rate to be unjust, unreasonable or unduly
discriminatory or preferential before it can take the actions regarding
cost allocation that it took in Order No. 1000. We disagree that such a
finding must be made case-by-case rather than generically. As explained
above,\693\ 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.\694\ Nor do we agree with FirstEnergy Service Company that
Commission actions taken in a rulemaking cannot apply to future
jurisdictional transmission service. Commission rulemakings are
prospective in their effect, and when the Commission proceeds by rule
it can conclude that ``any tariff violating the rule would have such
adverse effects * * * as to render it `unjust and unreasonable' ''
within the meaning of section 206 of the FPA.\695\ The effects that a
tariff would have include effects on future jurisdictional transmission
service.
---------------------------------------------------------------------------
\693\ See discussion supra at section 0.
\694\ Associated Gas Distributors v. FERC, 824 F.2d at 1008.
\695\ Id. (emphasis in original).
---------------------------------------------------------------------------
588. We further disagree with FirstEnergy Service Company's
assertion that where no cost allocation method or methods exist, the
Commission cannot use section 206 as a basis for requiring them. The
basis for the Commission's reforms in Order No. 1000 is that
transmission planning for transmission service and the associated
allocation of costs for new transmission facilities are practices that
affect rates for purposes of section 206.\696\ The Commission also
explained that the allocation of transmission costs is often
contentious and prone to litigation,\697\ and that the lack of ex ante
cost allocation methods that identify the beneficiaries of proposed
regional and interregional transmission facilities may be impairing the
ability of public utility transmission providers to implement more
efficient or cost-effective transmission solutions identified in the
transmission planning process.\698\ The absence of a cost allocation
method or methods also has an adverse effect on rates by making it
difficult to deal with free rider problems related to new facilities.
The Commission's authority to require the adoption of a cost allocation
method or methods arises directly from its authority under section 206
to ensure that practices that affect transmission rates, such as
transmission planning, are just and reasonable and not unduly
discriminatory or preferential.
---------------------------------------------------------------------------
\696\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 58.
\697\ Id. P 498.
\698\ Id. P 499.
---------------------------------------------------------------------------
589. FirstEnergy Service Company's argument that section 205 does
not permit the Commission to require the filing of rates or contracts
is equally flawed. Here, FirstEnergy Service Company is simply arguing
that all rates are initially to be proposed by public utility
transmission providers. However, the Commission is not requiring the
proposal of a particular rate. It is requiring that public utility
transmission providers have a cost allocation method or methods in
their OATTs to ensure that the costs of new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation are properly allocated to beneficiaries. It is for public
utility transmission providers to propose an actual method or methods.
The Commission is simply requiring that any cost allocation method or
methods that are proposed meet certain general
[[Page 32276]]
principles established in Order No. 1000.
590. The case law cited by FirstEnergy Service Company to support
the proposition that the Commission cannot impose a new rate without
first determining that an existing rate is unjust, unreasonable, or
unduly discriminatory or preferential reinforces our above points. All
the cases that FirstEnergy Service Company cites in this connection
involve situations in which the court found that the Commission had
moved beyond rejecting a proposed rate to the task of redesigning
it.\699\ The Commission is not here ``imposing'' any rates, as it is
not specifying, designing, or redesigning any rates. Instead it is
requiring that all public utility transmission providers have a cost
allocation method or methods for certain new transmission facilities
that comply with a broad set of general principles.
---------------------------------------------------------------------------
\699\ See, e.g., Western Resources, Inc. v. FERC, 9 F.3d 1568,
1578-79 (D.C. Cir. 1993).
---------------------------------------------------------------------------
591. We agree with California ISO that rates are not unjust and
unreasonable simply because another rate might be more just and
reasonable. However, this point applies in a situation where the status
quo has been found to be just and reasonable and not unduly
discriminatory or preferential, which is not the case here. California
ISO argues that in its case such a finding is necessary because it has
voluntarily included in its tariff provisions that ensure the
construction of needed transmission projects, and it takes into account
cost-effectiveness in choosing these transmission projects. This
argument misconstrues the Commission's actions here, which are to
ensure that certain minimum requirements pertaining to transmission
planning and cost allocation are in place. California ISO's practices
may already satisfy some of these requirements, in which case it need
only explain how it satisfies them in its compliance filing.\700\ This,
however, does not show that there is no need for such requirements.
---------------------------------------------------------------------------
\700\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 565,
583.
---------------------------------------------------------------------------
592. Ad Hoc Coalition of Southeastern Utilities questions the
Commission's ability to require a cost allocation method or methods on
the grounds that section 206 limits the Commission's authority over
practices affecting rates to those that directly affect rates. Cost
allocation is a practice that affects rates because the effect of a
cost allocation method or methods is quite direct, as it determines who
is responsible for specific costs. As explained above, Order No. 1000
found that the lack of a regional cost allocation method known in
advance to transmission planners and the existence of free riders,
result in inefficient transmission planning that impedes the
development of more efficient and cost effective new transmission
facilities, with the result that jurisdictional rates are higher than
they would otherwise be. As we have noted previously, we disagree with
Ad Hoc Coalition of Southeastern Utilities' contention that requiring
utilities to pay for facilities that they do not use does not directly
affect rates for jurisdictional transmission service and is therefore
beyond the Commission's authority. This argument ignores the reality
that any entity connected to the transmission grid may benefit from a
transmission facility whether or not it is connected to, or
specifically requests service from, a particular transmission facility
for which costs have been allocated.\701\ Order No. 1000's cost
allocation reforms are therefore intended to ensure that all of these
beneficiaries are allocated costs roughly commensurate with the
benefits they receive in their use of the transmission grid, and we
believe that such a requirement can be seen as directly affecting the
rates for jurisdictional transmission service.
---------------------------------------------------------------------------
\701\ Id. P 625.
---------------------------------------------------------------------------
B. Cost Allocation Method for Regional Transmission Facilities
1. Final Rule
593. In Order No. 1000, the Commission required that each public
utility transmission provider have in place a method, or set of
methods, for allocating the costs of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation.\702\ The Commission stated that if the public utility
transmission provider is an RTO or ISO, then the cost allocation method
or methods must be set forth in the RTO or ISO OATT.\703\ In a non-RTO/
ISO transmission planning region, the Commission required each public
utility transmission provider located within the region to set forth in
its OATT the same language regarding the cost allocation method or
methods used in its transmission planning region.\704\ In either
instance, the Commission required that such cost allocation method or
methods be consistent with the regional cost allocation principles
adopted in Order No. 1000.\705\
---------------------------------------------------------------------------
\702\ Id. P 558.
\703\ Id.
\704\ Id.
\705\ Id.
---------------------------------------------------------------------------
594. The Commission did not specify how the costs of an individual
regional transmission facility should be allocated.\706\ It noted,
however, that while each transmission planning region may develop a
method or methods for different types of transmission projects, each
such method or methods should apply to all transmission facilities of
the type in question and would have to be determined in advance for
each type of facility.\707\ Additionally, the Commission acknowledged
that cost containment is important, but declined to establish a
corresponding cost allocation principle, primarily because cost
containment concerns the level of costs, not how costs should be
allocated among beneficiaries.\708\
---------------------------------------------------------------------------
\706\ Id. P 560.
\707\ Id.
\708\ Id. P 704.
---------------------------------------------------------------------------
595. With respect to cost allocation for a proposed transmission
facility located entirely within one public utility transmission
owner's service territory, the Commission found that a public utility
transmission owner may not unilaterally apply the regional cost
allocation method or methods developed pursuant to Order No. 1000.\709\
However, the Commission also found that a proposed transmission
facility located entirely within a public utility transmission owner's
service territory could be determined by the public utility
transmission providers in the region to provide benefits to others in
the region and thus be selected in the regional transmission plan for
purposes of cost allocation; then the cost of that transmission
facility would be allocated according to that region's regional cost
allocation method or methods.\710\
---------------------------------------------------------------------------
\709\ Id. P 564.
\710\ Id.
---------------------------------------------------------------------------
596. In Order No. 1000, the Commission also declined to make new
findings with respect to pancaked rates, stating that it was beyond the
scope of the proceeding.\711\ The Commission further stated that it was
not making any modifications to the Commission's pancaked rate
provisions for an RTO under Order No. 2000.\712\ However, the
Commission noted that if rate pancaking was an issue in a particular
transmission planning region, stakeholders could raise their concerns
in the consultations leading to the compliance proceedings for Order
No. 1000 or make a separate filing with the Commission under section
205 or 206 of the FPA, as appropriate.\713\
---------------------------------------------------------------------------
\711\ Id. P 764.
\712\ Id.
\713\ Id.
---------------------------------------------------------------------------
[[Page 32277]]
2. Requests for Rehearing and Clarification
597. North Carolina Agencies argue that the Commission's planning
and cost allocation reforms represent major changes that have the
potential to preempt state authority over bundled retail rates. They
state that to date, the Commission has declined to exercise its
authority over the transmission component of bundled retail rates and
service despite pressure to do so and the U.S. Supreme Court's decision
in New York v. FERC.\714\ North Carolina Agencies assert that the
Commission must recognize that the applicability of any cost allocation
methods that result from Order No. 1000 is limited to unbundled
transmission and cannot impinge on state jurisdiction with respect to
bundled retail rates. Ad Hoc Coalition of Southeastern Utilities
likewise contends that the allocation of the cost of regional
transmission facilities to entities performing a retail sales function
would preempt state commissions in setting bundled retail rates because
under the Supremacy Clause, utilities will be entitled to recover their
costs in retail rates.
---------------------------------------------------------------------------
\714\ North Carolina Agencies at 4 (citing 535 U.S. 1 (2002)).
North Carolina Agencies state that while New York v. FERC includes
dicta suggesting that the Commission's authority is an open issue,
the Court found that the jurisdictional issue is a difficult one.
North Carolina Agencies at 5.
---------------------------------------------------------------------------
598. Northern Tier Transmission Group also states that the
Commission should clarify that it does not intend to set retail rates.
It states that the Commission has not explained the relationship
between the mandatory cost allocation process and the ability of a
project proponent to recover the costs of a selected transmission
facility.
599. In a related argument, Alabama PSC argues that Order No. 1000
fails to satisfy the requirements of the Administrative Procedure Act
(APA) \715\ because it lacks definiteness on how cost allocation will
translate into recovery. It is concerned that the rule will result in
stranded costs if a transmission provider cannot recover allocated
costs because of the absence of an appropriate contractual vehicle and
lead to cost shifting to others within the region. Alabama PSC also
asserts that Commission is being inconsistent when it does not address
cost recovery but then does not accept participant funding, which
Alabama PSC describes as a form of cost recovery, as a regional cost
allocation method. Southern Companies argue that if there is no payment
obligation coinciding with a cost assignment, industry cannot presume
that Order No. 1000's objective is to create a rate structure to induce
transmission developers to participate more fully in regional
transmission planning processes. They state that the Commission should
address this issue in order to prevent parties from engaging in a
futile exercise over the next eighteen months.
---------------------------------------------------------------------------
\715\ Administrative Procedure Act, 5 U.S.C. 706(2)(A).
---------------------------------------------------------------------------
600. Several other petitioners also take issue with the
Commission's determination to not address cost recovery issues in Order
No. 1000. Sacramento Municipal Utility District argues that the issue
with respect to cost recovery mechanisms is not the identity of the
transmission provider, but whether the party being assessed charges is
one of the provider's customers. It maintains that ``it is not a mere
concern over form'' to expect an explanation of the mechanism for
recovering a rate when the party being charged is not a customer.
601. Edison Electric Institute, NV Energy and Southern Companies
argue that the Commission does not explain how costs can be allocated
under a regional transmission plan in a non-RTO/ISO region without a
contractual mechanism permitting the charging and collection of such
costs. Edison Electric Institute acknowledges that a tariff could
provide a contractual mechanism for the collection of allocated costs,
but states that Order No. 1000 does not identify any mechanism for
requiring the payment of costs in the absence of such an applicable
tariff or agreement. Edison Electric Institute thus asserts that the
Commission is not engaging in reasoned decision making when it
concludes that it ``would permit recovery of costs from a beneficiary
in the absence of a voluntary arrangement.'' \716\
---------------------------------------------------------------------------
\716\ Edison Electric Institute at 7-8.
---------------------------------------------------------------------------
602. In the alternative, Edison Electric Institute argues that the
Commission should clarify: (1) Whether allocation in a regional plan of
costs to a beneficiary in a non-RTO/ISO region without a voluntary
arrangement to pay creates an obligation of the beneficiary to pay
those costs; and (2) if so, the mechanism for collecting such costs,
including the source of the obligation of the beneficiary to pay.
Southern Companies make a similar argument.
603. National Rural Electric Coops argue that the distinction
between cost allocation and cost recovery in Order No. 1000 has no
practical significance. NARUC argues that if cost allocation is
distinct from cost recovery, it is not clear that the Commission's
authority to set rates for transmission under the FPA provides the
Commission with jurisdiction over cost allocation.
604. Northern Tier Transmission Group requests that the Commission
clarify the relationship between cost allocation and cost recovery. It
states that the ability to recover costs appears to be merely a factor
that can be considered and acknowledged in the cost allocation process.
Northern Tier Transmission Group asserts that this issue is material to
the decision to participate in the construction of a project. Therefore
a clarification of the intended relationship between cost allocation
and cost recovery will better inform the methods developed for and the
analysis performed by the regional and interregional transmission
planning processes.
605. Northern Tier Transmission Group also asserts that the
Commission has no authority under the FPA to require the imposition of
transmission construction costs on non-jurisdictional beneficiaries or
to impose cost recovery on the United States or any state including any
political subdivision.\717\ Edison Electric Institute states that
paragraph 629 of Order No. 1000 states that non-jurisdictional
transmission providers that do not participate in the regional planning
process are not responsible for costs allocated in that process. It
states that it is arbitrary and capricious to treat jurisdictional
transmission providers and non-public utility transmission providers
differently with respect to any obligation they may have, in the
absence of a voluntary agreement, to pay costs allocated to them in a
regional planning process.
---------------------------------------------------------------------------
\717\ Northern Tier Transmission Group at 6 (citing 16 U.S.C.
824(e) and (f); Bonneville Power Admin. v. FERC, 422 F.3d 908 (9th
Cir. 2005)).
---------------------------------------------------------------------------
606. Arizona Cooperative and Southwest Transmission argue that
paragraph 629 in Order No. 1000 suggests that a non-public utility will
be forced to accept the regional cost allocation, and may effectively
forfeit its right to avoid an unduly discriminatory cost assignment if
participating in the process means that it loses the ability to
exercise its right to seek relief from the Commission. Arizona
Cooperative and Southwest Transmission argue that non-participation is
not a desirable answer to this problem, especially as an entity that
does not participate could still get saddled with costs and would also
forego the opportunity to have its own contributions to a more robust
grid included in the regional plan.
607. Alabama PSC argues that if the regional planning process
supersedes or replaces the output of a state integrated
[[Page 32278]]
resource plan that relies on participant funding, it will infringe on a
state's prerogative to manage the costs borne by its consumers. Alabama
PSC also states that Order No. 1000 incorrectly asserts that the cost
allocation requirements conform fully with the position taken by the
Alabama PSC. Instead, it states that its concern is that a regional
process may identify electricity consumers in Alabama as receiving
benefits from a new transmission project selected in a regional
transmission plan for purposes of cost allocation, even if the supposed
benefits are completely at odds with Alabama PSC's conclusions. Thus,
even though Order No. 1000 states that consumers will not be assigned
costs from which they derive no benefit, Alabama PSC remains concerned
about this and maintains that states should have the option of vetoing
such a course or opting out of any cost allocation.
608. Florida PSC argues that the cost allocation provisions of
Order No. 1000 infringe on its jurisdiction. Florida PSC states that
Florida utilities are vertically-integrated, and no part of the state
is a member of an RTO or ISO. It thus retains authority over cost
allocation. Florida PSC asserts that planning decisions under the new
processes will affect wholesale rates that will flow to retail
customers. Florida PSC thus argues that regions may find themselves
paying higher retail rates for benefits realized only in a neighboring
region. Florida PSC argues that the Commission does not have authority
to assign cost recovery to retail rates for benefits not defined as
such in the retail customers' region.
609. Transmission Access Policy Study Group argues that Order No.
1000 erred in finding that comments on access to regionally cost
allocated facilities through regional tariffs at non-pancaked rates
were beyond the scope of the proceeding.\718\ It asserts that failing
to address these issues leaves a void that must be filled before
regional cost allocations can be implemented in non-RTO regions.\719\
It believes that a regional tariff, with non-pancaked rates covering
both existing and new facilities, is the best way to address these
issues because such tariffs can solve cost allocation implementation
issues and avoid the creation of new rate pancakes. Transmission Access
Policy Study Group suggests that if the Commission does not grant
rehearing, it should use its authority to induce transmission providers
to adopt regional rates that eliminate pancaking and foster
transmission investment.
---------------------------------------------------------------------------
\718\ Transmission Access Policy Study Group at 40 (citing Order
No. 1000, FERC Stats. & Regs. ] 31,323 at PP 549, 764).
\719\ Transmission Access Policy Study Group asserts that Order
No. 1000's focus on cost allocation as disassociated from service
relationships heighten these concerns.
---------------------------------------------------------------------------
610. Alternatively, Transmission Access Policy Study Group states
that the Commission should require a process to address access issues
at the compliance stage. It also argues that access should be addressed
when a specific cost allocation is applied to a project. Transmission
Access Policy Study Group states that in non-RTO regions, the
Commission should require that access issues be addressed in the
regional process for selection of an upgrade and the application of the
regional cost allocation to a facility, as well as require filing of
the specific cost allocation as applied to the particular project
selected for regional cost allocation, with a description of how access
will be provided and on what rates, terms, and conditions. Transmission
Access Policy Study Group believes that specific applications of the
regional cost allocation should be filed as soon as the constructor of
the facility is identified, with access issues addressed at that time
rather than when the facility is completed.\720\ According to
Transmission Access Policy Study Group, this will help address
uncertainty caused by the absence of regional tariffs and Order No.
1000's preference for flexibility. Finally, Transmission Access Policy
Study Group urges prompt public disclosure of the mechanism to provide
access to regionally cost-allocated facilities, and it states that it
is essential to address access issues before a proposed facility
proceeds through the permitting and siting process.
---------------------------------------------------------------------------
\720\ Transmission Access Policy Study Group notes that Order
No. 1000 does not address timing of the filing of specific
applications of the regional cost allocation.
---------------------------------------------------------------------------
611. Several petitioners question the Commission's decision not to
address cost containment issues in Order No. 1000. For example,
Illinois Commerce Commission argues that the Commission does not
provide a good reason for not addressing cost containment, and that it
must be addressed to prevent excessive costs, which is a fundamental
part of any appropriate cost allocation method. Illinois Commerce
Commission asserts that even if Order No. 1000 is not the appropriate
forum, the Commission erred in failing to identify an alternative
forum.
612. Wisconsin PSC requests that there be a mandate to consider
cost overrun containment mechanisms. It argues that uncontained costs
are as likely to undermine needed transmission development as a flawed
cost allocation method or no method at all would. Wisconsin PSC states
that Order No. 1000's distinction between the allocation of costs and
the amount of costs is a hollow one because the key question for states
and the customers who pay for the lines is the cost/benefit of the
buildout.\721\ It also argues that since the Commission saw fit to
develop a fallback mechanism for situations where a project developer
abandons a line that a transmission provider had depended upon for
reliability and supply purposes; it should also have a fallback
mechanism for cost overruns, which pose a much greater prospect of harm
to the consuming public.
---------------------------------------------------------------------------
\721\ Wisconsin PSC at 10-11 (citing Order No. 1000, FERC Stats.
& Regs. ] 31,323 at PP 704-05 (2007)).
---------------------------------------------------------------------------
3. Commission Determination
613. We affirm Order No. 1000's requirement that each public
utility transmission provider have in place a method, or set of
methods, for allocating the costs of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation.\722\ In Order No. 1000, the Commission did not specify how
the costs of an individual regional transmission facility should be
allocated.\723\ It noted, however, that while each transmission
planning region may develop a method or methods for different types of
transmission projects, each such method or methods should apply to all
transmission facilities of the type in question and would have to be
determined in advance for each type of facility.\724\ We continue to
believe that such an approach is necessary to ensure that the rates,
terms, and conditions of jurisdictional service are just and reasonable
and not unduly discriminatory or preferential. This is because in the
absence of clear cost allocation rules, there is a greater potential
that pubic utility transmission providers and nonincumbent transmission
developers may be unable to develop transmission facilities that are
determined by the region to meet their needs.\725\
---------------------------------------------------------------------------
\722\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 558.
\723\ Id. P 560.
\724\ Id.
\725\ Id. P 559.
---------------------------------------------------------------------------
614. In response to Alabama PSC's argument that a state should be
permitted to veto any particular cost allocation if it disagrees with
the outcome, we reiterate Order No. 1000's finding declining to mandate
veto rights
[[Page 32279]]
for state committees. However, as stated in Order No. 1000, the
Commission does not preclude public utility transmission providers from
proposing such mechanisms on compliance if they choose to do so.\726\
We emphasize that any such mechanisms must be consistent with the goals
of Order No. 1000's transmission planning and cost allocation reforms,
an important part of which are to provide that costs are allocated to
beneficiaries roughly commensurate with the benefits that they receive.
---------------------------------------------------------------------------
\726\ Id. P 502.
---------------------------------------------------------------------------
615. In response to Alabama PSC's concern that the Commission's
cost allocation reforms could lead to stranded transmission costs due
to the absence of a necessary contractual vehicle, we note that
entities that receive benefits are subject to a Commission-approved
transmission tariff. The existence of obligation arising under such a
tariff is sufficient to ensure that there will be no stranded costs,
and the question of specific recovery mechanisms is beyond the scope of
this proceeding. This point applies equally to Southern Companies'
concern about payment obligations that correspond to cost assignments.
616. Additionally, we find no merit in the arguments advanced to
challenge our position in Order No. 1000 that cost allocation and cost
recovery are distinct issues and our determination not to address
matters of cost recovery there.\727\ We therefore affirm the
Commission's decision in Order No. 1000 that cost recovery is a
separate issue, and we will not specify how costs can be recovered for
transmission projects that are selected in the regional transmission
plan for purposes of cost allocation. The U.S. Supreme Court has found
that the Commission has broad discretion in determining which issues to
address in a particular proceeding.\728\ While we will not address cost
recovery in this proceeding, we note that cost recovery may be
considered as part of a region's stakeholder process in developing a
cost allocation method or methods to comply with Order No. 1000.
Therefore, to the extent that cost recovery provisions are considered
in connection with a cost allocation method or methods for a regional
or interregional transmission facility, public utility transmission
providers may include cost recovery provisions in their compliance
filings.
---------------------------------------------------------------------------
\727\ Id. P 563.
\728\ Mobil Oil Exploration & Producing Southeast, Inc. v.
United Distribution Companies, 498 U.S. 211, 230 (1991). See also
Tennessee Valley Municipal Gas Association v. FERC, 140 F.3d. 1085,
1088 (D.C. Cir. 1998).
---------------------------------------------------------------------------
617. We thus reject Sacramento Municipal Utility District's
contention that Order No. 1000 is deficient because it does not explain
the mechanism for recovering a cost ``when the party being charged is
not a customer.'' \729\ Sacramento Municipal Utility District's claim
of deficiency is premised on the proposition that costs cannot be
allocated in a situation where an entity does not have a preexisting
contractual relationship with the entity that will recover the costs.
It considers a cost allocation in this situation to be a cost
allocation to a non-customer. We have addressed this issue at length
above. Because we disagree with Sacramento Municipal Utility District's
premise, we disagree that our decision not to address cost recovery in
Order No. 1000 makes the order deficient. This conclusion applies
equally to Sacramento Municipal Utility District's assertion that it is
not a mere concern over form to expect an explanation of the mechanism
for recovering a charge when the party being charged is not a customer.
---------------------------------------------------------------------------
\729\ Sacramento Municipal Utility District at 11.
---------------------------------------------------------------------------
618. Edison Electric Institute seeks clarification on how costs can
be recovered from a beneficiary in the absence of an applicable tariff
or agreement. Edison Electric Institute's request is based on its
reading of paragraph 506 of Order No. 1000, which it notes states that
the Commission ``would permit recovery of costs from a beneficiary in
the absence of a voluntary arrangement.'' However, this statement is
simply part of a summary of the Commission's ruling in AEP. This
summary does not imply that Order No. 1000 contemplates the recovery of
costs from a beneficiary in the absence of an applicable tariff or
agreement. All tariffs will be required to contain an appropriate cost
allocation method or methods.
619. In response to Alabama PSC, the Commission was not being
inconsistent on the issue of cost recovery when it found that
participant funding, which it describes as a form of cost recovery,
cannot be a regional cost allocation method. This argument assumes that
cost allocation and cost recovery are not distinct issues. The
Commission's position is that they are distinct--a point that Alabama
PSC does not challenge--and thus when it concluded that participant
funding cannot serve as a regional cost allocation method, the
Commission was not making a conclusion regarding cost recovery
mechanisms. As a result, the Commission was not taking an action that
was inconsistent with its position that it would not address cost
recovery in Order No. 1000. We address the prohibition against
participant funding as a regional cost allocation method elsewhere in
this order. Similarly, we disagree with Northern Tier Transmission
Group that the Commission is impermissibly imposing recovery of
transmission construction costs on non-jurisdictional entities, as
Order No. 1000 did not address matters of cost recovery.
620. Moreover, we disagree with petitioners' arguments that Order
No. 1000's cost allocation provisions infringe on state authority over
the siting and permitting of transmission facilities, or that they
infringe on integrated resource planning. Petitioners have not
demonstrated anything persuasive to support their comments. More
generally, as we discuss in the cost allocation legal authority section
above, we have ample authority under the FPA to require public utility
transmission providers to file regional and interregional cost
allocation methods, and we direct petitioners to that section for a
fuller discussion of the Commission's legal authority.
621. We disagree with those petitioners who claim the Commission is
seeking to regulate bundled retail rates. North Carolina Agencies
provide no clear explanation for their position. Indeed, they state
only that there is a potential for the Commission to regulate bundled
retail rates. As for Ad Hoc Coalition of Southeastern Utilities'
arguments, we disagree that requiring the implementation of a method to
allocate the costs of new transmission facilities selected in a
regional transmission plan for purposes of cost allocation amounts to
regulation of bundled retail rates.\730\ As discussed in Order No. 1000
and in this order, we have ample legal authority to adopt the Order No.
1000 cost allocation reforms.\731\ We also affirm Order No. 1000's
discussion of this issue, namely, that:
---------------------------------------------------------------------------
\730\ Ad Hoc Coalition of Southeastern Utilities at 74.
\731\ See, e.g., Order No. 1000, FERC Stats. & Regs. ] 31,323 at
P 530-49; see also discussion supra at section 0 and discussion
supra at section IV.A.3.
[I]t is not clear why cost allocations consistent with this
Final Rule would affect state jurisdiction differently from existing
cost allocations. In any event, we find that such arguments are
premature. It is inappropriate for the Commission to decide such
issues generically in a rulemaking, as such issues should be decided
based on
[[Page 32280]]
specific facts and circumstances, none of which are presented
here.\732\
---------------------------------------------------------------------------
\732\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 548.
Accordingly, we reiterate here that in this generic rulemaking
proceeding, these issues are not presented for Commission
determination.
622. To the extent a non-public utility transmission provider
exercises its discretion to enroll as a transmission provider in a
regional transmission planning process, it may be allocated costs
roughly commensurate with the benefits that it is determined to receive
from new transmission facilities selected in the regional transmission
plan for purposes of cost allocation.\733\ We disagree with Arizona
Cooperative and Southwest Transmission that a non-public utility
transmission provider will effectively forfeit its rights to avoid
undue discrimination by participating in the regional transmission
planning process for several reasons. First, the choice of whether to
enroll in the regional transmission planning process, and thus be
subject to being determined to be a beneficiary for which cost
allocation is appropriate, remains with each non-public utility
transmission provider. Second, it will have a voice in the process of
determining the cost allocation method, and if it believes that the
result is unduly discriminatory, it maintains the right to intervene in
the compliance proceeding when that method is filed at the Commission.
Third, for future applications of the method to actual new facilities,
a non-public utility transmission provider could exercise any right it
has in the regional transmission planning process to withdraw rather
than accept the allocation of costs.\734\ And finally, non-public
utility transmission providers choosing to remain in the transmission
planning region notwithstanding dissatisfaction with a particular
application of the cost allocation method may file with the Commission
for a FPA 206 determination that the approved method is no longer just
and reasonable or is unduly discriminatory or preferential in practice.
---------------------------------------------------------------------------
\733\ See discussion supra at PP 0-0.
\734\ To accommodate the participation of non-public utility
transmission providers, the relevant tariffs or agreements governing
the regional transmission planning process could establish the terms
and conditions of orderly withdrawal for non-public utility
transmission providers that are unable to accept the allocation of
costs pursuant to a regional or interregional cost allocation
method. See Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 820.
---------------------------------------------------------------------------
623. We affirm the Commission's finding in Order No. 1000 that this
is not the proper proceeding to address rate pancaking issues. If rate
pancaking is an issue in a particular transmission planning region,
stakeholders may raise their concerns in the consultations leading to
the compliance proceedings for Order No. 1000 or make a separate filing
with the Commission under section 205 or 206 of the FPA, as
appropriate.\735\ The Commission has the discretion to determine which
issues to address in a particular proceeding.\736\
---------------------------------------------------------------------------
\735\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 764.
\736\ Mobil Oil Exploration & Producing Southeast, Inc. v.
United Distribution Companies, 498 U.S. 211, 230 (1991). See also
Tennessee Valley Municipal Gas Association v. FERC, 140 F.3d. 1085,
1088 (D.C. Cir. 1998).
---------------------------------------------------------------------------
624. With regard to concerns related to access to new transmission
facilities for which an entity has been allocated costs pursuant to a
regional or interregional cost allocation method, the Commission
believes that the appropriate forum to consider such issues in the
first instance is in the regional transmission planning process for
each transmission planning region. Each 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. The Commission
anticipates that regions may approach these issues in different ways
and thus will allow public utility transmission providers, in
consultation with stakeholders, to address these issues as they develop
the regional and interregional cost allocation methods for their
transmission planning region. We note that entities may utilize the
existing OATT provisions regarding Order No. 890 dispute resolution,
which will also apply to the new transmission planning and cost
allocation processes adopted under Order No. 1000, if they disagree
with the public utility transmission provider's identification of
benefits and beneficiaries for a regional or interregional transmission
facility selected in the regional transmission plan for purposes of
cost allocation.
625. We affirm the Commission's decision in Order No. 1000 that
cost containment issues relate to the level of costs and not how costs
should be allocated among beneficiaries.\737\ As the Commission
emphasized in Order No. 1000, this proceeding relates to transmission
planning reforms, including the role of cost allocation in transmission
planning, not the level of transmission costs,\738\ and therefore this
proceeding is not the appropriate forum for addressing the transmission
cost containment issues raised by petitioners. However, as with cost
recovery, we note that cost containment may be considered as part of a
region's stakeholder process in developing a cost allocation method or
methods to comply with Order No. 1000. Therefore, to the extent that
cost containment provisions are considered in connection with a cost
allocation method or methods for a regional or interregional
transmission facility, public utility transmission providers may
include transmission cost containment provisions in their compliance
filings.
---------------------------------------------------------------------------
\737\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 704.
\738\ Id.
---------------------------------------------------------------------------
C. Cost Allocation Method for Interregional Transmission Facilities
1. Final Rule
626. In Order No. 1000, the Commission required each public utility
transmission provider in a transmission planning region to have,
together with the public utility transmission providers in its own
transmission planning region and a neighboring transmission planning
region, a common method or methods for allocating the costs of a new
interregional transmission facility among the beneficiaries of that
transmission facility in the two neighboring transmission planning
regions in which the transmission facility is located. The Commission
explained that the cost allocation method or methods used by the pair
of neighboring transmission regions can differ from the cost allocation
method or methods used by each region to allocate the cost of a new
interregional transmission facility within that region.\739\ The
Commission stated that in an RTO or ISO region, the method must be
filed in the OATT.\740\ Additionally, the Commission stated that in a
non-RTO/ISO transmission planning region, the same common cost
allocation method or methods must be filed in the OATT of each public
utility transmission provider in the transmission planning region.\741\
In either instance, the Commission stated that such cost allocation
method or methods must be consistent with the interregional cost
allocation principles adopted in Order No. 1000.\742\
---------------------------------------------------------------------------
\739\ Id. P 578.
\740\ Id.
\741\ Id.
\742\ Id.
---------------------------------------------------------------------------
627. The Commission also clarified that it would not require each
transmission planning region to have the same interregional cost
allocation method or methods with each of its neighbors.\743\ Order No.
1000 provided that each pair of transmission planning
[[Page 32281]]
regions may develop its own approach to interregional cost allocation
that satisfies both transmission planning regions' needs and concerns,
as long as that approach satisfies the interregional cost allocation
principles.\744\
---------------------------------------------------------------------------
\743\ Id. P 580.
\744\ Id.
---------------------------------------------------------------------------
628. The Commission did not specify how the costs for an individual
interregional transmission facility should be allocated.\745\ However,
the Commission stated that while transmission planning regions can
develop a different cost allocation method or methods for different
types of transmission projects, such a cost allocation method or
methods should apply to all transmission facilities of the type in
question and each cost allocation method would have to be determined in
advance for each type of transmission facility.\746\ Also, the
Commission adopted the requirement that an interregional transmission
facility must be selected in a relevant regional transmission plan for
purposes of cost allocation to be eligible for interregional cost
allocation pursuant to the interregional cost allocation method or
methods.\747\
---------------------------------------------------------------------------
\745\ Id. P 581.
\746\ Id.
\747\ Id.
---------------------------------------------------------------------------
629. The Commission also noted that as it made clear in its
discussion of Cost Allocation Principle 4,\748\ costs may be assigned
only on a voluntary basis to a transmission planning region in which an
interregional transmission facility is not located.\749\ The Commission
noted that, given this option, regions are free to negotiate
interregional transmission arrangements that allow for the allocation
of costs to beneficiaries that are not located in the same transmission
planning region as any given interregional transmission facility.\750\
---------------------------------------------------------------------------
\748\ See Order No. 1000, FERC Stats. & Regs. ] 31,323 at
section IV.E.5.
\749\ Id. P 582.
\750\ Id.
---------------------------------------------------------------------------
630. In addition, the Commission clarified that the requirement to
coordinate with neighboring regions applies to public utility
transmission providers within a region as a group, not to each
individual public utility transmission provider acting on its own. For
example, within an RTO or ISO, the RTO or ISO would develop an
interregional cost allocation method or methods with its neighboring
regions on behalf of its public utility transmission owning
members.\751\
---------------------------------------------------------------------------
\751\ Id. P 584.
---------------------------------------------------------------------------
2. Requests for Rehearing or Clarification
631. Several petitioners seek clarification of the Commission's
interregional cost allocation requirements. California ISO seeks
clarification that one planning region cannot allocate costs to a
neighboring transmission planning region for a transmission line that
interconnects to the system of the neighboring region but that the
neighboring region has not determined is needed and has not included in
its transmission plan.
632. MISO Transmission Owners Group 1 requests clarification that
Order No. 1000's statement that a transmission owner in an RTO or ISO
can comply with the proposed interregional cost allocation mandates
through participation in the RTO and ISO is not intended to alter a
transmission owner's section 205 rights or the division of section 205
filing rights between an RTO and its transmission owners. It states
that if the Commission does not provide this clarification, the
Commission must grant rehearing because limiting the section 205 filing
rights of transmission owners would be contrary to judicial
precedent.\752\
---------------------------------------------------------------------------
\752\ MISO Transmission Owners Group 1 at 13-14 (citing Atlantic
City Electric Co. v. FERC, 295 F.3d 1 (D.C. Cir. 2002)).
---------------------------------------------------------------------------
633. Transmission Dependent Utility Systems request clarification
that transmission customer load-serving entities should be able to
review and comment on the development of interregional cost allocation
methods and have their input considered and addressed before public
utility transmission providers make their compliance filings.
Transmission Dependent Utility Systems assert this is necessary to
ensure consistency with the non-discrimination requirements of FPA
section 205.
3. Commission Determination
634. As stated in Order No. 1000, the Commission requires that each
public utility transmission provider in a transmission planning region
must have, together with the public utility transmission providers in
its own transmission planning region and a neighboring transmission
planning region, a common method or methods for allocating the costs of
a new interregional transmission facility among the beneficiaries of
that transmission facility in the two neighboring transmission planning
regions in which the transmission facility is located.\753\ We continue
to believe that the absence of clear cost allocation rules for
interregional transmission facilities can impede the development of
such transmission facilities due to the uncertainty regarding the
allocation of responsibility for associated costs, potentially
adversely affecting rates for jurisdictional services causing them to
become unjust and unreasonable or unduly discriminatory or
preferential.\754\
---------------------------------------------------------------------------
\753\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 579.
\754\ Id.
---------------------------------------------------------------------------
635. In response to California ISO's request that we clarify that
another region could not impose costs on it for an interregional
transmission facility without approval, Order No. 1000 states that, for
an interregional transmission facility to receive interregional cost
allocation, each of the neighboring transmission planning regions in
which the interregional transmission facility is proposed to be located
must select the facility in its regional transmission plan for purposes
of cost allocation.\755\ As such, we believe that it is clear that, if
one of the regional transmission planning processes does not select the
interregional transmission facility to receive interregional cost
allocation, neither the transmission developer nor the other
transmission planning region may allocate the costs of that
interregional transmission facility under the provisions of Order No.
1000 to the region that did not select the interregional transmission
facility.
---------------------------------------------------------------------------
\755\ Id. P 436.
---------------------------------------------------------------------------
636. In response to MISO Transmission Owners Group 1, we clarify
that the Order No. 1000 interregional cost allocation requirements are
not intended to alter the section 205 rights of transmission owners and
RTOs.
637. In response to Transmission Dependent Utility Systems, we
clarify that all interested parties, including transmission customer
load-serving entities, must have the opportunity to participate in the
process of developing the interregional cost allocation method or
methods. As the Commission stated in Order No. 1000, in developing
appropriate cost allocation methods for their regional and
interregional transmission facilities, public utility transmission
providers must consult with stakeholders.\756\ The Commission also
stated that stakeholder input in the development of a cost allocation
method or methods should ensure that the method or methods ultimately
agreed upon is balanced and does not favor any
[[Page 32282]]
particular entity.\757\ Consistent with Order No. 890, the Commission
defined ``stakeholder'' in Order No. 1000 as including any party
interested in the regional transmission planning process.\758\ As such,
we view stakeholder participation, including that by load-serving
entities, as an important aspect of the development of compliance
filings to meet the requirements of Order No. 1000.
---------------------------------------------------------------------------
\756\ Id. P 482.
\757\ Id. P 671.
\758\ Id. P 143.
---------------------------------------------------------------------------
D. Principles for Regional and Interregional Cost Allocation
1. Use of a Principles-Based Approach
638. In Order No. 1000, the Commission required each public utility
transmission provider to show on compliance that its cost allocation
method or methods for regional cost allocation and its method or
methods for interregional cost allocation are just and reasonable and
not unduly discriminatory or preferential by demonstrating that each
method satisfies the six cost allocation principles.\759\ The
Commission took a principles-based approach because it recognized that
regional differences may warrant distinctions in cost allocation
methods among transmission planning regions. The Commission explained
that the six regional cost allocation principles apply to, and only to,
a cost allocation method or methods for new regional transmission
facilities selected in a regional transmission plan for purposes of
cost allocation.\760\ Likewise, the Commission stated that the six
analogous interregional cost allocation principles apply to, and only
to, a cost allocation method or methods for a new transmission facility
that is located in two neighboring transmission planning regions and
accounted for in the interregional transmission coordination procedure
in an OATT.\761\ Additionally, the Commission stated that the cost
allocation principles do not apply to other new transmission facilities
and therefore did not foreclose the opportunity for a developer or
individual customer to voluntarily assume the costs of a new
transmission facility.\762\
---------------------------------------------------------------------------
\759\ Id. P 603.
\760\ Id.
\761\ Id.
\762\ Id.
---------------------------------------------------------------------------
639. The Commission declined to adopt a default regional or
interregional cost allocation method, but stated that in the event of a
failure to reach an agreement on a cost allocation method or methods,
it would use the record in the relevant compliance filing proceeding as
a basis to develop a cost allocation method or methods that meets its
proposed requirements.\763\
---------------------------------------------------------------------------
\763\ Id. PP 607, 610.
---------------------------------------------------------------------------
a. Arguments That Principles-Based Cost Allocation Methods Are Unfair
and Arguments Related to Commission Determination of Cost Allocation
Method Pursuant to the Compliance Process
640. Illinois Commerce Commission argues that Order No. 1000
appears to require transmission providers to be responsible for
estimating project benefits, which effectively delegates the
Commission's authority over rates and to define what constitutes
benefits. It maintains that delegating this authority to the
transmission provider and the stakeholder process does not ensure that
planning criteria and cost allocation methods based on benefits will be
just and reasonable.
641. Illinois Commerce Commission asserts that the stakeholder
process may neglect the interests of some load-serving entities that
will bear the costs of transmission investment when the interests of
those load-serving entities are not aligned or directly conflicts with
the majority of load-serving entities and other stakeholders within the
region. It cites Illinois Commerce Commission as an example of an
outcome where the majority of stakeholders agreed to spread costs in
eastern PJM to utilities in western PJM, and the Commission deferred to
this ``regional consensus'' while acknowledging there was none.
Illinois Commerce Commission states that the Seventh Circuit disagreed
and found that one group of utilities' desire to be subsidized by
another is no reason in itself for giving them their way.
642. Illinois Commerce Commission further argues that delegating
the Commission's obligation to ensure just and reasonable rates to a
stakeholder process violates section 205 due process rights of
interested parties because it imposes an undue burden on parties to
participate in a new and costly process without providing the funding
to participate. It contends that the process will lack a public
administrative record, making it difficult for interested parties who
would have otherwise intervened in a normal administrative process to
follow the proceeding. Illinois Commerce Commission states that the
right of parties to bring a section 206 complaint is an inadequate
remedy in light of these issues.
643. Several petitioners seek rehearing of the Commission's
statement that if an agreement on a cost allocation method is not
reached, it will use the record to develop a method or methods for the
region, arguing that the Commission does not have the authority to do
so.\764\ Florida PSC argues that this provision encroaches on Florida's
jurisdiction because the Commission does not have authority to assign
cost recovery to retail customers.\765\ Kentucky PSC also argues that
the due process requirements of the state integrated resource planning
and certificate of public convenience and necessity processes is being
replaced by majoritarian processes backed by the threat that the
Commission will determine cost allocation processes if the regional
group cannot.
---------------------------------------------------------------------------
\764\ See, e.g., Georgia PSC; Illinois Commerce Commission; and
Florida PSC.
\765\ Florida PSC at 7 (citing Order No. 1000, FERC Stats. &
Regs. ] 31,323 at P 607).
---------------------------------------------------------------------------
644. Illinois Commerce Commission argues that Order No. 1000
implies that if there is consensus, the Commission will accept that
compliance filing. Illinois Commerce Commission seeks rehearing of the
meaning of ``consensus'' if it means here something different from
``agreement.'' \766\ It argues that the term is insufficient to protect
those who may be harmed by a majority. Additionally, Illinois Commerce
Commission argues that requiring a consensus means that minority
interests will always lose, which is unduly discriminatory on its face,
and forcing minority interests to bring a section 206 complaint is
insufficient to protect their interests and overly burdensome.
---------------------------------------------------------------------------
\766\ Illinois Commerce Commission at 35.
---------------------------------------------------------------------------
645. New York Transmission Owners seek clarification that the
Commission will impose a cost allocation method on transmission
planning regions only as a last resort after consensus has been
encouraged through mediation and other alternative dispute resolution
procedures.
646. Transmission Dependent Utility Systems seek clarification, or
in the alternative rehearing, that compliance filings must document the
opportunities for customer input in the development of regional and
interregional cost allocation methods as well as the basis relied upon
for disregarding any such input. They argue that this information is
necessary to gauge the inclusiveness and transparency of the processes
for developing cost allocation methods.
i. Commission Determination
647. We affirm the Commission's decision that the appropriate
approach is for public utility transmission providers to develop
regional and interregional cost allocation methods based on the six
cost allocation
[[Page 32283]]
principles described in Order No. 1000, thereby allowing public utility
transmission providers the flexibility to develop cost allocation
methods that best suit regional needs. The Commission disagrees that
Order No. 1000 is delegating the Commission's authority over rates to
define what constitutes benefits. The proper context for further
consideration of ``benefits'' and ``beneficiaries'' is in the
Commission's review of compliance proposals and a record before the
Commission.\767\ As the Commission explained in Order No. 1000, the
cost allocation principles do not prescribe a uniform approach, but
provide the public utility transmission providers in consultation with
the stakeholders in each region the opportunity to first develop their
own method or methods, and recognized that regional differences may
warrant distinctions in cost allocation methods.\768\ It would be
inconsistent with the regional flexibility provided in Order No. 1000
for the Commission to prescribe a uniform approach to determining
benefits or beneficiaries when a multitude of factors vary across
transmission planning regions and the entire country.
---------------------------------------------------------------------------
\767\ Id. P 624.
\768\ Id.
---------------------------------------------------------------------------
648. In response to concerns that a stakeholder process is an
inappropriate way to allocate costs, we note that the Commission has
previously found, and the D.C. Circuit has affirmed, that a stakeholder
process is appropriate when unresolved issues may be better addressed
in a forum featuring broad stakeholder input, and where a transmission
solution can be better tailored to meet regional transmission needs
through broad input from interested participants that may not otherwise
participate in a Commission proceeding.\769\ The public utility
transmission providers and stakeholders that make up the region are
intimately familiar with the transmission needs of their region.
Therefore, they are in the best position to develop, and submit to the
Commission for review, a cost allocation method or methods that
complies with the six cost allocation principles and best meets the
transmission planning region's needs. This does not amount to a
delegation of Commission authority because the Commission ultimately
will determine whether the method or methods are just and reasonable
and interested parties will continue to have an opportunity to support
or oppose the cost allocation methods proposed in the compliance
filings at the Commission.\770\
---------------------------------------------------------------------------
\769\ Braintree Elec. Light Dept. v. ISO New England, Inc., 128
FERC ] 61,008 (2009) (citing MISO, 125 FERC ] 61,038, at P 19
(2008); Pepco Energy Servs. v. PJM Interconnection, L.L.C., 124 FERC
] 61,008, at P 24 (2008); PSC of Wis. v. FERC, 545 F.3d 1058, 1063
(D.C. Cir. 2008)).
\770\ PSC of Wis. v. FERC, 545 F.3d at 1064.
---------------------------------------------------------------------------
649. It also does not interfere with section 205 rights or
otherwise impose an undue burden on parties to participate in new and
costly processes. The transmission planning and cost allocation
processes in Order No. 1000 are not entirely new, but rather build on
the reforms to the processes already required by Order No. 890, in
which all interested parties should already be participating. In any
event, with regard to state regulators, such as Illinois Commerce
Commission, we have already explained above that, consistent with Order
Nos. 1000 and 890, they may request that the public utility
transmission providers in their region propose a mechanism in their
compliance filings providing for state regulators to recoup the costs
of their participation in the regional transmission planning
process.\771\ In addition, interested parties retained their section
206 rights to file a complaint if they have concerns about the process
or the method or methods proposed. Illinois Commerce Commission has not
provided a reason that section 206 would not be an appropriate remedy
and not identified specific facts to illustrate a scenario where it
would not be able to obtain an adequate remedy under section 206.
---------------------------------------------------------------------------
\771\ See discussion supra at section 0. (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 162 and quoting Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 574 n.339 and P 586)).
---------------------------------------------------------------------------
650. We also affirm the Commission's decision in Order No. 1000
that, in the event of a failure to reach an agreement on a cost
allocation method or methods, the Commission will use the record in the
relevant compliance filing proceeding as a basis to develop a cost
allocation method or methods that meets Order No. 1000's cost
allocation principles.\772\ This provision does not infringe upon state
jurisdiction, as suggested by the Florida and Kentucky PSCs, because,
as discussed above, states retain whatever jurisdiction they have over
retail rates.
---------------------------------------------------------------------------
\772\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 607.
---------------------------------------------------------------------------
651. In response to Illinois Commerce Commission's argument
regarding whether a ``consensus'' of stakeholders is synonymous with
``agreement,'' and if so, that such an approach would allow the
majority to override minority interests when making compliance filings,
we reiterate our finding in Order No. 1000 that ``the Commission will
consider in response to compliance filings all issues raised by
commenters, such as what constitutes an impasse, [and] whether there
should be deference to the majority * * *.'' \773\ Accordingly, we
decline to speculate in advance of these compliance filings the extent
to which the Commission would give weight to the majority of public
utility transmission providers and stakeholders in a region.
---------------------------------------------------------------------------
\773\ Id. P 609.
---------------------------------------------------------------------------
652. In response to New York Transmission Owners, we reiterate that
the Commission will use the record in the relevant compliance filings
as a basis to develop a cost allocation method or methods for a
transmission planning region when the transmission planning region
fails to reach an agreement. To this end, we note that in response to a
directive to do so in Order No. 1000,\774\ the Commission's staff has
been made available to assist public utility transmission providers and
stakeholders in the various regions around the country in reaching an
agreement on a compliance filing. The Commission also noted in Order
No. 1000 that the procedural mechanisms used by it in response to
compliance filings will depend on the nature of remaining disputes and
what issues are still at stake that are preventing the public utility
transmission providers in each transmission planning region or pair of
transmission planning regions from reaching a consensus.\775\
Accordingly, in advance of such compliance filings, we decline to
specifically endorse any particular procedural method for resolving
cost allocation disputes brought forward in compliance filings;
mediation or other alternative dispute resolution procedures, as
suggested by New York Transmission Owners are certainly viable methods
to encourage consensus and will be considered if necessary at the
appropriate time.
---------------------------------------------------------------------------
\774\ Id. P 14.
\775\ Id. P 609.
---------------------------------------------------------------------------
653. In response to Transmission Dependent Utility Systems' request
that compliance filings must document the opportunities for customer
input provided, as well as the basis relied upon for disregarding any
such customer input, we do not believe any clarification of Order No.
1000 is necessary. Order No. 1000 already provides that ``[p]ublic
utility transmission providers must document in their compliance
filings the steps they have taken to reach consensus on a cost
allocation method or set of methods to comply with this Final Rule, as
thoroughly as practicable, and provide whatever information they view
[[Page 32284]]
as necessary for the Commission to make a determination of the
appropriate cost allocation method or methods.'' \776\
---------------------------------------------------------------------------
\776\ Id. P 607.
---------------------------------------------------------------------------
2. Cost Allocation Principle 1--Costs Allocated in a Way That Is
Roughly Commensurate With Benefits
654. In Order No. 1000, the Commission adopted the following Cost
Allocation Principle 1 for both regional and interregional cost
allocation:
Regional Cost Allocation Principle 1: The cost of transmission
facilities must be allocated to those within the transmission
planning region that benefit from those facilities in a manner that
is at least roughly commensurate with estimated benefits. In
determining the beneficiaries of transmission facilities, a regional
transmission planning process may consider benefits including, but
not limited to, the extent to which transmission facilities,
individually or in the aggregate, provide for maintaining
reliability and sharing reserves, production cost savings and
congestion relief, and/or meeting Public Policy Requirements.
and
Interregional Cost Allocation Principle 1: The costs of a new
interregional transmission facility must be allocated to each
transmission planning region in which that transmission facility is
located in a manner that is at least roughly commensurate with the
estimated benefits of that transmission facility in each of the
transmission planning regions. In determining the beneficiaries of
interregional transmission facilities, transmission planning regions
may consider benefits including, but not limited to, those
associated with maintaining reliability and sharing reserves,
production cost savings and congestion relief, and meeting Public
Policy Requirements.\777\
---------------------------------------------------------------------------
\777\ Id. P 622.
655. However, the Commission stated that it was not prescribing a
particular definition of ``benefits'' or ``beneficiaries'' in Order No.
1000.\778\ In the Commission's view, the proper context for
consideration of these matters is in the regional stakeholder meetings
in the first instance, followed by Commission consideration of these
matters on review of compliance proposals and the record before the
Commission.\779\
---------------------------------------------------------------------------
\778\ Id. P 624.
\779\ Id.
---------------------------------------------------------------------------
656. The Commission also stated that if a non-public utility
transmission provider makes the choice to become part of the
transmission planning region and it is determined by the transmission
planning process to be a beneficiary of certain transmission facilities
selected in the regional transmission plan for purposes of cost
allocation, that non-public utility transmission provider is
responsible for the costs associated with such benefits.\780\
---------------------------------------------------------------------------
\780\ Id. P 629.
---------------------------------------------------------------------------
657. Additionally, in Order No. 1000, the Commission found that
issues related to the generator interconnection process and to
interconnection cost recovery were outside the scope of the rulemaking
proceeding.\781\ The Commission stated that Order No. 2003 \782\ sets
forth the procedures for the interconnection of a large generating
transmission facility to the bulk power system.\783\ Additionally, the
Commission emphasized that Order No. 1000 did not set forth any new
requirements with respect to such procedures for interconnecting large,
small, or wind or other generation facilities.\784\ Therefore, the
Commission determined that Order No. 1000 was not the proper proceeding
for commenters to raise issues about the interconnection agreements and
procedures under Order Nos. 2003, 2006 \785\ or 661.\786\
---------------------------------------------------------------------------
\781\ Id. P 760.
\782\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146,
order on reh'g, Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, 70 FR 265, FERC Stats. &
Regs. ] 31,171, order on reh'g, Order No. 2003-C, 70 FR 37661, FERC
Stats. & Regs. ] 31,190, aff'd sub nom. Nat'l Ass'n of Regulatory
Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied,
552 U.S. 1230 (2008).
\783\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 760.
\784\ Id.
\785\ Order No. 2006, 70 FR 34189, FERC Stats. & Regs. ] 31,180,
order on reh'g, Order No. 2006-A, 70 FR 71760, FERC Stats. & Regs. ]
31,196, order granting clarification, Order No. 2006-B, 71 FR 42587,
FERC Stats. & Regs. ] 31,221.
\786\ Order No. 661, 70 FR 34993 (Jun. 16, 2005), FERC Stats. &
Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs.
] 31,198.
---------------------------------------------------------------------------
a. Requests for Rehearing or Clarification
658. Several petitioners seek rehearing or clarification regarding
the lack of a definition of ``benefits'' in Order No. 1000. Illinois
Commerce Commission argues that by failing to establish definitions and
standards for transmission providers to implement in identifying
project benefits, the Commission has placed transmission providers in
conflict with majority desires in the stakeholder process because an
RTO is obligated to act in the interests of its transmission owning
members. It argues that RTO behavior has been more accommodating to
transmission owning utilities than captive ratepayers, and this issue
will be exacerbated with less Commission oversight.
659. Arizona Cooperative and Southwest Transmission also argue that
there is insufficient Commission oversight of the definition and
measurement of benefits. It argues that ``benefits'' can, within the
context of a network, become so pliable as to become meaningless,
especially as applied to individual situations. Arizona Cooperative and
Southwest Transmission add that different outcomes are apt to flow from
how benefits are defined. Public utilities may value needs and
interests differently from other stakeholders, and customers and
entities will not all have the same needs and interests. Arizona
Cooperative and Southwest Transmission are concerned that it may be
deemed to receive benefits that have little or nothing to do with its
needs.
660. Georgia PSC and Florida PSC seek clarification of the
definition of benefits and what constitutes too narrow or too broad a
definition. Florida PSC asserts that leaving this question to the
stakeholder and subsequent compliance process creates the possibility
that regions will adopt a definition of benefits that does not meet
whatever undefined standard the Commission may have in mind. It argues
that this approach limits regional autonomy in an undefined way, even
though the Commission states that regions are free to determine their
own definitions of benefits.
661. Georgia PSC and Florida PSC also seek clarification of what
benefits must be quantifiable and based on existing policies in state
and federal law. Florida PSC argues that ambiguities on this issue and
what constitutes too broad or narrow a definition of benefits violate
the Due Process Clause ``fair notice'' requirement.\787\
---------------------------------------------------------------------------
\787\ Florida PSC at 8 (citing Trinity Broadcasting of Fla.,
Inc. v. FCC, 211 F.3d 618, 628 (D.C. Cir. 2000)).
---------------------------------------------------------------------------
662. Other petitioners argue that the definitions of ``benefits''
and ``beneficiary'' were left too broad.\788\ Kentucky PSC argues that
the Commission erred in failing to define ``cost causer'' and
``beneficiary.'' \789\ It asserts that recently there has been
considerable dispute over the meaning of cost causer and when an entity
becomes a beneficiary of a new or expanded facility developed by
others. Kentucky PSC is concerned that there is no requirement that
cost allocation processes account for proximity to a project, which it
asserts is directly related a project's actual benefits in terms of
improving reliability, reducing congestion, and opening markets. It
contends that it appears that a project may be eligible for cost
allocation solely
[[Page 32285]]
due to its ability to meet the public policy requirements of state or
federal governments.\790\ Kentucky PSC explains that there is no
requirement that a state have a need for a project, which will result
in ratepayers paying for projects that may not be located within their
state and that are designed to meet other states' public policy
requirements. It maintains that to exempt a state's ratepayers from
cost allocation only if they will not benefit at present or in a
``future scenario'' appears to enable the majority in a regional
planning entity to decide that a particular state's legislature will,
or should, ultimately enact certain public policies or that the federal
government will do so.
---------------------------------------------------------------------------
\788\ See, e.g., Coalition for Fair Transmission Policy; and
PSEG Companies.
\789\ Kentucky PSC at 5.
\790\ Kentucky PSC at 6 (quoting Order No. 1000, FERC Stats. &
Regs. ] 31,323 at P 585).
---------------------------------------------------------------------------
663. Likewise, Coalition for Fair Transmission Policy argues that
not limiting the definition of ``benefits'' and ``beneficiary'' will
lead to uncertainty and dispute.\791\ It states that a beneficiary-pays
approach is appropriate for certain types of projects, such as projects
driven by reliability compliance obligations, because the relationship
between specific transmission projects, reliability impacts, and the
benefits of reliability are well established and capable of examination
within a framework of existing transmission planning horizons and study
methodologies. However, Coalition for Fair Transmission Policy asserts
that it is difficult to define benefits and beneficiaries in a way that
is just and reasonable and objectively verifiable for projects such as
upgrades driven by economics and/or public policy requirements.
---------------------------------------------------------------------------
\791\ Coalition for Fair Transmission Policy at 8.
---------------------------------------------------------------------------
664. According to Coalition for Fair Transmission Policy, failure
to define potential benefits correctly on compliance will have adverse
economic and policy impacts. For instance, it maintains that if
benefits are defined to include broad societal benefits of building
renewables in a certain area, and that definition is used to justify
cost socialization of transmission projects to that area, the generator
or customer will not face the true costs of their resource decisions.
Buyers may decide to buy from remote renewable resources that require
long-distance transmission, rather than potentially lower cost local
renewable resources, because they do not have to pay the full
transmission costs. According to Coalition for Fair Transmission
Policy, competitive wholesale markets using locational-marginal pricing
would at that point begin to see price signals break down and become
inefficient. It also argues that siting may become more difficult
because those required to pay for lines they do not see benefit from
will litigate both the cost and siting-approval processes.
665. Coalition for Fair Transmission Policy urges the Commission to
limit regions to considering only benefits that: (1) Occur within the
typical transmission planning horizon of the public utilities within
the region that can be measured or projected through the kinds of
transmission planning studies that are normally conducted; (2) are not
speculative; and (3) are not based on ``societal'' benefits that are
not embodied in existing federal and state public policy
requirements.\792\ It also argues that the Commission should clarify
that regional transmission planning may not adopt presumptions that
broad categorizations of types or classes of transmission lines driven
by economic or public policy requirements have broad benefits and
should be allocated widely. Also, Coalition for Fair Transmission
Policy and North Carolina Agencies argue that the Commission should
require that those seeking cost allocations for individual transmission
projects be able to demonstrate quantifiable, observable and tangible
reliability and economic benefits with reasonable particularity that is
tied directly to those who will be required to pay under a cost
allocation methodology. North Carolina Agencies argue that both the FPA
and Commission precedent require the allocation of costs in proportion
to the real reliability and economic benefits resulting from a
transmission investment that can be measured or projected within the
planning horizon.
---------------------------------------------------------------------------
\792\ Coalition for Fair Transmission Policy at 13.
---------------------------------------------------------------------------
666. In addition, Coalition for Fair Transmission Policy argues
that the Commission should revise its cost allocation principles to
assure that benefits are defined in way that conforms with what it
asserts are established cost-causation standards, which include, among
other things, tying cost allocation to the taking of transmission
service.\793\
---------------------------------------------------------------------------
\793\ Coalition for Fair Transmission Policy at 15-16 (citing
Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1369 (D.C.
Cir. 2004); citing Illinois Commerce Commission v. FERC, 576 F.3d at
474-77; citing Pacific Gas & Electric Co. v. FERC, 373 F.3d 1315,
1321 (D.C. Cir. 2004); quoting Algonquin Gas Transmission Co. v.
FERC, 948 F.2d 1305, 1312-14 (D.C. Cir. 1991)).
---------------------------------------------------------------------------
667. Coalition for Fair Transmission Policy maintains that while
Order No. 1000 states that the Commission will fill in the gaps that it
left in Order No. 1000 through the process of accepting or rejecting or
requiring modification of proposed definitions, the courts have
rejected this approach as contrary to law, arbitrary and
capricious.\794\ Coalition for Fair Transmission Policy asserts that
the Commission must supply sufficient explanation to provide a
reasonable benchmark and guidance in the development of compliance
filings. Coalition for Fair Transmission Policy asserts that the lack
of additional guidance creates a risk of stalemate at the regional
level and a likelihood that the Commission ultimately would have to
define the terms for a region. It argues that this would essentially
penalize public utility transmission providers because the process is
designed to fail and then be saved by the Commission.
---------------------------------------------------------------------------
\794\ Coalition for Fair Transmission Policy at 14 (citing
Appalachian Power Co. v. EPA, 208 F.3d 1015, 1020 (D.C. Cir. 2000)).
---------------------------------------------------------------------------
668. Illinois Commerce Commission argues that there is no way to
identify ``more efficient or cost effective'' transmission projects in
the planning process without a meaningful estimation of benefits, and
there is no way to assess whether a transmission provider has complied
with the Commission's directive that costs be allocated at least
roughly commensurate with benefits unless the level of benefits
expected to be provided by a project to each load-serving entity have
been determined.\795\ It adds that if the Commission's requirements are
not clear, there will be no basis to make compliance findings or to
detect planning and cost allocation abuses.
---------------------------------------------------------------------------
\795\ Illinois Commerce Commission at 10.
---------------------------------------------------------------------------
669. Illinois Commerce Commission and MISO Northeast seek
clarification that generators are subject to regional cost allocation.
Illinois Commerce Commission requests clarification that costs can be
recovered when the planning itself is undertaken to accommodate the
interconnection of particular generators. It notes that Order No. 1000
ruled out participant funding as an acceptable regional or
interregional cost allocation method, but Illinois Commerce Commission
states that participant funding has applied to generation developers
that agree to fund transmission network upgrades to enable their
generator to be interconnected to the network. Illinois Commerce
Commission requests clarification that Order No. 1000 does not prohibit
transmission providers from finding generators to be cost causers or
beneficiaries of new transmission facilities developed pursuant to the
regional or interregional planning process and allocating costs to
those generators accordingly. MISO Northeast likewise requests that the
[[Page 32286]]
Commission clarify that any regionwide cost allocation method adopted
pursuant to Order No. 1000 must allocate costs to generators and end-
users commensurate with the share of public policy benefits that they
receive.
670. In contrast, NextEra argues that generators should not be
responsible for costs not specified in interconnection agreements. It
explains that Order No. 2003 recognized that generators must be able to
identify all risks prior to entering into an interconnection agreement
and commencing construction when it concluded that interconnection
customers should only be responsible for costs specifically identified
in their interconnection agreements.\796\ It argues that it follows
that generators should not be responsible for costs not identified in
their interconnection agreements, and asserts that if costs could be so
allocated, it would make the cost of project financing prohibitive
because lenders would likely seek protection for such contingencies.
NextEra thus urges the Commission to clarify that generators and other
tie line owners will not be responsible for costs not specified in
their interconnection agreements, which it argues is consistent with
Order No. 1000's conclusion that costs cannot be involuntarily
allocated to non-beneficiaries. Otherwise, NextEra argues, such
unknowable and unworkable cost allocation creates unjust and
unreasonable risks and would be inconsistent with Order No. 2003.
---------------------------------------------------------------------------
\796\ NextEra at 18 (citing Order No. 2003, FERC Stats. & Regs.
] 31,146 at P 421).
---------------------------------------------------------------------------
671. Illinois Commerce Commission also takes issue with the
requirement in Order No. 1000 that cost allocation methods consider the
benefits and costs of groups of new transmission facilities rather than
requiring that each project satisfy the Commission's principles and
requirements on its own merits. It argues that a portfolio approach to
transmission planning allows the approval of projects that, when
considered individually, are not cost beneficial.
672. Illinois Commerce Commission states that if individual
projects are cost beneficial, and in the aggregate their estimated
benefits are roughly commensurate with a postage stamp allocation, then
an allocation according to the benefits of each project individually
would result in an allocation roughly equivalent with a postage stamp
allocation. It argues that this scenario would render the postage stamp
allocation unnecessary. Therefore, Illinois Commerce Commission argues
that the Commission erred by including the word ``aggregate'' in
Principle 1 because it allows transmission providers to avoid
demonstrating that each individual project is cost beneficial. It also
argues that the Commission violated the FPA and case precedent in
failing to remove postage stamp rates as a possible cost allocation
method. Specifically, it maintains that it is incorrect to conclude
that even when ``all customers within a transmission planning region
are found to benefit from the use or availability of a transmission
facility or class or group of transmission facilities,'' they all
benefit roughly equally.\797\ Illinois Commerce Commission also points
to the Seventh Circuit's statement that an assertion of generalized
system benefits is not sufficient to justify a cost allocation and that
alleged benefits, without specific evidentiary support, are too
speculative to be considered.
---------------------------------------------------------------------------
\797\ Illinois Commerce Commission at 16.
---------------------------------------------------------------------------
673. Finally, ELCON, AF&PA, and the Associated Industrial Groups
argue that use of a postage stamp rate for cost allocation at the
regional or interregional level is a form of cost socialization, and it
is therefore inconsistent with the cost causation principle. They also
maintain that the statement by the court in Illinois Commerce
Commission that benefits be at least roughly commensurate with costs
requires one to conclude that a postage stamp rate is an impermissible
form of cost causation.
i. Commission Determination
674. We affirm Order No. 1000 and therefore deny those arguments
requesting us to prescribe a particular definition of ``benefits'' or
``beneficiaries.'' As the Commission found in Order No. 1000, the
proper context for further consideration of these matters is on review
of compliance proposals and a record before us. Many of the petitioners
here essentially expound on concerns they raised in the rulemaking
proceeding that more specificity in Order No. 1000 itself is required
because an overly broad or overly narrow definition of beneficiary or
beneficiaries could lead to cost allocations that do not correspond to
cost causation. However, as stated in Order No. 1000, we believe that
concerns regarding overly narrow or broad interpretations of benefits
will be addressed in the first instance during the process of public
utility transmission providers consulting with their stakeholders as
part of the development of a compliance filing. If such interpretations
should emerge, we can more effectively ensure that the term is not
given too narrow or broad a meaning by considering a specific proposal
and a record than by attempting to anticipate and rule on all
possibilities before the fact. This point applies equally to those
petitioners that note the potential difficulties in quantifying
benefits.\798\ For this reason, we decline to adopt any of the many
suggestions offered by petitioners in their requests for rehearing and
clarification, including those who argue that only certain benefits,
such as reliability benefits, should be considered, because determining
other types of benefits is difficult or speculative.
---------------------------------------------------------------------------
\798\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 624-25.
---------------------------------------------------------------------------
675. In response to Illinois Commerce Commission's concern that by
not providing a definition of ``benefits'' in Order No. 1000 the
Commission would exacerbate an RTO's ability to favor its transmission
owning members to the detriment of other stakeholders, we first note
that we do not accept the premise that RTOs as a rule engage in such
behavior. In any event, when each public utility transmission provider,
including an RTO, proposes its cost allocation method or methods, the
Commission will review the method or methods, including how benefits
and beneficiaries are defined, to determine whether it complies with
the requirements of Order No. 1000. This review will include an
analysis of whether the cost allocation method or methods comply with
Principle 1, which requires that the cost allocation method or method
result in an allocation of costs roughly commensurate with benefits. If
the compliance filing is unclear on these matters or if parties take
issue with aspects of the compliance filing, such as the definition of
benefits, the Commission will address those issues at that time.
676. We also disagree with petitioners, such as Georgia PSC and
Florida PSC, who assert that by not defining benefits the Commission is
limiting regional autonomy. By permitting public utility transmission
providers in a region to define benefits collectively together with
regional stakeholders, the Commission is enabling them to account for
regional differences rather than prescribing a one-size-fits-all method
that might not do so as effectively. We also decline to grant the
requests of Georgia PSC and Florida PSC for clarification of what
benefits must be quantifiable based on
[[Page 32287]]
existing policies in state and federal law. Consistent with the
discussion above, we believe that this is a matter that is best
addressed in the first instance by the public utility transmission
providers and their stakeholders in the development of the cost
allocation methods for their regions. Furthermore, Florida PSC's
argument that the fair notice requirement of the Due Process Clause
requires a definition of benefits is without merit, as Florida PSC and
all other stakeholders will have ample opportunity to participate in
both in the development of the cost allocation methods for their
regions, as well as in the Commission proceeding to review the
compliance filings that incorporate those cost allocation methods.
677. Moreover, we note that, as applied by the courts, the Due
Process standard has been held to allow for flexibility in the wording
of an agency's rules and for a reasonable breadth in their
construction.\799\ In fact, the courts have recognized that ``by
requiring regulations to be too specific, [courts] would be opening up
large loopholes allowing conduct which should be regulated to escape
regulation.'' \800\ As the Supreme Court has noted, the degree of
vagueness tolerated by the Constitution depends in part on the nature
of the rules at issue.\801\ In the case of economic regulation, the
Supreme Court has found that the vagueness test must be applied in a
less strict manner because, among other things, ``the regulated
enterprise may have the ability to clarify the meaning of the
regulation by its own inquiry, or by resort to an administrative
process.'' \802\
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\799\ See Grayned v. City of Rockford, 408 U.S. 110 (1971)
(holding that an anti-noise ordinance was not vague where the words
of the ordinance ``are marked by flexibility and reasonable breadth,
rather than meticulous specificity.'').
\800\ See Ray Evers Welding Co. v. OSHRC, 625 F.2d 726, 730 (6th
Cir. 1980).
\801\ See Village of Hoffman Estates v. The Flipside, Hoffman
Estates, Inc., 455 U.S. 489 (1981).
\802\ See id. at 498.
---------------------------------------------------------------------------
678. We also note several petitioners' concerns that the
definitions of ``benefits,'' ``beneficiary,'' and ``cost causer,'' are
too broad, which they argue will lead to further disputes. As the
Commission stated in Order No. 1000, the Commission is allowing
flexibility to accommodate a variety of approaches which can better
advance the goals of Order No. 1000, recognizing that regional
differences may warrant distinctions in cost allocation method or
methods.\803\ This flexibility is provided so that public utility
transmission providers and their stakeholders can develop cost
allocation methods that best meet their region's needs. The Commission
established the Cost Allocation Principles to provide general guidance
to public utility transmission providers to limit uncertainty as they
develop their compliance filings. However, for those cost allocation
methods to be accepted by the Commission as Order No. 1000-compliant,
they will have to clearly and definitively specify the benefits and the
class of beneficiaries. Accordingly, we disagree with the premise of
some petitioners' arguments that there will be uncertainty once the
Commission accepts the cost allocation method or methods in exactly who
is a beneficiary and how such determinations are made. That is the very
purpose of requiring an ex ante cost allocation method: To be clear
upfront about who is benefitting so that disputes are minimized and so
that the transmission facilities selected in the regional transmission
plan for purposes of cost allocation are more likely to be constructed.
---------------------------------------------------------------------------
\803\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 624.
---------------------------------------------------------------------------
679. Additionally, we agree with Illinois Commerce Commission's
argument that there is no way to identify ``more efficient or cost
effective'' transmission solutions, or to assess whether costs are
being allocated at least roughly commensurate with benefits, without a
meaningful estimation of benefits. However, we do not believe that this
requires any change or clarification to Order No. 1000. As we explain
above, while Order No. 1000 does not define benefits and beneficiaries,
it does require the public utility transmission providers in each
region to be definite about benefits and beneficiaries for purposes of
their cost allocation methods. Once beneficiaries are identified,
public utility transmission providers would then be able to identify
what is the more efficient or cost effective transmission solution or
assess whether costs are being allocated at least roughly commensurate
with benefits.
680. With respect to generators being identified as beneficiaries
and ultimately responsible for costs, we find that just as each
transmission planning region retains the flexibility to define benefit
and beneficiary, the public utility transmission providers in each
transmission planning region, in consultation with their stakeholders,
may consider proposals to allocate costs directly to generators as
beneficiaries that could be subject to regional or interregional cost
allocation. However, we emphasize that any effort to do so must not be
inconsistent with the generator interconnection process under Order No.
2003 \804\ because, as we stated in Order No. 1000, the generator
interconnection process and interconnection cost recovery are outside
the scope of this rulemaking. With this said, however, we are not
minimizing the importance of evaluating the impact of generation
interconnection requests during transmission planning, nor limiting the
ability of public utility transmission providers to take requests for
generator interconnections into account in developing assumptions to be
used in the transmission planning process.\805\ While we agree with
NextEra that interconnection costs would be specified in
interconnection agreements, we deny NextEra's request that the
Commission clarify those are the only transmission costs for which
generators could be responsible. The Commission determined in Order No.
2003 that interconnection service does not convey the right to flow
output of the interconnection customer's generating facility onto the
transmission provider's transmission system and does not constitute a
reservation of transmission capacity.\806\ Order No. 2003 states that
the interconnection customer, load or other market participant would
have to request either point-to-point or Network Integration
Transmission Service under the Transmission Provider's OATT in order to
receive the delivery service that is a prerequisite to flowing power
onto the system.\807\ As such, the interconnection customer could be
subject to charges associated with transmission service that are not
addressed in its interconnection agreement.
---------------------------------------------------------------------------
\804\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146,
order on reh'g, Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, 70 FR 265, FERC Stats. &
Regs. ] 31,171, order on reh'g, Order No. 2003-C, 70 FR 37661, FERC
Stats. & Regs. ] 31,190, aff'd sub nom. Nat'l Ass'n of Regulatory
Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied,
552 U.S. 1230 (2008).
\805\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 760.
\806\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146
at P 767.
\807\ Id.
---------------------------------------------------------------------------
681. We affirm the Commission's finding in Order No. 1000 that in
determining the beneficiaries of transmission facilities, Regional Cost
Allocation Principle 1 should permit a regional transmission planning
process to ``consider benefits including, but not limited to, the
extent to which transmission facilities, individually or in the
aggregate, provide for maintaining reliability and sharing reserves,
production cost savings and congestion relief, and/or meeting Public
Policy
[[Page 32288]]
Requirements.'' \808\ Order No. 1000 was not intended to restrict
regional choice in the transmission planning and cost allocation
process as petitioners request.
---------------------------------------------------------------------------
\808\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 622.
---------------------------------------------------------------------------
682. Accordingly, we continue to believe that it is appropriate to
allow public utility transmission providers in a transmission planning
region to propose a cost allocation method that considers the benefits
and costs of a group of new transmission facilities, although they are
not required to do so.\809\ As such, we deny Illinois Commerce
Commission's arguments that ask us to decide in advance that such an
approach is inappropriate and at odds with cost causation. We reiterate
that if public utility transmission providers in a region in
consultation with their regional stakeholders choose to propose and
adequately support a cost allocation method or methods that considers
the benefits and costs of a group of new transmission facilities, Order
No. 1000 would not require a facility-by-facility showing, so long as
the aggregate cost of the transmission facilities in the group is
allocated roughly commensurate with aggregate benefits.\810\ Such an
approach could be reasonable if it, for instance, enables a
transmission planning region to prioritize its new transmission
facilities in such a way as to ensure benefits from the facilities and
maximize the number of system users who will share in those benefits.
---------------------------------------------------------------------------
\809\ Id. P 627.
\810\ Id. P 641.
---------------------------------------------------------------------------
683. We also decline to forbid in advance the potential use of a
postage stamp cost allocation method. We continue to believe that a
postage stamp cost allocation method may be appropriate where all
customers within a specified transmission planning region are found to
benefit from the use or availability of a transmission facility or
class or group of transmission facilities, especially if the
distribution of benefits associated with a class or group of
transmission facilities is likely to vary considerably over the long
depreciation life of the transmission facilities amid changing power
flows, fuel prices, population patterns, and local economic
considerations.\811\ As such, we believe that public utility
transmission providers, if they choose to do so in consultation with
stakeholders, should be permitted to make the case in their compliance
filings that a postage stamp cost allocation is consistent with
Principle 1's requirement that all costs be allocated roughly
commensurate with benefits. To this end, we agree with Illinois
Commerce Commission that any such case would have to do more than make
a mere assertion of generalized system benefits. Last, we decline to
address Illinois Commerce Commission's arguments related to the MISO
MVP proceeding in Docket No. ER10-1791-000 as outside the scope of this
proceeding.
---------------------------------------------------------------------------
\811\ Id. P 605.
---------------------------------------------------------------------------
3. Cost Allocation Principle 2--No Involuntary Allocation of Costs to
Non-Beneficiaries
a. Final Rule
684. 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.\812\
---------------------------------------------------------------------------
\812\ Id. P 637.
685. 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.\813\
---------------------------------------------------------------------------
\813\ Id. P 640.
---------------------------------------------------------------------------
b. Requests for Rehearing or Clarification
686. PSEG Companies argue that Principle 2's ``likely future
scenarios'' language is problematic because it could easily result in
the expansion of the class of customers that are labeled beneficiaries
as more scenarios are introduced, thus making cost allocation
determinations more likely to be inexact and speculative.\814\ They
further state that Order No. 1000's statement that benefits must be
``identifiable'' does not cure the defect, particularly because Order
No. 1000 allows not only transmission providers to identify the
beneficiaries of proposed projects based on ``likely future
scenarios,'' but also allows them to develop such scenarios based on
potential public policy requirements.\815\ PSEG Companies argue that
allowing transmission providers to exercise unfettered discretion in
identifying beneficiaries under future scenarios will allow them to act
arbitrarily and capriciously, and that the expansive interpretations of
``benefits'' and ``beneficiaries'' would permit the allocation of costs
based on tenuous associations with benefits, contrary to Illinois
Commerce Commission.\816\
---------------------------------------------------------------------------
\814\ PSEG Companies at 41-42.
\815\ PSEG Companies at 42-43.
\816\ PSEG Companies at 43-44. PSEG Companies also cite to
Transcontinental Gas Pipe Line Corp., 112 FERC ] 61,170 (2005),
where the Commission rejected reliance on a claim of generalized
system benefits as a basis for allocating gas pipeline upgrade costs
to existing shippers.
---------------------------------------------------------------------------
687. ITC Companies seek clarification 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.\817\ ITC Companies state that one helpful
clarification would be to confirm that, if a project is shown to have
benefits for a zone or customer in one or more of the planning
scenarios generally used by the transmission provider to prepare a
regional transmission plan, those benefits satisfy Principle 2 and
support the allocation of costs to the beneficiaries.
---------------------------------------------------------------------------
\817\ ITC Companies at 14.
---------------------------------------------------------------------------
688. Long Island Power Authority seeks clarification that entities
not subject to a Public Policy Requirement will have an opportunity to
demonstrate this fact for purposes of cost allocation. Long Island
Power Authority acknowledges, however, that where an approved project
provides multiple benefits, it could be appropriate for an entity to be
allocated that portion of a project's costs that are unrelated to
fulfilling certain public policy goals, provided that the economic and
reliability related costs were allocated according to the economic and
reliability procedures of the region, or as agreed upon by neighboring
regions.
c. Commission Determination
689. We affirm Order No. 1000's adoption of Regional and
Interregional Cost Allocation Principle 2. Accordingly, we deny PSEG
Companies' request for rehearing, which largely repeats arguments it
made in the rulemaking proceeding. The Commission disagreed with PSEG
Companies in Order No. 1000 that basing a determination of who
constitutes a ``beneficiary'' on ``likely future scenarios''
necessarily would result in inexact and speculative proposed
transmission plans and cost allocation methods.\818\ The Commission
explained that scenario analysis is a common feature of electric power
[[Page 32289]]
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.\819\ We disagree that the use of ``likely future scenarios''
and Public Policy Requirements will expand the class of customers who
will be identified as beneficiaries. The Commission stated in the
discussion on Cost Allocation Principle 1 above that the identification
of beneficiaries is based on the principle of cost causation.
Accordingly, the scenario analysis is not unfettered. It is limited to
scenarios in which a beneficiary is identified as such on the basis of
the cost causation principle.
---------------------------------------------------------------------------
\818\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 626.
\819\ Id.
---------------------------------------------------------------------------
690. In response to ITC Companies, we therefore clarify 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. 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.
691. In response to Long Island Power Authority's request that the
Commission clarify that entities have the opportunity to demonstrate
that a transmission project proposed to meet a given Public Policy
Requirement is not applicable to them and provides no benefit to them,
we affirm the Commission's statement in Order No. 1000 that
consideration of regional transmission needs driven by Public Policy
Requirements must follow the cost allocation principles. For instance,
Cost Allocation Principle 1 makes clear that Long Island Power
Authority will be allocated only costs that are roughly commensurate
with the benefits it receives from a transmission facility or
facilities. Additionally, Cost Allocation Principle 2 states that those
that receive no benefit from new transmission facilities, either at
present or in a likely future scenario, must not be involuntarily
allocated any of the costs of those transmission facilities.\820\ Given
this, if it is true that Long Island Power Authority would not benefit
from a transmission project or group of projects designed to meet a
regional transmission need driven by a Public Policy Requirement, the
transmission planning region's cost allocation method or methods would
not be permitted to allocate any costs to it. As Long Island Power
Authority acknowledges, even if it does not need the transmission
facility to meet a Public Policy Requirement of its own, it
nevertheless may receive other economic or reliability benefits from a
proposed transmission facility and then the cost allocation method may
allocate the costs for the economic or reliability benefits received.
---------------------------------------------------------------------------
\820\ Id. P 219.
---------------------------------------------------------------------------
4. Cost Allocation Principle 3--Benefit to Cost Threshold Ratio
a. Final Rule
692. The Commission adopted the following Cost Allocation Principle
3 for both regional and interregional cost allocation:
Regional Cost Allocation Principle 3: If a benefit to cost
threshold is used to determine which transmission facilities have
sufficient net benefits to be selected in a regional transmission
plan for the purpose of cost allocation, it must not be so high that
transmission facilities with significant positive net benefits are
excluded from cost allocation. A public utility transmission
provider in a transmission planning region may choose to use such a
threshold to account for uncertainty in the calculation of benefits
and costs. If adopted, such a threshold may not include a ratio of
benefits to costs that exceeds 1.25 unless the transmission planning
region or public utility transmission provider justifies and the
Commission approves a higher ratio.
and
Interregional Cost Allocation Principle 3: If a benefit-cost
threshold ratio is used to determine whether an interregional
transmission facility has sufficient net benefits to qualify for
interregional cost allocation, this ratio must not be so large as to
exclude a transmission facility with significant positive net
benefits from cost allocation. The public utility transmission
providers located in the neighboring transmission planning regions
may choose to use such a threshold to account for uncertainty in the
calculation of benefits and costs. If adopted, such a threshold may
not include a ratio of benefits to costs that exceeds 1.25 unless
the pair of regions justifies and the Commission approves a higher
ratio.\821\
---------------------------------------------------------------------------
\821\ Id. P 646.
693. The Commission stated that Cost Allocation Principle 3 did not
require the use of a benefit to cost ratio threshold.\822\ However, if
a transmission planning region chooses to have such a threshold, the
principle limited the threshold to one that is not so high as to block
inclusion of many worthwhile transmission projects in the regional
transmission plan.\823\ Further, it allowed public utility providers in
a transmission planning region to use a lower ratio without a separate
showing and to use a higher threshold if they justify it and the
Commission approves a greater ratio.\824\
---------------------------------------------------------------------------
\822\ Id. P 647.
\823\ Id.
\824\ Id.
---------------------------------------------------------------------------
b. Request for Rehearing or Clarification
694. Transmission Dependent Utility Systems seek clarification, or
in the alternative rehearing, that stakeholders will have access to the
data necessary to replicate any benefit-to-cost analysis that public
utility transmission providers conduct pursuant to Cost Allocation
Principle 3. They state that the Commission did not respond in Order
No. 1000 to their argument that Cost Allocation Principle 3 be modified
to ensure that implementation of any cost benefit analysis is
transparent to load serving entity transmission customers.
c. Commission Determination
695. We find that it is not necessary to modify Cost Allocation
Principle 3 to require transparency in the implementation of the
benefit to cost analysis because this requirement already exists in
Cost Allocation Principle 5. The language in Regional Cost Allocation
Principle 5 and Interregional Cost Allocation Principle 5 states that
``[t]he cost allocation method and data requirements for determining
benefits and identifying beneficiaries * * * must be transparent with
adequate documentation to allow a stakeholder to determine how they
were applied.'' \825\ Accordingly, we believe that it is clear that the
transparency requirement in Cost Allocation Principle 5 applies to any
benefit to cost analysis subject to Cost Allocation Principle 3, such
that all data relating to the benefit to cost ratio must be
transparent. Additionally, the Order No. 890 transparency principle
requires ``transmission providers to disclose to all customers and
other stakeholders the basic criteria, assumptions, and data that
underlie their transmission system plans.'' \826\
---------------------------------------------------------------------------
\825\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 668.
\826\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 471.
---------------------------------------------------------------------------
5. Cost Allocation Principle 4--Allocation To Be Solely Within
Transmission Planning Region(s) Unless Those Outside Voluntarily Assume
Costs
a. Final Rule
696. The Commission adopted the following Cost Allocation Principle
4 for both regional and interregional cost allocation:
[[Page 32290]]
Regional Cost Allocation Principle 4: The allocation method for
the cost of a transmission facility selected in a regional
transmission plan must allocate costs solely within that
transmission planning region unless another entity outside the
region or another transmission planning region voluntarily agrees to
assume a portion of those costs. However, the transmission planning
process in the original region must identify consequences for other
transmission planning regions, such as upgrades that may be required
in another region and, if the original region agrees to bear costs
associated with such upgrades, then the original region's cost
allocation method or methods must include provisions for allocating
the costs of the upgrades among the beneficiaries in the original
region.
and
Interregional Cost Allocation Principle 4: Costs allocated for
an interregional transmission facility must be assigned only to
transmission planning regions in which the transmission facility is
located. Costs cannot be assigned involuntarily under this rule to a
transmission planning region in which that transmission facility is
not located. However, interregional coordination must identify
consequences for other transmission planning regions, such as
upgrades that may be required in a third transmission planning
region and, if the transmission providers in the regions in which
the transmission facility is located agree to bear costs associated
with such upgrades, then the interregional cost allocation method
must include provisions for allocating the costs of such upgrades
among the beneficiaries in the transmission planning regions in
which the transmission facility is located.\827\
---------------------------------------------------------------------------
\827\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 657.
b. Requests for Rehearing or Clarification
697. Several petitioners argue that Principle 4 is inconsistent
with cost causation.\828\ Energy Future Coalition Group and AEP assert
that the Commission should require beneficiaries in adjoining regions
to contribute to the costs of new transmission facilities. They assert
that otherwise it is likely that intraregional transmission projects
that are in the public interest, and would benefit customers in
multiple regions, will fail.
---------------------------------------------------------------------------
\828\ See, e.g., Joint Petitioners; Energy Future Coalition
Group; and AEP.
---------------------------------------------------------------------------
698. Energy Future Coalition Group argues that the Commission
disregarded the beneficiary pays principle by providing that costs for
a transmission facility located in one region may be allocated to
beneficiaries in another region only if those beneficiaries volunteer
to pay those costs.\829\ Energy Future Coalition Group, Joint
Petitioners, and AEP add that the Commission's decision fails to
address the concern about free-riders. AEP argues that the Commission's
decision is contrary to its findings that the FPA and court precedent
\830\ require all rates to ``reflect to some degree the costs actually
caused by the customer who must pay them,'' and ``[t]o the extent that
a utility benefits from the costs of new facilities, it may be said to
have `caused' a part of those costs to be incurred.'' \831\ AEP argues
that this cost causation principle applies to all identifiable
beneficiaries, not only those who voluntarily agree to pay the costs
associated with the facilities. AEP further argues that the
Commission's policy results in unjust and unreasonable rates that
discriminate against a set of customers.
---------------------------------------------------------------------------
\829\ Energy Future Coalition Group at 9 (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 582).
\830\ AEP at 7 (citing Illinois Commerce Commission v. FERC, 576
F.3d 470 (7th Cir. 2009); K N Energy, Inc. v. FERC, 968 F.2d 1295,
1300 (D.C. Cir. 1992); Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361, 1369 (D.C. Cir. 2004); Sithe/Independent Power Partners,
L.P. v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002)).
\831\ AEP at 8 (quoting Illinois Commerce Commission v. FERC,
576 F.3d at 476).
---------------------------------------------------------------------------
699. Joint Petitioners further argue that it is arbitrary to follow
the beneficiary pays principle within a region, but not across regions,
when the Commission has declined to define what these regions should be
and when they may have little or no electrical significance. AEP makes
a similar argument. Energy Future Coalition Group and AEP also argue
that there will be a perverse incentive to create regional boundaries
for the purpose of evading cost responsibility for nearby transmission
facilities. AEP adds that the choice between a regional and an
interregional project configuration would make an enormous difference
with respect to cost allocation, but that there may be very little
difference in the distribution of benefits or the physical design of
the project.
700. Energy Future Coalition Group notes that the Commission held
that within a given region, costs of a new project built wholly within
the service territory of one transmission provider can be allocated to
beneficiaries throughout the region if there is a clear regional
benefit. It argues that this is directly analogous to the potential for
extraregional benefits from a regional transmission project and asserts
that the Commission unaccountably reaches the opposite conclusion as to
the possibility of broader interregional cost allocation for a regional
project with broader benefits.
701. Energy Future Coalition Group argues that the Commission can
ensure that the attenuated assessments of benefits are avoided by
providing that interregional planning and cost allocation are required
for a project located wholly within one region only when: (1) The
extraregional benefits are directly related to the proposed
transmission project, not to assumed electricity market reactions or
influences; (2) the identified extraregional benefits are enjoyed in an
adjacent planning region; and (3) the extraregional benefits are
similar in nature to the benefits for which costs are proposed to be
allocated within the region where the facility is proposed.\832\
---------------------------------------------------------------------------
\832\ Energy Future Coalition Group at 11.
---------------------------------------------------------------------------
702. Joint Petitioners suggest that to limit the stakeholder burden
of monitoring transmission planning in other regions, and in keeping
with the evidence of the broad benefits of extra high voltage
transmission, Regional Cost Allocation Principle 4 and Interregional
Cost Allocation Principle 4 should be limited to transmission projects
less than 345 kV. Joint Petitioners recommend that for projects at 345
kV and above, the Commission should expand its interregional
coordination requirements to require that a regional planning entity
notify its neighbors when it is considering such an extra high voltage
project. Joint Petitioners state that the neighboring transmission
planning region then could have an opportunity to participate in the
planning process through which the project's beneficiaries will be
determined or may conduct its own planning process to consider the
project. They suggest similar opportunities should be provided in the
regional planning process.
703. Similarly, AEP proposes that the Commission expand the scope
of ``interregional transmission facilities'' to include new facilities
located solely within a single region in certain circumstances, such as
where the facilities are extra high voltage facilities that provide
demonstrable benefits to the neighboring region.\833\ AEP adds that
identification of potential beneficiaries will be strictly limited to a
region that adjoins the region in which the facility will be located,
and would specifically exclude any region that does not have a direct
interconnection with the region in which the new facility is located.
AEP asserts that this approach addresses several of the Commission's
concerns and does not place any undue burden on stakeholders.\834\
---------------------------------------------------------------------------
\833\ AEP at 14.
\834\ AEP adds that the Commission should find that the
transmission planning provisions of the joint operating agreement
between PJM and MISO meet the requirements of the Final Rule for
interregional transmission coordination without the need to justify
the process in a compliance filing.
---------------------------------------------------------------------------
[[Page 32291]]
704. MISO argues that Cost Allocation Principle 4 should not
preclude an RTO from allocating to a withdrawing RTO member the cost of
eligible transmission upgrades located solely in the RTO and approved
before the withdrawal. It states that in recently accepting MISO's
tariff provisions regarding multi-value projects, the Commission
specifically found just and reasonable tariff provisions that authorize
allocating to a withdrawing transmission owner the cost of a multi-
value project approved before the withdrawal, although the associated
facility will be located only in a MISO state.
705. Vermont Agencies note that while Order No. 1000 states that it
will not authorize the allocation of costs of facilities located in one
region to entities located in another region, because Order No. 1000
does not define ``region'' it could be read to claim authority to force
market participants into a region where they will be subject to cost
allocation plans agreed upon by the participants in that region.\835\
---------------------------------------------------------------------------
\835\ Vermont Agencies at 9.
---------------------------------------------------------------------------
706. Finally, North Carolina Agencies state that while the
Commission approves Principle 4, the Commission also states that if
there are benefits of a new transmission project to a public or non-
public utility within a region that has no transmission arrangement
with the entity building the project, costs can still be allocated to
that utility if it is found to benefit from the project. According to
North Carolina Agencies, the Commission has committed error by not
recognizing this apparent contradiction in the foregoing statements, as
well as by stating that the costs of new transmission projects may be
allocated involuntarily to those that lack any sort of connection to
the transmission project in question.
c. Commission Determination
707. We affirm Regional and Interregional Cost Allocation Principle
4. Accordingly, we deny the arguments of those petitioners that ask us
to expand the scope of Cost Allocation Principle 4 to permit a
transmission planning region where a new transmission facility is
located to allocate costs of the facility unilaterally to a neighboring
region that benefits from it. Such arguments fail to take into account
the relationship between the Commission's cost allocation reforms and
the other reforms contained in Order No. 1000 and the need to balance a
number of factors to ensure that the reforms achieve the goal of
improved planning and cost allocation for transmission in interstate
commerce.
708. In Order No. 1000, the Commission acknowledged that its
approach may lead to some beneficiaries of transmission facilities
escaping cost responsibility because they are not located in the same
transmission planning region as the transmission facility. Nonetheless,
the Commission found this approach to be appropriate since Order No.
1000 establishes a closer link between regional transmission planning
and regional cost allocation, both of which involve the identification
of beneficiaries. In light of that closer link, the Commission found
that allowing one region to allocate costs unilaterally to entities in
another region would impose too heavy a burden on stakeholders to
actively monitor transmission planning processes in numerous other
regions, from which they could be identified as beneficiaries and be
subject to cost allocation. The Commission noted that if it expected
such participation, the resulting regional transmission planning
processes could amount to interconnectionwide transmission planning
with corresponding cost allocation, albeit conducted in a highly
inefficient manner. The Commission further explained that it is not
requiring either interconnectionwide transmission planning or
interconnectionwide cost allocation.\836\
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\836\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 660.
---------------------------------------------------------------------------
709. Moreover, the discussion above highlights the importance that
the ability to participate in the transmission planning and cost
allocation process has for the Commission's transmission planning
reforms. While the Commission concluded in Order No. 1000 that cost
allocation is not dependent on a preexisting contractual relationship,
we also think it is important that any entities that will be
responsible for costs have an opportunity to participate in the process
through which they will be allocated costs. This follows directly from
the requirement of Order No. 890 that transmission planning be open and
transparent. It also promotes a close link between transmission
planning and cost allocation and helps to ensure fairness, which
ultimately promotes successful transmission planning. Entities outside
of a region may not be capable of being full participants in each and
every region's transmission planning process in which they could
potentially be allocated transmission costs. Unilateral allocation of
costs to them thus could undermine rather than promote the linking of
cost allocation and transmission planning.
710. Energy Future Coalition Group, Joint Petitioners, and AEP
state that failing to revisit Cost Allocation Principle 4 does not
address the Commission's concerns about free riders. North Carolina
Agencies argue that the Commission's adoption of Cost Allocation
Principle 4 contradicts the Commission's finding that costs can still
be allocated to any entity that benefits from a new transmission
facility without a transmission arrangement. As noted above, the
Commission acknowledged in Order No. 1000 that its decision ``may lead
to some beneficiaries of transmission facilities escaping cost
responsibility because they are not located in the same transmission
planning region as the transmission facility.'' \837\ However, the
Commission's cost allocation reforms represent a significant advance
over current practices, and it is important to balance the possibility
that some beneficiaries could escape cost responsibility against the
larger goal of linking cost allocation with the transmission planning
process for the purpose of improving that process. Additionally, as
noted in our discussion of the need for the Commission's reforms,
transmission planning is more likely to succeed if it is understood in
advance how the costs of planned facilities will be allocated. While a
preexisting contract is not necessary to establish a cost allocation,
we believe that an ability to participate in the process in which costs
are allocated is important as it promotes the improved transmission
planning that Order No. 1000 seeks to achieve. The Commission
acknowledged in Order No. 1000 that some beneficiaries could escape
cost responsibility as a result of the decision not to allow costs to
be allocated outside the region in which a transmission facility is
located, but the implementation of any policy often requires one to
balance a number of considerations, which we believe Cost Allocation
Principle 4 does appropriately.
---------------------------------------------------------------------------
\837\ Id.
---------------------------------------------------------------------------
711. For these same reasons, we decline to adopt the suggestions
made by those petitioners that attempt to address the burden on
stakeholders to participate in several transmission planning regions,
by for example, limiting extraregional cost allocation to higher
voltage facilities or by requiring that costs be allocated only to
regions adjacent to the one in which a transmission facility is
located. While
[[Page 32292]]
we agree that these suggestions might mitigate the burden on some
stakeholders, we nevertheless are not convinced that they are
sufficient to ensure that the Commission is not through this rulemaking
proceeding effectively requiring interconnectionwide transmission
planning. In any event, nothing in Order No. 1000 would prohibit
regions from voluntarily agreeing to bear the costs for transmission
facilities located in neighboring regions and from which they receive a
benefit. Doing so is not inconsistent with Cost Allocation Principle
4.\838\
---------------------------------------------------------------------------
\838\ Id. PP 658-59.
---------------------------------------------------------------------------
712. We further disagree with petitioners that this determination
will result in arbitrary drawing of regional boundaries to avoid cost
allocation. In Order No. 890, the Commission determined that ``the
scope of a transmission planning region should be governed by the
integrated nature of the regional power grid and the particular
reliability and resource issues affecting individual regions.'' \839\
Consistent with that guidance, regions already have defined themselves
for purposes of transmission planning. The Commission appreciates that
these regional boundaries may change in response to Order No. 1000, but
any such changes will be subject to Commission review on compliance to
ensure that they continue to be appropriate. In response to Vermont
Agencies' concerns about entities being forced into regions against
their will, we note that in Order No. 1000, the Commission found that a
transmission planning region ``is one in which public utility
transmission providers, in consultation with stakeholders and affected
states, have agreed to participate in for purposes of regional
transmission planning and development of a single regional transmission
plan.'' \840\
---------------------------------------------------------------------------
\839\ Id. P 160 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 527).
\840\ Id. P 160 (emphasis added).
---------------------------------------------------------------------------
713. We agree with AEP that there can be cases where a project can
have similar transmission flow impacts whether it is configured
regionally or interregionally. However, we conclude that the regional
and interregional transmission planning and coordination requirements
of Order No. 1000 provide sufficient opportunities for analyzing the
potential benefits of new transmission facilities, whether regional or
interregional in configuration.
714. In response to MISO, we clarify that Cost Allocation Principle
4 does not preclude an RTO from allocating to a withdrawing RTO member
the cost of eligible transmission upgrades located solely in the RTO
and approved before the withdrawal pursuant to a Commission-approved
RTO agreement.
6. Whether To Establish Other Cost Allocation Principles
a. Final Rule
715. In Order No. 1000, the Commission stated that it did not
believe that any additional cost allocation principles were necessary
at that time.\841\
---------------------------------------------------------------------------
\841\ Id. P 705.
---------------------------------------------------------------------------
b. Requests for Rehearing
716. ELCON, AF&PA, and the Associated Industrial Groups argue that
Order No. 1000 should address whether the costs of new transmission
occasioned by low capacity factor resources should be allocated on a
capacity basis. They assert that the Commission devoted no substantive
consideration to this issue, and deferred it to the regional
transmission planning processes. ELCON, AF&PA, and the Associated
Industrial Groups assert that FERC provided no explanation for why this
issue is better addressed by regional planning agencies. For example,
they argue that allocating the fixed costs of transmission facilities
intended to transmit wind energy to load centers on a volumetric basis
inappropriately subsidies wind energy, which is inconsistent with
resource neutrality and economically efficient resource allocation.
Moreover, ELCON, AF&PA, and the Associated Industrial Groups argue that
allocating these costs on any basis other than a capacity basis would
unfairly penalize and significantly increase costs for those customers
that have invested in operational changes to minimize consumption
during system peak periods.
c. Commission Determination
717. We disagree with ELCON, AF&PA, and the Associated Industrial
Groups' assertion that the Commission dismissed their proposal for new
principles that would address cost allocation on a capacity basis
without explanation. In Order No. 1000, the Commission declined to
adopt additional principles proposed by commenters because the
Commission believed that to do so would limit the flexibility provided
to public utility transmission providers in proposing the appropriate
cost allocation method or methods for their transmission planning
region or pair of transmission planning regions.\842\ We continue to
believe this to be the case, and we therefore affirm the Commission's
decision on this issue.
---------------------------------------------------------------------------
\842\ Id.
---------------------------------------------------------------------------
E. Application of Cost Allocation Principles
1. Participant Funding
a. Final Rule
718. In Order No. 1000, the Commission found that participant
funding is permitted, but not as a regional or interregional cost
allocation method.\843\ The Commission explained that if proposed as a
regional or interregional cost allocation method, participant funding
would not comply with the regional or interregional cost allocation
principles adopted in Order No. 1000.\844\ The Commission explained,
however, that these principles do not in any way foreclose the
opportunity for a transmission developer, a group of transmission
developers, or one or more individual transmission customers to
voluntarily assume the costs of a new transmission facility.\845\
---------------------------------------------------------------------------
\843\ Id. P 723.
\844\ Id.
\845\ Id. P 724.
---------------------------------------------------------------------------
b. Requests for Rehearing or Clarification
719. Several petitioners request rehearing or clarification of the
Commission's finding that participant funding cannot be the regional or
interregional cost allocation method.\846\ Ad Hoc Coalition of
Southeastern Utilities states that, as a matter of policy, new long-
line transmission facilities that span utility service areas must be
supported by ascertainable demand, and that the most economically sound
way to determine what facilities should be built, and at what price, is
for those entities that will use the facilities to pay for them. ELCON,
AF&PA, and the Associated Industrial Groups argue that prohibiting
participant funding as a regional or interregional cost allocation
method creates a new free rider problem. According to them,
participants who, from an economic perspective, should be funding
transmission, and could do so most expeditiously, will now have an
incentive not to do so, because the cost will be allocated to other
more peripheral beneficiaries as part of the regional transmission
planning process.
---------------------------------------------------------------------------
\846\ See, e.g., Illinois Commerce Commission; ELCON, AF&PA, and
the Associated Industrial Groups; Arizona Cooperative; Ad Hoc
Coalition of Southeastern Utilities; and Southern Companies.
---------------------------------------------------------------------------
720. ELCON, AF&PA, and the Associated Industrial Groups argue that
the Commission's explanation of why participant funding should be
[[Page 32293]]
prohibited is both arbitrary and inconsistent when compared to
determinations made by the Commission in Order No. 1000 concerning
other cost allocation approaches. For instance, they state that the
Commission was willing to leave the decision of whether postage stamp
rate allocation is an appropriate cost allocation method to regional
planning entities. ELCON, AF&PA, and the Associated Industrial Groups
argue that Order No. 1000 subjects the two different cost allocation
methods to widely divergent standards of scrutiny with no explanation
as to why such differential treatment would be appropriate. They also
seek clarification that Order No. 1000 allows participant funding to be
used as the default for certain types of projects on a category basis
where participant funding best matches cost causation principles.
721. Arizona Cooperatives and Southwest Transmission are concerned
that Order No. 1000 does not recognize the benefits of participant
funding. For instance, Arizona Cooperatives and Southwest Transmission
state that under participant funding, the cost of associated
transmission is bundled with generation. If the bundled price is
excessive, then the project does not attract customers and an unworthy
investment is avoided.
722. Southern Companies argue that the Commission's treatment of
participant funding in Order No. 1000 is overly vague and unexplained.
They state that the Commission should refine its guidance on rehearing
to define ``participant funding'' more narrowly and in terms of the
issue that Order No. 1000 seeks to address, rather than categorically
excluding it. Southern Companies state the Commission should clarify
that participant funding is only impermissible as a cost allocation
method if there are identified beneficiaries and those beneficiaries
would receive non-trivial, direct benefits and would be expected to
participate in the facilities as a transmission customer or co-owner
but for others valuing the new transmission facility more and agreeing
to go ahead and support the project financially.
723. Southern Companies repeats arguments made above that the
Supreme Court held the FPA is premised on the concept of voluntary sale
and purchase of jurisdictional services and the courts have uniformly
applied cost causation principles only in the setting of relationships
where privity exists. Therefore, it asserts that participant funding
may well be the only cost allocation method or rate structure that is
lawful for new regional and/or interregional transmission projects as
envisioned by Order No. 1000. Southern Companies assert that without a
privity relationship between the developer of a project and those
expected to fund the project, there is no lawful basis upon which to
impose a rate, and no assurance that any rate would be in connection
with the provision of a jurisdictional service. Large Public Power
Council and Ad Hoc Coalition of Southeastern Utilities also state that
the Commission's rejection of participant funding confounds a basic
precept of the FPA that a utility's ability to recover its costs rests
on a contractual relationship with its customers.
724. Southern Companies assert participant funding is consistent
with cost causation and represents a proven-way of getting the costs of
such regional and/or interregional transmission facilities allocated,
paid and constructed on a timely basis.\847\ Southern Companies add
that given the Commission's objective to foster more development,
categorical ex ante exclusion of a cost allocation method that has a
proven track record of success does not reflect reasoned decision
making. Large Public Power Council also believes that the only
economically sound way to determine what facilities should be built,
and at what price, is to have those entities that will use the
facilities pay for them.
---------------------------------------------------------------------------
\847\ Southern Companies at 109 (citing Bryan K. Hill September
28, 2010 Affidavit at 31-32).
---------------------------------------------------------------------------
725. On the other hand, Transmission Dependent Utility Systems
commend the Commission's ruling that participant funding cannot be used
as a regional or interregional cost allocation method. Transmission
Dependent Utility Systems also request that the Commission reaffirm its
long-held policy prohibiting ``and'' pricing.\848\ Transmission
Dependent Utility Systems assert the Commission should confirm that any
limited use of participant funding in the future will be bound by the
Commission's same long-standing precedent.\849\
---------------------------------------------------------------------------
\848\ Transmission Dependent Utility Systems at 31 (citing
Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 694
n.111 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs.
] 31,160 (2004), order on reh'g, Order No. 2003-B, FERC Stats. &
Regs. ] 31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats.
& Regs. ] 31,190 (2005), aff'd sub. nom. Nat'l Ass'n of Regulatory
Utils. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007)).
\849\ Transmission Dependent Utility Systems at 31 (citing
Inquiry Concerning the Comm'n's Transmission Pricing Policy for
Transmission Services Provided by Pub. Utils. Under the Fed. Power
Act, 55 Fed. Reg. 55,031, FERC Stats. & Regs. ] 31,005, at 31,142-43
(1994), clarified, 71 FERC ] 61,195 (1995); Am. Elec. Power Co., 67
FERC ] 61,168 (1994)); see also Pennsylvania Elec. Co. v. FERC, 11
F.3d 207 (D.C. Cir. 1993).
---------------------------------------------------------------------------
c. Commission Determination
726. We affirm Order No. 1000's determination that participant
funding is permitted, but not as a regional or interregional cost
allocation method.\850\ We therefore continue to believe that if
proposed as a regional or interregional cost allocation method,
participant funding will not comply with the regional or interregional
cost allocation principles adopted above. We remain concerned that
reliance on participant funding as a regional or interregional cost
allocation method increases the incentive of any individual beneficiary
to defer investment in the hopes that other beneficiaries will value a
transmission project enough to fund its development. Because of this,
it is likely that some transmission facilities identified in the
regional transmission planning process as more efficient or cost-
effective solutions would not be constructed in a timely manner or
would not be constructed at all, adversely affecting ratepayers.
Moreover, reliance on participant funding as a regional or
interregional cost allocation method leaves a transmission developer
with no opportunity to allocate costs to beneficiaries identified in
the regional transmission planning process, even if the developer's
transmission facility is identified as a more efficient or cost-
effective solution and is selected in the regional transmission plan
for purposes of cost allocation. In light of this prospect, a
transmission developer may decline to propose such a transmission
facility in the regional transmission planning process.
---------------------------------------------------------------------------
\850\ See Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP
723-29.
---------------------------------------------------------------------------
727. The Commission rejected participant funding as a regional or
interregional cost allocation method because it does not comply with
the regional or interregional cost allocation principles set forth in
Order No. 1000. This is because participant funding by its nature does
not assess transmission project benefits in regional or interregional
terms. For this reason, it does not ensure that the allocation of costs
will be roughly commensurate with benefits, since its focus is limited
to transmission project participants rather than the regional or
interregional impact of a transmission project. Many petitioners
describe what they consider to be advantages of participant funding,
but these descriptions and the arguments based on them do not show how
participant funding satisfies the
[[Page 32294]]
specific requirements or policy goals of Order No. 1000.
728. However, as Order No. 1000 made clear, we are not finding that
participant funding leads to improper results in all cases. For
example, a transmission developer may propose a project to be selected
in the regional transmission plan for purposes of regional cost
allocation but fail to satisfy the transmission planning region's
criteria for a transmission project selected in the regional
transmission plan for purposes of cost allocation. Under such
circumstances, the developer could either withdraw its transmission
project or proceed to ``participant fund'' the transmission project on
its own or jointly with others. In addition, it is possible that the
developer of a facility selected in the regional transmission plan for
purposes of cost allocation might decline to pursue regional cost
allocation and, instead, rely on participant funding. Moreover, nothing
in Order No. 1000 forecloses the opportunity for a transmission
developer, a group of transmission developers, or one or more
individual transmission customers to voluntarily assume the costs of a
new transmission facility. Accordingly, Order No. 1000 does not
prohibit or, as Southern Companies assert, ``categorically'' exclude
the use of participant funding.
729. The Commission nowhere intended to suggest that participant
funding has no place in the development of transmission infrastructure.
As noted by Southern Companies, participant funding can result in
timely construction of transmission facilities in many circumstances.
Transmission developers who see particular advantages in participant
funding remain free to use it on their own or jointly with others. This
simply means that they would not be pursuing regional or interregional
cost allocation. ELCON, AF&PA, and the Associated Industrial Groups do
not explain what they mean by the use of participant funding ``as the
default for certain types of projects,'' \851\ and we are not persuaded
that the type of transmission project involved affects the ability of
participant funding to satisfy the cost allocation principles of Order
No. 1000.
---------------------------------------------------------------------------
\851\ ELCON, AF&PA, and the Associated Industrial Groups at 16.
---------------------------------------------------------------------------
730. The Commission did not state in Order No. 1000 that entities
who support participant funding must show that it is uniquely the cost
allocation method that follows ``but for'' cost causation principles,
as ELCON, AF&PA, and the Associated Industrial Groups contend. The
Commission simply stated that entities who had argued that it was such
a method had not demonstrated that this was the case and that,
moreover, the contention was at odds with existing precedent on cost
causation.\852\
---------------------------------------------------------------------------
\852\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 726.
---------------------------------------------------------------------------
731. Southern Companies maintain that participant funding means
different things to different people and that the Commission should
define it more narrowly for purposes of Order No. 1000. However,
Southern Companies do not describe the different meanings of
participant funding that they have in mind, and we therefore do not
know what further refinements it believes would be in order.\853\ The
Commission stated in Order No. 1000 that ``[u]nder a participant
funding approach to cost allocation, the costs of a transmission
facility are allocated only to those entities that volunteer to bear
those costs.'' \854\ In addition, the Commission noted in Order No.
1000 that the Proposed Rule cited to a number of concrete examples of
the participant funding approach.\855\ We think that this provides
sufficient guidance on the meaning of participant funding for purposes
of Order No. 1000.
---------------------------------------------------------------------------
\853\ Southern Companies only state that the Commission's
``categorical exclusion'' of participant funding had created a need
to state specifically in Order No. 1000 (in response to Entergy)
that prohibition of participant funding as a regional cost
allocation mechanism ``is not intended to modify existing pro forma
OATT transmission service mechanisms for individual transmission
service requests or requests for interconnection service.'' Southern
Companies at 106 (quoting Order No. 1000, FERC Stats. & Regs. ]
31,323 at P 729). Southern Companies state that specifying this was
important because long-term firm transmission service is a form of
participant funding that addresses free rider issues, and this
demonstrates the need for greater clarity on what the Commission is
prohibiting. Id. However, Order No. 1000 does not create a
``categorical exclusion'' of participant funding, only an exclusion
of the use of participant funding as a regional cost allocation
method. We therefore do not see how the continued use of existing
mechanisms for individual transmission service requests affects our
conclusions on the use of participant funding for new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. As a result, we do not see the need for further
refinements in the meaning of participant funding for purposes of
Order No. 1000. We think that the two very different contexts at
issue in Southern Companies' argument--firm transmission service
requests and regional transmission planning--make such analogies
inappropriate.
\854\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 486
n.375 (citing Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 128).
\855\ Id. See Proposed Rule, FERC Stats. & Regs. ] 32,660 at P
128.
---------------------------------------------------------------------------
732. We disagree that precluding participant funding as a regional
and interregional cost allocation method creates a new free rider
problem by creating an incentive for what ELCON, AF&PA, and the
Associated Industrial Groups describe as entities who should be funding
a transmission project not to fund it in the hope of an allocation to
additional beneficiaries. The primary goal of Order No. 1000's cost
allocation principles is to ensure that costs of regional transmission
facilities selected in a regional transmission plan for purposes of
cost allocation are allocated to beneficiaries in the region roughly
commensurate with the benefits that they receive. It is unlikely that
entities which benefit from such transmission facilities would decline
to fund them. Moreover, we disagree with the argument that preclusion
of participant funding as a regional or interregional cost allocation
method creates an incentive not to develop a transmission project. On
the contrary, a transmission developer will have the option of using
participant funding or submitting its transmission project for
evaluation in the regional transmission planning process to be selected
for regional or interregional cost allocation. If its transmission
project is selected in the regional transmission plan for purposes of
cost allocation, the transmission developer would be able to allocate
costs to beneficiaries consistent with the relevant cost allocation
method, an opportunity that not only encourages development but also
promotes development of more efficient or cost-effective transmission
solution to regional and interregional transmission needs.
733. We think that this point helps illuminate why participant
funding does not constitute an appropriate regional or interregional
cost allocation method. Entities that might develop a transmission
project through participant funding remain free to do so. However,
exclusive reliance on such an approach creates an incentive not to
consider potential regional or interregional transmission needs. It
thus is not a method that is tailored to promote better regional and
interregional transmission planning.
734. We deny Southern Companies' request for clarification on the
situations in which participant funding should be impermissible.
Southern Companies asserts that participant funding should only be
impermissible if there are identified beneficiaries and those
beneficiaries would receive non-trivial, direct benefits and would be
expected to participate in the facilities as a transmission customer or
co-owner but for others valuing the new transmission facility more and
agreeing to go ahead and support the project financially. The
[[Page 32295]]
focus of the cost allocation reforms of Order No. 1000 is on
transmission projects that are selected in the regional transmission
plan for purposes of cost allocation, not the circumstances under which
voluntary use of participant funding is appropriate.
735. We disagree with ELCON, AF&PA, and the Associated Industrial
Groups who see inconsistency in the Commission's willingness to allow
consideration of postage stamp rates as a cost allocation method, but
not participant funding. As we noted above, Order No. 1000 found that a
postage stamp cost allocation method may be appropriate where all
customers within a specified transmission planning region are found to
benefit from the use or availability of a transmission facility or
class or group of transmission facilities, especially if the
distribution of benefits associated with a class or group of
transmission facilities is likely to vary considerably over the long
depreciation life of the transmission facilities amid changing power
flows, fuel prices, population patterns, and local economic
considerations.\856\ Accordingly, unlike participant funding, if such a
showing can be made, a postage stamp cost allocation would meet Cost
Allocation Principle 1's requirement that costs be allocated roughly
commensurate with benefits. Participant funding, on the other hand, is
incapable of meeting the regional or interregional cost allocation
principles set forth in Order No. 1000, because by its nature it is not
a cost allocation method that accounts for potential regional or
interregional benefits.
---------------------------------------------------------------------------
\856\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 605.
---------------------------------------------------------------------------
736. We clarify, in response to Transmission Dependent Utility
System's request, that Order No. 1000 did not address or change the
Commission's policy on ``and'' pricing.\857\ Order No. 1000 applies
only to transmission projects that are selected in the regional
transmission planning process for purposes of cost allocation.
Participant funding cannot be the regional or interregional cost
allocation method under Order No. 1000. Therefore, if a project's costs
are allocated under a participant funding method, by definition, it was
not selected in the regional transmission planning process for purposes
of cost allocation.\858\
---------------------------------------------------------------------------
\857\ Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
\858\ The Commission made clear in Order No. 1000 that
transmission facilities that are selected in the regional
transmission plan for purposes of cost allocation may not comprise
all of the transmission facilities in the regional transmission
plan, and therefore, participant funded facilities may be included
in the regional transmission plan for other purposes. Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 63.
---------------------------------------------------------------------------
737. Lastly, a number of petitioners argue that participant funding
is the form of cost allocation that corresponds to what they assert is
a requirement that cost allocation be premised on a contractual
relationship. As we explained above,\859\ we reject the interpretation
of the FPA that petitioners have offered, specifically that the FPA
requires a contractual relationship before rates can be assessed.
Contracts do not define or limit the benefits that a transmission
customer receives from the entire transmission grid, which the courts
have recognized in finding that the customer relationship is to the
transmission grid as a whole, rather than the dictates of
contracts.\860\ Therefore, petitioners' arguments that the Commission's
finding that participant funding cannot be the regional or
interregional cost allocation method are unfounded.
---------------------------------------------------------------------------
\859\ See discussion supra at section 0.
\860\ See discussion supra at section 0.
---------------------------------------------------------------------------
F. Other Cost Allocation Issues
1. Final Rule
738. In Order No. 1000, the Commission reiterated the approach it
took in Order No. 890, requiring that generation, demand resources, and
transmission be treated comparably in the regional transmission
planning process.\861\ Also, the Commission stated that while the
consideration of non-transmission alternatives to transmission
facilities may affect whether certain transmission facilities are in a
regional transmission plan, the Commission concluded that the issue of
cost recovery for non-transmission alternatives was beyond the scope of
the cost allocation reforms adopted in Order No. 1000, which are
limited to allocating the costs of new transmission facilities.\862\
---------------------------------------------------------------------------
\861\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 779.
\862\ The Commission also recognized that, in appropriate
circumstances, alternative technologies may be eligible for
treatment as transmission for ratemaking purposes. Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 779 & n.563.
---------------------------------------------------------------------------
2. Requests for Rehearing or Clarification
739. California State Water Project argues that on rehearing the
Commission should require all public utilities to exempt sponsors of
demand-based transmission alternatives from Order No. 1000's benefits-
based cost allocation, as well as apply time-sensitive cost allocation.
Specifically, it argues that customers investing in demand-based non-
transmission alternatives and sponsors of demand-based transmission
alternatives should not be subject to benefits-based cost allocation
that in effect imposes discriminatory double billing for both the
transmission alternative provided and for unused transmission
automatically deemed to provide benefits. Moreover, it adds that the
Commission has stated that customers' ability to modify their behavior
in response to price signals benefits the entire grid and is among the
best means of holding down costs and countering market power.\863\
---------------------------------------------------------------------------
\863\ California State Water Project at 18 (quoting Order No.
719, FERC Stats. & Regs. ] 31,281 at P 41).
---------------------------------------------------------------------------
740. California State Water Project also argues that the rule
unduly discriminates against demand-based non-transmission alternatives
as it stressed the need for clear cost allocation to promote
transmission construction, yet declined to consider compensation and
cost allocation for demand-based non-transmission alternatives.
California State Water Project states that in the Energy Policy Act of
2005 Congress declared that the national policy of the United States is
to promote demand response and to eliminate unnecessary barriers to
demand response.\864\ It also states that the Commission followed up on
this policy in Order No. 719, stating that ``[a]ny reforms must ensure
that demand response resources are treated on a basis comparable to
other resources.'' \865\ California State Water Project adds that under
the FPA the Commission also must not permit undue discrimination
against such resources. It notes that the Commission has applied this
principle to avert undue discrimination against various kinds of
resources, such as the measures to remedy undue discrimination against
non-incumbent transmission developers in Order No. 1000.\866\
---------------------------------------------------------------------------
\864\ California State Water Project at 9-10 (citing Energy
Policy Act of 2005, Pub. L. 109-58, Sec. 1252(f), 119 Stat. 594
(2005)).
\865\ California State Water Project at 10 (quoting Order No.
719, FERC Stats. & Regs. ] 31,281 at P 14).
\866\ California State Water Project at 11 (citing Order No.
888, FERC Stats. & Regs. ] 31,036 at 31,669; Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 229).
---------------------------------------------------------------------------
741. California State Water Project recommends that the Commission
[[Page 32296]]
incorporate benchmarks or metrics to support periodic evaluation of its
success or failure in achieving nondiscriminatory promotion of both
physical transmission upgrades and non-transmission alternatives. It
argues that incorporating such benchmarks will ensure that the
Commission and all concerned undertake appropriate improvements on a
timely basis.
742. Transmission Dependent Utility Systems point out that in their
comments during the Order No. 1000 proceeding, they requested that the
Commission align local, regional and interregional planning and cost
allocation processes and methods with formula rate protocols because
those who pay the costs of needed new transmission infrastructure
should not learn about projects for the first time in formula rate
updates. In particular, Transmission Dependent Utility Systems argue
that to the extent project upgrade costs are not discussed in the
planning processes with stakeholders, a separate FPA section 205 filing
must be made for recovery of these costs. It argues that most public
utility transmission providers have incentive rates and that the
formula rate annual update process provides only limited opportunity to
review and challenge costs included in the formula rate update filing.
Transmission Dependent Utility Systems argue that their requested link
between formula rate cost recovery and the local and regional planning
and interregional coordination processes is within the scope of issues
raised in this proceeding because it is a safeguard needed to ensure
that load-serving customers, which pay for the costs of transmission
upgrades, have a meaningful role in the development of regional and
interregional projects and the allocation of the costs of those
projects. Transmission Dependent Utility Systems further assert that
Order No. 1000 failed to address this issue in a manner that comports
with reasoned decision-making.\867\
---------------------------------------------------------------------------
\867\ Transmission Dependent Utility Systems at 31 (citing K N
Energy Inc. v. FERC, 968 F.2d 1295, 1303)).
---------------------------------------------------------------------------
743. Dayton Power and Light requests clarification that the
Commission will issue a separate order on remand from the Seventh
Circuit on Opinion No. 494 \868\ in the near future that will specify a
cost allocation mechanism for new high voltage facilities that complies
with the Order No. 1000 principles.\869\ Dayton Power and Light states
that failing to issue an order on remand would lead to renewed
litigation a year from now to address the same issues using
substantially the same evidence that is already before the Commission
for decision and waste the resources of PJM members, PJM, and the
Commission and its staff.
---------------------------------------------------------------------------
\868\ PJM Interconnection, L.L.C., 130 FERC ] 61,052 (2010).
\869\ Dayton Power and Light at 2, 4 (citing Illinois Commerce
Commission v. FERC, 576 F.3d 470).
---------------------------------------------------------------------------
744. Dayton Power and Light urges the Commission to state
explicitly that the use of the Distribution Factor analysis complies
with the Order No. 1000 cost allocation principles. In support, Dayton
Power and Light states that PJM has used distribution factor analysis
to allocate the costs of new PJM facilities operating at less than 500
kV without question or challenge.
3. Commission Determination
745. We deny California State Water Project's arguments and affirm
Order No. 1000's determination that cost allocation for non-
transmission alternatives is beyond the scope of this proceeding, which
is limited to allocating the costs of new transmission facilities. In
response to California State Water Project's suggestions regarding
time-sensitive rates and the establishment of benchmarks, we affirm
Order No. 1000, and therefore, will not establish minimum requirements
governing which non-transmission alternatives should be considered or
the appropriate metrics to measure non-transmission alternatives
against transmission alternatives. We continue to believe that those
considerations are best managed among the stakeholders and the public
utility transmission providers participating in the regional
transmission planning process.\870\
---------------------------------------------------------------------------
\870\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 155.
---------------------------------------------------------------------------
746. We deny Transmission Dependent Utility Systems' request that
we address a link between formula rates and cost allocation as beyond
the scope of this proceeding. As we note above, and as we found in
Order No. 1000, we are not addressing cost recovery issues here.\871\
In any event, we disagree with Transmission Dependent Utility Systems'
premise that those who pay for project upgrade costs that are selected
in a regional transmission plan for purposes of cost allocation under
the provisions of Order No. 1000 may learn about these costs for the
first time when flowed through a formula rate, when there would be only
a limited opportunity to review the costs.\872\ As is clear in Order
No. 1000, any entity can participate in the regional transmission
planning process and costs will be allocated only for those regional
and interregional transmission facilities that have been selected in
the regional transmission plan for purposes of cost allocation.\873\
Therefore, Transmission Dependent Utility Systems will have a
meaningful opportunity to participate in the development of regional
and interregional transmission projects and the allocation of the costs
of those transmission projects, whether or not these are incorporated
into formula rates, through their ability to participate in the
regional transmission planning process. Additionally, as noted above,
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.
---------------------------------------------------------------------------
\871\ Id. P 563.
\872\ In any event, we note that when ratepayers learn of other
formula costs is outside the scope of this proceeding.
\873\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 503.
---------------------------------------------------------------------------
747. In response to Dayton Power and Light's request that the
Commission find that the use of the distribution factor analysis
complies with Order No. 1000 cost allocation principles, we reiterate
what the Commission said in Order No. 1000 in response to commenters
making similar arguments. We decline to prejudge whether any existing
cost allocation method complies with the requirements of Order No.
1000. To the extent that Dayton Power and Light believes that to be the
case in its transmission planning region, it can take such a position
during the development of compliance proposals and during Commission
review of compliance filings.\874\ Last, with respect to the timing
concerns Dayton Power and Light describes regarding the relationship
between our order on remand from the U.S. Court of Appeals for the
Seventh Circuit on Opinion No. 494 and the development of an Order No.
1000-compliant cost allocation method in PJM, the Commission has since
issued an order in the Opinion No. 494 proceeding.\875\
---------------------------------------------------------------------------
\874\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 565.
\875\ PJM Interconnection, L.L.C., 138 FERC ] 61,230 (2012).
---------------------------------------------------------------------------
V. Compliance and Reciprocity
A. Compliance
1. Final Rule
748. The Commission required that each public utility transmission
provider must submit a compliance filing within twelve months of the
[[Page 32297]]
effective date of Order No. 1000 revising its OATT or other document(s)
subject to the Commission's jurisdiction as necessary to demonstrate
that it meets the local and regional transmission planning and cost
allocation requirements set forth in Order No. 1000. The Commission
also required each public utility transmission provider to submit a
compliance filing within eighteen months of the effective date of Order
No. 1000 revising its OATT or other document(s) subject to the
Commission's jurisdiction as necessary to demonstrate that it meets the
requirements set forth therein with respect to interregional
transmission coordination procedures and an interregional cost
allocation method or methods.\876\
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\876\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 792.
---------------------------------------------------------------------------
2. Requests for Rehearing or Clarification
749. Duke requests that the Commission rule on requests for
clarification as soon as possible before issuance of an Order No. 1000
rehearing order so that stakeholders' compliance efforts are not
interrupted or entirely disrupted. MISO requests that the Commission
clarify that RTOs and ISOs are not required to make any changes to
their tariffs or processes in connection with the participation of non-
jurisdictional entities in regional or interregional planning and cost
allocation processes. According to MISO, requiring the development of a
regional plan and cost allocation process with an entity that has no
such corresponding mandate is unreasonable, and it may not be possible
to comply with such a requirement because compliance would depend
entirely on the desire of such non-jurisdictional entities to
coordinate. MISO states that at most, the Commission should require
that Commission-jurisdictional entities engage in a good faith effort
at regional coordination, planning, and cost allocation with non-
jurisdictional entities.
750. NextEra seeks clarification that generator tie line owners
that have OATTs on file can seek waiver of compliance with Order No.
1000 requirements, as the Commission has previously found that such
lines are not integrated with the regional transmission grid for
ratemaking purposes. It suggests that there may be confusion as to
whether such tie line owners can seek waiver because of use of the word
``and'' rather than ``or'' when Order No. 1000 states that entities
must seek waivers of Order Nos. 888, 889, and 890. NextEra contends
that if the Commission intended to mean ``or,'' then the vast majority
of tie line owners would not be subject to Order No. 1000.\877\ It also
urges the Commission to adopt a broad-based waiver that focuses on the
nature of a radial line, which it argues would be consistent with the
intent of the transmission planning process. NextEra argues that the
fact that such tie lines are not integrated in the transmission grid
should not be ignored. It states that the nature of a radial line does
not change simply because one tie line owner may provide
interconnection and transmission service to affiliates and have waivers
from Order Nos. 888, 889, and 890 while another may provide the same
service under an OATT to non-affiliates. NextEra states further that no
generation tie lines should be required to participate in the regional
transmission planning process unless they voluntarily choose to do
so.\878\
---------------------------------------------------------------------------
\877\ NextEra at 16.
\878\ NextEra at 17 (citing Southern Cal. Edison Co., 117 FERC ]
61,103 (2006); Mansfield Mun. Elec. Dept. v. New England Power Co.,
97 FERC ] 61,134 (2001)).
---------------------------------------------------------------------------
3. Commission Determination
751. In response to Duke, we believe that addressing the requests
for clarification of Order No. 1000 in this order is appropriate. Many
of the requests for clarification are linked with requests for
rehearing and are thus best addressed in the same order. Moreover, the
Commission considered the need for providing timely clarifications in
issuing this order now, and we believe that its issuance now allows
stakeholders adequate time to address these clarifications in their
compliance processes.
752. We clarify for MISO that a public utility transmission
provider will not be deemed out of compliance with Order No. 1000 if it
demonstrates that it made a good faith effort, but was ultimately
unable, to reach resolution with neighboring non-public utility
transmission providers on a regional transmission planning process,
interregional transmission coordination procedures, or a regional or
interregional cost allocation method.
753. In response to NextEra, we clarify that Order No. 1000's
determination that it ``applies to public utilities that own, control
or operate interstate transmission facilities other than those that
have received waiver of the obligation to comply with Order Nos. 888,
889, and 890'' \879\ was meant to provide assurance to those entities
that have existing waivers of those three rules that they would not
also have to seek waiver of Order No. 1000 in order to obtain waiver
from it. This is consistent with the approach the Commission took to
waivers in Order No. 890.\880\ This determination, however, was not
meant to affect the ability of an entity that does not have a waiver to
seek one. The Commission will entertain requests for waiver of Order
No. 1000 on a case-by-case basis from any entity, including a
generation tie line owner, that believes it meets the criteria for such
waiver, which the Commission made clear in Order No. 1000 remains
unchanged from that used to evaluate requests for waiver under Order
Nos. 888, 889, and 890.\881\
---------------------------------------------------------------------------
\879\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 832.
\880\ Order No. 890, FERC Stats. & Regs. ] 31,241 at n.105
(``The Commission clarifies that existing waivers of the obligation
to file an OATT or otherwise offer open access transmission service
in accordance with Order No. 888 shall remain in place. The reforms
to the pro forma OATT adopted in this Final Rule therefore do not
apply to transmission providers with such waivers, although we
expect those transmission providers to participate in the regional
planning processes in place in their regions, as discussed in more
detail in section V.B. Whether an existing waiver of OATT
requirements should be revoked will be considered on a case-by-case
basis in light of the circumstances surrounding the particular
transmission provider.''); see also Order No. 890-A, FERC Stats. &
Regs. ] 31,261 at P 36.
\881\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 832.
---------------------------------------------------------------------------
B. Reciprocity
1. Final Rule
754. In Order No. 1000, the Commission found that to maintain a
safe harbor tariff, a non-public utility transmission provider must
ensure that the provisions of that tariff substantially conform, or are
superior, to the pro forma OATT as it has been revised by Order No.
1000.\882\ The Commission stated that it was encouraged that, based on
the efforts that followed Order No. 890, both public utility and non-
public utility transmission providers collaborate in a number of
regional transmission planning processes.\883\ Therefore, the
Commission did not believe it was necessary to invoke its authority
under FPA section 211A, which gives it authority to require non-public
utility transmission providers to provide transmission services on a
comparable and not unduly discriminatory or preferential basis.\884\
However, the Commission stated that if it finds on the appropriate
record that non-public utility transmission providers are not
participating in the transmission planning and cost allocation
processes required by Order
[[Page 32298]]
No. 1000, the Commission may exercise its authority under FPA section
211A on a case-by-case basis.\885\ The Commission also emphasized that
it is not modifying the scope of the reciprocity provision as
established in Order No. 890.\886\ However, the Commission noted that
it expects all public and non-public utility transmission providers in
an existing regional transmission planning process comprised of both
public and non-public utility transmission providers to participate in
the transmission planning and cost allocation processes set forth in
Order No. 1000. The Commission also noted that those non-public utility
transmission providers that take advantage of open access under an
OATT, including the OATT's new provisions for improved transmission
planning and cost allocation, should be expected to follow the same
requirements as public utility transmission providers.\887\
---------------------------------------------------------------------------
\882\ Id. P 815.
\883\ Id.
\884\ Id.
\885\ Id.
\886\ Id. P 816.
\887\ Id. P 818.
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2. Requests for Rehearing or Clarification
755. Petitioners request rehearing of Order No. 1000's reciprocity
requirement, arguing that the Commission is changing the scope of the
principle of reciprocity under Order Nos. 888 and 890. For example,
Large Public Power Council states that reciprocity as initially
conceived in Order No. 888 was a matter of fundamental fairness. It
states that this concept was clarified in Order No. 2004-A, where the
Commission found that service provided by a non-public utility
transmission provider did not have to be identical to the service
provided by an investor-owned utility, only comparable to the service
the non-public utility would receive for its own purposes. Large Public
Power Council explains that Order No. 1000 appears to hold that a non-
public utility's obligation to provide reciprocal service outside a
safe harbor tariff includes an obligation to participate in the
planning and cost allocation processes implemented pursuant to Order
No. 1000. Large Public Power Council states that including these
planning and cost allocation obligations within a non-public utility's
reciprocity obligations would modify the scope of reciprocity, and thus
requests that the Commission clarify whether this is its intention.
756. Likewise, National Rural Electric Coops state that it appears
that the Commission misstated the reciprocity requirement in Order No.
1000 when it stated in paragraph 819 that ``the non-public utility
transmission provider that owns, controls or operates transmission
facilities must provide comparable transmission service that it is
capable of providing on its own system.'' \888\ They assert that under
the Commission's existing reciprocity requirement, a non-public utility
transmission provider is not obligated to provide such service, because
a public utility transmission provider is not obligated to refuse to
provide service if a non-public utility transmission provider does not
reciprocate. Rather, they point out that there are three alternatives
available to non-public utilities to meet the reciprocity requirement,
including obtaining a waiver from, or entering into a bilateral
agreement with, the public utility transmission provider from which the
non-public utility seeks service, and that providing service under a
safe harbor tariff is only one alternative. National Rural Electric
Coops state that only a few non-public utilities have Commission-
approved reciprocity tariffs and significant disputes could arise from
the unintentional language in Order No. 1000. They state that
clarification would help to minimize controversies over the scope of
non-public utilities' obligations with respect to regional planning and
cost allocation, and would be consistent with the Commission's
statement that it is not proposing any changes to the reciprocity
provision of the pro forma OATT or any other document.
---------------------------------------------------------------------------
\888\ National Rural Electric Coops at 5-6 (quoting Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 819).
---------------------------------------------------------------------------
757. Sacramento Municipal Utility District also states that by
asserting that all non-public utilities must abide by Order No. 1000's
transmission planning and cost allocation provisions if they take open
access service, the Commission both: (1) Eviscerates the waiver option
expressly contemplated under Order Nos. 888 and 890 and (2) creates an
automatic trigger directly at variance with the principle that non-
public utilities must reciprocate if asked to do so. Sacramento
Municipal Utility District points out that Order Nos. 888 and 890
unambiguously require safe harbor candidates to adopt tariffs that
match or exceed the terms of the pro forma OATT. It argues, however,
that the Commission's interpretation in Order No. 1000 that non-public
utilities without safe harbor tariffs that take service under open
access tariffs also are automatically bound to follow the transmission
planning and cost allocation provisions of Order No. 1000 improperly
conflates the safe harbor tariff provisions found in Order Nos. 888 and
890 since markedly different reciprocity requirements apply when a non-
public utility does not employ a safe harbor tariff.
758. Sacramento Municipal Utility District further argues that the
Commission's longstanding policy has been that reciprocity under Order
Nos. 888 and 890 only obligates the non-public utility to provide
transmission service to individual public utility transmission
providers requesting reciprocity as a condition of obtaining their
transmission service if a non-public utility has not sought a ``safe-
harbor'' tariff.\889\ Sacramento Municipal Utility District argues that
the actual provisions of Order Nos. 888 and 890 make clear that a
reciprocity obligation is not automatic, is purely bilateral and
applies only to the transmission provider that asks the non-public
utility to reciprocate.\890\ Thus, Sacramento Municipal Utility
District states that the Commission's determination that the act of
taking service from a public utility with a regional cost allocation
plan in its open access tariff automatically triggers the non-public
utility's reciprocity obligation under Order Nos. 888 and 890
constitutes an arbitrary and unexplained departure from the policies
established in those orders.\891\
---------------------------------------------------------------------------
\889\ Sacramento Municipal Utility District at 3.
\890\ Sacramento Municipal Utility District at 18 (citing
Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Serv. By Pub. Utils; Recovery of
Stranded Costs by Pub. Utils. And Transmitting Utils., Order No.
888-A, FERC Stats. & Regs. ] 31,048, at P 30, 180-81(1997)).
\891\ Sacramento Municipal Utility District at 3 (citing FCC v.
Fox Television Stations, Inc., 129 S. Ct. 1800, 1811 (2009); Greater
Boston Television Corp. v. FCC, 444 F.2d 841, 952 (D.C. Cir. 1970),
cert. denied, 403 U.S. 923 (1971)).
---------------------------------------------------------------------------
759. Bonneville Power further argues that the Commission is
inappropriately attempting to regulate Bonneville Power and other non-
public utility transmission providers under section 206 of the FPA. In
support, Bonneville Power asserts that the Commission's action is more
extreme than its attempt to impose refund liability on non-public
utilities in, for example, BPA v. FERC.\892\ Bonneville Power contends
that in that case, the court held the Commission lacked refund
authority over non-public utilities that participated in a power market
established by a public utility. Bonneville Power argues that the
Commission is similarly imposing cost responsibility on non-public
utilities under section 206 absent statutory authority to do so.
Bonneville Power contends that if the Commission denies
[[Page 32299]]
clarification that the regional planning process determination would
not be binding on Bonneville Power and that instead, it and
transmission developers could use the cost allocation analysis as input
to their negotiations and other required statutory processes, then the
Commission is directly regulating Bonneville Power by not allowing
Bonneville Power to follow its own statutory authority in implementing
cost allocation in place of the Commission's policy adopted under
section 206, which the Commission cannot do.
---------------------------------------------------------------------------
\892\ Bonneville Power at 17 (citing BPA v. FERC, 422 F.3d 908,
921 (9th Cir. 2005)).
---------------------------------------------------------------------------
760. Sacramento Municipal Utility District argues that the
Commission lacks the authority to mandate regional transmission
planning and therefore it cannot attach an obligation to accept the
cost allocation agreement negotiated under a regional transmission
planning process that the non-public utility was not mandated to join.
Sacramento Municipal Utility District therefore contends that since
non-public utilities under section 201(f) are not subject to section
205 and 206, they cannot be required as a condition of reciprocity to
accept cost allocation agreements that the Commission has no authority
to impose even on public utilities.
761. Sacramento Municipal Utility District states that when a non-
public utility takes service from a jurisdictional public utility, it
will pay a tariff rate approved by the Commission, and a reciprocity
provision is simply unnecessary to ensure proper cost recovery.
Sacramento Municipal Utility District argues that if the non-public
utility takes no service from a transmission provider that has
constructed a new facility approved by a regional transmission planning
body, and the costs of that facility are not properly included in the
rates of other transmission providers from whom the non-public utility
does take service, the reciprocity provision should be completely
inapplicable.
762. Moreover, Sacramento Municipal Utility District argues that
cost allocation is not a transmission service so that a non-public
utility requesting only transmission service can be deemed to have
reciprocated only by participating in regional cost allocation.
Similarly, Bonneville Power contends that the Commission should not
condition a non-jurisdictional transmitting utility's ability to
receive transmission service from a public utility on the non-
jurisdictional utility's inclusion of Order No. 1000's planning and
cost allocation reforms in its own tariff because the provisions of
Order No. 1000 go well beyond the basic provision of transmission
service and are not the type of provisions that reasonably fall within
the reciprocity construct.
763. Edison Electric Institute seeks clarification that section 6
of the OATT, which codifies the reciprocity requirement, enables a
public utility to refuse transmission service to unregulated
transmitting utilities that refuse to participate in regional
transmission planning and cost allocation processes. Furthermore,
Edison Electric Institute seeks clarification that, to satisfy the
reciprocity requirements, unregulated transmitting utilities must
fulfill each of the compliance requirements imposed on public
utilities. If unregulated transmitting utilities do not, then Edison
Electric Institute argues that the Commission should clarify that they
have failed to offer the ``comparable'' service required under section
6 of the OATT.
764. Large Public Power Council seeks clarification that the
Commission did not intend that it would enforce reciprocity tariff
provisions itself. Large Public Power Council states that if the
Commission does intend to enforce the reciprocity provisions itself,
Large Public Power Council seeks rehearing. Large Public Power Council
argues that to date, the Commission has not intimated that it has
authority to enforce these provisions with respect to a non-public
utility, which is consistent with case law finding that a non-public
utility's involvement in Commission-jurisdictional service does not
authorize the Commission to regulate the non-public utility.
765. Other petitioners argue that the Commission does not have
authority under section 211A to compel a non-public utility
transmission provider to participate in planning or pay for regional or
interregional transmission projects.\893\ For instance, Large Public
Power Council asserts that section 211A makes it plain that the
Commission's authority is limited to compelling a non-public utility to
provide transmission service at rates and on terms and conditions that
are essentially inward looking. As such, Large Public Power Council
contends that the Commission cannot redefine the terms under which
service is to be provided under section 211A in a manner that would
give the Commission broader authority than that given by Congress.
Accordingly, it states that the Commission does not have the authority
to compel non-public utilities to contribute to new regional or
interregional cost allocation mechanisms, or to operate according to
Commission-approved transmission plans directing the level and nature
of transmission investment.
---------------------------------------------------------------------------
\893\ See, e.g., Large Public Power Council; Sacramento
Municipal Utility District; and Bonneville Power.
---------------------------------------------------------------------------
766. Sacramento Municipal Utility District asserts that section
211A of the FPA makes clear that the comparability the Commission is
empowered to enforce is comparability to the transmission services the
non-public utility provides to itself, and that if a non-public utility
chooses not to participate in a regional cost allocation process as
part of its service to itself, it cannot be compelled to participate or
to accept a regional cost allocation plan under section 211A.
Bonneville Power contends that the Commission is inappropriately
attempting to indirectly regulate non-public utility transmission
providers by suggesting that it will use section 211A to obtain their
compliance with mandatory cost allocation. Sacramento Municipal Utility
District and Bonneville Power, therefore, argue that the Commission
should remove its statement that it will use section 211A against non-
public utility transmission providers to obtain compliance with Order
No. 1000. Sacramento Municipal Utility District alternatively urges the
Commission to clarify that its interpretation is not binding and is
without prejudice to the rights of non-public utilities to challenge
such an interpretation in any actual case in which the Commission
invokes the authority to mandate non-public utility participation in
regional planning and cost allocation.
767. On the other hand, Edison Electric Institute argues that the
Commission erred by relying on non-public utility transmission
providers to voluntarily participate in regional transmission planning
and cost allocation processes.\894\ Edison Electric Institute argues
that the Commission should have exercised its authority under section
211A to ensure that unregulated transmitting utilities comply with the
transmission planning and regional cost allocation provisions on the
same terms and conditions as jurisdictional public utilities. Edison
Electric Institute also asserts that the Commission has not
demonstrated or otherwise explained why mandatory action is required in
the case of public utility but is not required for non-public utility
transmission providers. Edison Electric Institute asserts that both
sets of utilities own transmission facilities, provide transmission
service to customers, and may currently
[[Page 32300]]
participate in regional transmission planning processes.
---------------------------------------------------------------------------
\894\ Edison Electric Institute at 26 (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 815).
---------------------------------------------------------------------------
768. Edison Electric Institute asserts that the Commission is
authorized through section 211A to act ``by rule'' to require
unregulated transmitting utilities to remedy discriminatory
transmission rates and practices.\895\ Edison Electric Institute states
that the Commission has recognized that section 211A allows it to
require an unregulated transmitting utility to provide transmission
services on a comparable and not unduly discriminatory basis. Edison
Electric Institute further states that section 211A contains the same
``unduly discriminatory or preferential'' standard found in section
206. Thus, Edison Electric Institute concludes that FPA section 211A,
along with section 206, vests the Commission with the duty to eliminate
undue discrimination and to ensure open access to transmission across
the entire interstate grid.
---------------------------------------------------------------------------
\895\ Edison Electric Institute at 27 (quoting 16 U.S.C. 824j-
1(b)).
---------------------------------------------------------------------------
769. Edison Electric Institute argues that the Commission's
decision to rely on voluntary compliance is ill-founded and inadequate
because there is no indication that non-jurisdictional utilities will
voluntarily comply. It also argues that since Order No. 888, non-
jurisdictional utilities have not fully embraced voluntary compliance
with the Commission's open access reforms. Furthermore, Edison Electric
Institute argues that allowing non-public utilities to participate
voluntarily injects uncertainty in transmission planning and cost
allocation, especially in areas that are predominately served by
unregulated entities. Edison Electric Institute asserts that
participants in regional transmission planning and cost allocation
processes should not have to wait to know whether an unregulated
transmitting utility, and potential beneficiary of a transmission
project, is going to be subject to regional cost allocation. Edison
Electric Institute adds that it also is unclear if, when, and how the
Commission will exercise its authority under section 211A. Edison
Electric Institute asserts that the lack of certainty, layered on to
the short period for compliance, will undermine confidence in the
planning and regional cost allocation processes and hinder their
development.
770. Edison Electric Institute requests that the Commission clarify
and strengthen the obligations of unregulated transmitting utilities to
facilitate full compliance with regional planning and cost allocation
provisions, and make clear when and how it will act on a case-by-case
basis under section 211A. In addition, Edison Electric Institute states
that the Commission has the authority to direct unregulated
transmitting utilities to comply with the requirements in Order No.
1000, whether it learns of non-compliance through a complaint or on its
own motion. Edison Electric Institute argues that failure by the
Commission to act would be an abdication of its obligation to ensure
non-discriminatory treatment in transmission service.
3. Commission Determination
771. In response to petitioners who are concerned that the
Commission is modifying the scope of the reciprocity requirement under
Order Nos. 888 and 890, we clarify that the reciprocity requirement
remains unchanged. A non-public utility transmission provider may
continue to satisfy the reciprocity condition in one of three ways.
First, it may provide service under a tariff that has been approved by
the Commission under the voluntary ``safe harbor'' provision of the pro
forma OATT. A non-public utility transmission provider using this
alternative submits a reciprocity tariff to the Commission seeking a
declaratory order that the proposed reciprocity tariff substantially
conforms to, or is superior to, the pro forma OATT. The non-public
utility transmission provider then must offer service under its
reciprocity tariff to any public utility transmission provider whose
transmission service the non-public utility transmission provider seeks
to use. Second, the non-public utility transmission provider may
provide service to a public utility transmission provider under a
bilateral agreement that satisfies its reciprocity obligation. Finally,
the non-public utility transmission provider may seek a waiver of the
reciprocity condition from the public utility transmission
provider.\896\
---------------------------------------------------------------------------
\896\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 799 &
n.574 (citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 163
(citing Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,285-
86)).
---------------------------------------------------------------------------
772. We affirm the Commission's determination in Order No. 1000
that to maintain a reciprocity tariff under the voluntary ``safe
harbor'' provision, a non-public utility transmission provider must
ensure that the provisions of that tariff substantially conform, or are
superior, to the pro forma OATT and its Attachment K as these have been
revised by Order No. 1000.\897\ As such, if a non-public utility
transmission provider wishes to maintain its safe harbor tariff, it
will need to ensure that it addresses Order No. 1000's transmission
planning and cost allocation reforms, so that it continues to
substantially conform, or be superior, to the pro forma OATT.
---------------------------------------------------------------------------
\897\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 815 and
Appendix C: Pro Forma Open Access Transmission Tariff.
---------------------------------------------------------------------------
773. As we note above, the other two ways of satisfying the
reciprocity requirement also remain intact. For example, a non-public
utility transmission provider seeking service from a public utility
transmission provider may seek to enter into a bilateral agreement with
the public utility transmission provider that addresses that public
utility transmission provider's desire for reciprocity. In such case, a
public utility transmission provider may agree to provide service to a
non-public utility transmission provider without requiring that non-
public utility transmission provider to provide reciprocal service
under terms and conditions that are necessarily substantially
conforming with, or superior to, the pro forma OATT, which includes the
transmission planning and cost allocation reforms in Order No. 1000.
With respect to such bilateral agreements, the Commission in Order No.
888-A stated that it ``must leave these agreements to case-by-case
determinations.'' \898\ In doing so, the Commission stated that the
terms and conditions that ``may be necessary for a non-public utility
to provide reciprocal service to the public utility in a bilateral
agreement is necessarily a fact-specific matter not susceptible to
resolution in a generic rulemaking proceeding.'' \899\ As such, we deny
Edison Electric Institute's request for generic clarification that
section 6 of the pro forma OATT, which codifies the reciprocity
requirement, would allow a public utility transmission provider to
refuse service to a non-public utility transmission provider that
refused to enroll in the regional transmission planning and cost
allocation processes. However, we note that in Order No. 888-A, the
Commission also made clear that ``a public utility may refuse to
provide open access transmission service to a non-public utility if its
denial is based on a good faith assertion that the non-public utility
has not met the Commission's reciprocity requirements.'' \900\ While we
will
[[Page 32301]]
continue to address such matters on a case-by-case basis consistent
with Order No. 888-A, we nevertheless note our finding in Order No.
1000 that those that ``take advantage of open access, including
improved transmission planning and cost allocation, should be expected
to follow the same requirements as public utility transmission
providers.'' \901\ Finally, a public utility transmission provider
remains free to waive any reciprocity requirement for a non-public
utility transmission provider that seeks service from it.
---------------------------------------------------------------------------
\898\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,289.
\899\ Id.
\900\ Id. This approach is also consistent with Order No. 890
where the Commission stated that ``[u]nder the reciprocity provision
in section 6 of the pro forma OATT, if a public utility seeks
transmission service from a non-public utility to which it provides
open access transmission service, the non-public utility that owns,
controls, or operates transmission facilities must provide
comparable transmission service that it is capable of providing on
its own system. Under the pro forma OATT, a public utility may
refuse to provide open access transmission service to a non-public
utility if the non-public utility refuses to reciprocate.'' Order
No. 890, FERC Stats. & Regs. ] 31,241 at P 163.
\901\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 818.
---------------------------------------------------------------------------
774. We further clarify in response to National Rural Electric
Coops that, in the absence of a safe harbor tariff, a non-public
utility transmission provider's obligation to a public utility
transmission provider to provide a comparable transmission service that
it is capable of providing on its own system begins when that public
utility transmission provider requests comparable reciprocal service
from the non-public utility transmission provider.\902\ We also clarify
for Large Public Power Council that the Commission did not intend that
it would enforce reciprocity tariff provisions sua sponte, except
insofar as the Commission permits a public utility transmission
provider to refuse to offer open access transmission service to that
non-public utility transmission provider, in accordance with Order No.
888.
---------------------------------------------------------------------------
\902\ Id. P 819 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 163).
---------------------------------------------------------------------------
775. Because the reciprocity provisions of Order Nos. 888, 890, and
1000 do not impose any requirement on non-public utility transmission
providers, we reject Bonneville Power's and Sacramento Municipal
Utility District's arguments that the Commission is attempting to
regulate non-public utility transmission providers. As the Commission
stated in Order No. 1000, non-public utility transmission providers are
free to decide whether they will seek transmission service that is
subject to the Commission's jurisdiction, and the Commission does not
exercise jurisdiction over them when it determines the terms under
which public utility transmission providers must provide that
transmission service.\903\ As such, the reciprocity provision of Order
No. 1000 does not require non-public utility transmission providers to
comply with the Order No. 1000 transmission planning and cost
allocation reforms. In addition, as explained above in the discussion
of our legal authority to implement Order No. 1000's transmission
planning reforms, we disagree with Sacramento Municipal Utility
District's contention that the Commission lacks the authority to
mandate regional transmission planning for public utility transmission
providers.\904\
---------------------------------------------------------------------------
\903\ Id.
\904\ See discussion supra at section 0.
---------------------------------------------------------------------------
776. In response to Sacramento Municipal Utility District's concern
that a reciprocity provision is ``unnecessary to ensure proper cost
recovery,'' \905\ and Bonneville Power's and Sacramento Municipal
Utility District's concerns that the transmission planning and cost
allocation reforms should be outside the reciprocity construct, we
disagree. Any non-public utility transmission provider that takes
transmission service from a public utility transmission provider after
implementation of Order No. 1000 is likely to benefit from the new OATT
provisions of the public utility transmission providers in that region
providing for improved regional transmission planning and for regional
cost allocation commensurate with benefits for selected facilities, as
provided in Order No. 1000. We therefore in Order No. 1000 applied the
reciprocity provisions of Order Nos. 888 and 890 to provide that it is
within the Commission's discretion to allow a public utility
transmission provider to refuse to offer open access transmission
service to any non-public utility transmission provider that does not
provide comparable reciprocal transmission service insofar as it is
capable of doing so, including regional planning and cost allocation.
However, we reiterate a clarification made above that it is only when a
non-public utility transmission provider actually makes the choice to
become part of a transmission planning region by enrolling in that
region that it would be subject to the regional and interregional cost
allocation methods for that region.\906\
---------------------------------------------------------------------------
\905\ Sacramento Municipal Utility District at 20.
\906\ See discussion supra at section 0.
---------------------------------------------------------------------------
777. In response to Bonneville Power's and Sacramento Municipal
Utility District's contention that certain provisions of Order No.
1000, such as those relating to cost allocation, go beyond the
provision of transmission service and thus should not be incorporated
in the Commission's reciprocity condition, we reiterate that both
transmission planning and cost allocation are integral and essential
components of the provision of transmission service. The transmission
planning and cost allocation reforms adopted in Order No. 1000 are
intended to facilitate the development of a robust transmission system
capable of providing improved open access transmission service and to
help ensure that transmission rates are just and reasonable and not
unduly discriminatory or preferential.
778. We decline to address petitioners' arguments concerning the
scope of our authority under FPA section 211A in this proceeding
because the Commission did not act under FPA section 211A in Order No.
1000.\907\ As the Commission stated in Order No. 1000, the success of
the transmission planning process set forth therein will be enhanced if
all transmission owners participate. The Commission further stated that
non-public utility transmission providers will benefit greatly from the
improved transmission planning and cost allocation processes required
for public utility transmission providers because a well-planned grid
is more reliable and provides more available, less congested paths for
the transmission of electric power in interstate commerce.\908\
---------------------------------------------------------------------------
\907\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 821.
\908\ Id. P 818.
---------------------------------------------------------------------------
VI. Information Collection Statement
779. The Office of Management and Budget (OMB) requires that OMB
approve certain information collection and data retention requirements
imposed by agency rules.\909\ Upon approval of a collection(s) of
information, OMB will assign an OMB control number and an expiration
date. Respondents subject to the filing requirements of a rule will not
be penalized for failing to respond to these collections of information
unless the collections of information display a valid OMB control
number.
---------------------------------------------------------------------------
\909\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------
780. Previously, the Commission submitted to OMB the information
collection requirements arising from Order No. 1000 and OMB approved
those requirements. In this order, the Commission is making no
substantive changes to those requirements, but has provided
clarifications that require public utility transmission providers, and
transmission developers, to collect additional information. Therefore,
the Commission finds it necessary to make
[[Page 32302]]
a formal submission to OMB for review and approval under section
3507(d) of the Paperwork Reduction Act of 1995.\910\
---------------------------------------------------------------------------
\910\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------
781. The burden estimates in this order on rehearing and
clarification of Order No. 1000 represent the incremental burden
changes related only to the new and revised requirements set forth in
this order. It also should be noted that the burden estimates are
averages for all of the filers.
Burden Estimate and Information Collection Costs: The estimated
Public Reporting burden and cost for the new and revised requirements
contained in this order follow.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual number Total annual
FERC-917--New and revised reporting of Annual number Total annual hours in
requirements in order 1000-A in RM10-23 respondents of responses Hours per response hours in year subsequent
(Filers) 1 years
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (TP) develop & 132 1 2 in Year 1; 1 in Yrs. 2 & 3................. 264 132
maintain enrollment process defining how
entities make choice to become part of
trans. planning region; and include (&
maintain) in OATT a list of all pub. &
non-pub. utility trans. providers
enrolled as TP in planning region.
Transmission Developers (TD) submit 140 1 4 (each in Yrs. 1-3)......................... 560 560
development schedule (if selected in
regional plan for cost allocation).
TP describe in OATT how regional trans. 132 1 5 in Year 1; 0.5 in Yrs. 2&3................. 660 66
planning process gives stakeholders
chance to participate & how stakeholders
& TD can propose interregional trans.
facilities for TP in neighboring region
to evaluate jointly.
To the extent that a TP considers either 132 1 18 in Year 1; 1 in Yrs. 2&3.................. 2,376 132
cost containment or cost recovery
provisions as part of cost allocat.
method for regional or interregional
facility, such provisions may be
included in its compliance filing.
--------------------------------------------------------------------------------------------------------------
Total Estimated Additional Burden .............. .............. ............................................. 3,860 890
Hours, for FERC-917 due to Order
1000-A in RM10-23.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost to Comply:
Year 1: $440,040 [3,860 hours x $114 per hour \911\]
---------------------------------------------------------------------------
\911\ The estimated cost of $114 an hour is the average of the
hourly costs of: Attorney ($200), consultant ($150), technical
($80), and administrative support ($25).
---------------------------------------------------------------------------
Subsequent Years: $101,460 [890 hours x $114 per hour]
Title: FERC-917
Action: Clarification to Collection.
OMB Control No.: 1902-0233.
Respondents: Transmission Developers and Public Utility
Transmission Providers. An RTO or ISO also may file some materials on
behalf of its members.
Frequency of Responses: Initial filing and subsequent filings.
Necessity of the Information:
782. Building on the reforms in Order No. 890, the Federal Energy
Regulatory Commission provides these clarifications to the amendments
to the pro forma OATT to correct certain deficiencies in the
transmission planning and cost allocation requirements for public
utility transmission providers adopted in Order No. 1000. The purpose
of Order No. 1000 is to strengthen the pro forma OATT, so that the
transmission grid can better support wholesale power markets and ensure
that Commission-jurisdictional services are provided at rates, terms,
and conditions that are just and reasonable and not unduly
discriminatory or preferential. We expect to achieve this goal through
Order No. 1000 by reforming electric transmission planning requirements
and establishing a closer link between cost allocation and regional
transmission planning processes.
783. Interested persons may obtain information on reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, email:
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
Comments concerning the collection of information and the associated
burden estimate(s), may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission, phone: (202) 395-4638, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically
to the following email address: oira_submission@omb.eop.gov. Comments
submitted to OMB should include OMB Control No. 1902-0233 and Docket
No. RM10-23-001.
VII. Document Availability
784. 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.
785. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary,
[[Page 32303]]
type the docket number excluding the last three digits of this document
in the docket number field.
786. 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.
VIII. Effective Date and Congressional Notification
787. Changes to Order No. 1000 made in this order on rehearing and
clarification will be effective on July 2, 2012. The Commission has
determined, with the concurrence of the Administrator of the Office of
Information and Regulatory Affairs of OMB, that this rule on rehearing
and clarification of Order No. 1000 is not a ``major rule'' as defined
in section 351 of the Small Business Regulatory Enforcement Fairness
Act of 1996.
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
------------------------------------------------------------------------
Ad Hoc Coalition of Central Electric Power Cooperative, Inc.;
Southeastern Utilities. Dalton Utilities; Georgia Transmission
Corporation; JEA; MEAG Power; Orlando
Utilities Commission; Progress Energy
Service Company, LLC (on behalf of
Progress Energy Carolinas, Inc. and
Progress Energy Florida, Inc.); South
Carolina Electric & Gas Company; South
Carolina Public Service Authority
(Santee Cooper); and Southern Company
Services, Inc. (on behalf of Alabama
Power Company, Georgia Power Company,
Gulf Power Company, Mississippi Power
Company, and Southern Power Company).
AEP.......................... American Electric Power Service
Corporation.
Alabama PSC.................. Alabama Public Service Commission.
Ameren....................... Ameren Services Company.
American Transmission........ American Transmission Company LLC.
APPA......................... American Public Power Association.
Arizona Cooperative and Arizona Electric Power Cooperative, Inc.
Southwestern Transmission. and Southwest Transmission Cooperative,
Inc.
AWEA......................... American Wind Energy Association.
Baltimore Gas & Electric..... Baltimore Gas & Electric Company.
Bonneville Power............. Bonneville Power Administration.
California ISO............... California Independent System Operator
Corporation.
California State Water California Department of Water Resources
Project. State Water Project.
Coalition for Fair CMS Energy Corporation; Consolidated
Transmission Policy. Edison; DTE Energy Company; Progress
Energy, Inc.; Public Service Enterprise
Group; SCANA Corporation; Southern
Company. \912\*
Dayton Power and Light....... Dayton Power and Light Company (The).
Duke......................... Duke Energy Corporation.
Edison Electric Institute.... Edison Electric Institute.
ELCON, AF&PA, and the Electricity Consumers Resource Council,
Associated Industrial Groups. American Forest and Paper Association,
Electricity Consumers Resource Council;
American Chemistry Council; Association
of Businesses Advocating Tariff Equity;
Carolina Utility Customers Association;
Coalition of Midwest Transmission
Customers; Florida Industrial Power
Users Group; Georgia Industrial Group-
Electric; Industrial Energy Users--Ohio;
Oklahoma Industrial Energy Consumers;
PJM Industrial Customer Coalition; West
Virginia Energy Users Group; and
Wisconsin Industrial Energy Group.
Energy Future Coalition Group Energy Future Coalition; American Wind
Energy Association; Center for Energy
Efficiency and Renewable Technologies;
Center for Rural Affairs; Climate and
Energy Project; Denali Energy Inc.;
Fresh Energy; Gradient Resources, Inc.;
Iberdrola Renewables; Interwest Energy
Alliance; Natural Resources Defense
Council; Project for Sustainable FERC
Energy Policy; Solar Energy Industries
Association; The Stella Group, Ltd.;
Union of Concerned Scientists; Western
Grid Group; Wind on the Wires; and
WIRES.*
FirstEnergy Service Company.. FirstEnergy Service Company, on behalf of
FirstEnergy Companies: Ohio Edison
Company; Pennsylvania Power Company; The
Cleveland Electric Illuminating Company;
The Toledo Edison Company; American
Transmission Systems, Incorporated;
Jersey Central Power & Light Company;
Metropolitan Edison Company; and
Pennsylvania Electric Company, and
FirstEnergy Solutions Corp. and their
respective electric utility subsidiaries
and affiliates.
Florida PSC.................. Florida Public Service Commission.
Georgia PSC.................. Georgia Public Service Commission.
Illinois Commerce Commission. Illinois Commerce Commission.
ITC Companies................ International Transmission Company;
Michigan Electric Transmission Company,
LLC; ITC Midwest LLC; ITC Great Plains,
LLC; and Green Power Express LP.
Joint Petitioners............ American Electric Power Corp.; AWEA;
Iberdrola Renewables; ITC Holdings
Corp.; NextEra Energy, Inc.; MidAmerican
Energy.
Kentucky PSC................. Kentucky Public Service Commission.
Large Public Power Council... Austin Energy; Chelan County Public
Utility District No. 1; Clark Public
Utilities; Colorado Springs Utilities;
CPS Energy (San Antonio); ElectriCities
of North Carolina; Grant County Public
Utility District; IID Energy (Imperial
Irrigation District); JEA (Jacksonville,
FL); Long Island Power Authority; Los
Angeles Department of Water and Power;
Lower Colorado River Authority; MEAG
Power, Nebraska Public Power District;
New York Power Authority; Omaha Public
Power District; Orlando Utilities
Commission; Platte River Power
Authority; Puerto Rico Electric Power
Authority; Sacramento Municipal Utility
District; Salt River Project; Santee
Cooper; Seattle City Light; Snohomish
County Public Utility District No. 1;
and Tacoma Public Utilities.*
[[Page 32304]]
Long Island Power Authority.. Long Island Power Authority and LIPA.
LS Power..................... LS Power Transmission, LLC.
MEAG Power................... MEAG Power.
MISO......................... Midwest Independent System Transmission
Operator, Inc.
MISO Transmission Owners The Midwest ISO Transmission Owners for
Group 1. 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; American Transmission Company
LLC (``ATC''); City Water, Light & Power
(Springfield, IL); Dairyland Power
Cooperative; Great River Energy;
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 Indiana Gas & Electric Company
(d/b/a Vectren Energy Delivery of
Indiana); Southern Minnesota Municipal
Power Agency; and Wolverine Power Supply
Cooperative, Inc.
MISO Transmission Owners The Midwest ISO Transmission Owners for
Group 2. 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.
MISO Northeast............... MISO Northeast Transmission Customers of
Consumers.
NARUC........................ National Association of Regulatory
Utility Commissioners.
National Rural Electric Coops National Rural Electric Cooperative
Association.
NV Energy.................... Nevada Power Company and Sierra Pacific
Power Company.
New York ISO................. New York Independent System Operator,
Inc.
New York PSC................. New York State Public Service Commission.
New York Transmission Owners. Central Hudson Gas & Electric
Corporation; Consolidated Edison Company
of New York, Inc.; New York Power
Authority; Long Island Power Authority;
New York State Electric & Gas
Corporation; and Niagara Mohawk Power
Corporation; Orange and Rockland
Utilities, Inc.; and Rochester Gas and
Electric Corporation.
NextEra...................... NextEra Energy, Inc.
North Carolina Agencies...... North Carolina Utilities Commission and
Public Staff of the North Carolina
Utilities Commission.
Northern Tier Transmission Northern Tier Transmission Group.
Group.
Oklahoma Gas and Electric Oklahoma Gas and Electric Company.
Company.
PPL Companies................ PPL Electric Utilities Corporation; Lower
Mount Bethel Energy, LLC; PPL Brunner
Island, LLC; PPL Holtwood, LLC; PPL
Martins Creek, LLC; PPL Montour, LLC;
PPL Susquehanna, LLC; PPL University
Park, LLC; PPL EnergyPlus, LLC; PPL
GreatWorks, LLC; PPL Maine, LLC; PPL
Wallingford Energy, LLC; PPL New Jersey
Solar, LLC; PPL New Jersey Biogas, LLC;
PPL Renewable Energy, LLC; PPL Montana,
LLC; PPL Colstrip I, LLC; PPL Colstrip
II, LLC; Louisville Gas and Electric
Company; Kentucky Utilities Company; and
LG&E Energy Marketing LLC.*
PSEG Companies............... Public Service Electric and Gas Company;
PSEG Power LLC; and PSEG Energy
Resources & Trade LLC.
Sacramento Municipal Utility Sacramento Municipal Utility District.
District.
South Carolina Regulatory South Carolina Office of Regulatory
Staff. Staff.
Southern California Edison... Southern California Edison Company.
Southern Companies........... Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi
Power Company; and Southern Power
Company.
Sponsoring PJM Transmission Certain Sponsoring PJM Transmission
Owners. Owners (American Transmission Systems,
Incorporated; Jersey Central Power &
Light Company; Metropolitan Edison
Company; Monongahela Power Company;
Pennsylvania Electric Company; The
Potomac Edison Company; Trans-Allegheny
Interstate Line Company; and West Penn
Power Company (collectively, the
FirstEnergy Companies); Baltimore Gas
and Electric Company; The Dayton Power
and Light Company; Duquesne Light
Company; Public Service Electric and Gas
Company; PSEG Power LLC and PSEG Energy
Resources & Trade LLC (collectively,
PSEG Companies); and Virginia Electric
and Power Company).
Sunflower, Mid-Kansas and Sunflower Electric Power Corporation and
Western Farmers. Mid-Kansas Electric Company, LLC and
Western Farmers Electric Cooperative.
Transmission Access Policy Transmission Access Policy Study Group.
Study Group.
Transmission Dependent Arkansas Electric Cooperative
Utility Systems. Corporation; Golden Spread Electric
Cooperative, Inc.; Kansas Electric Power
Cooperative, Inc.; North Carolina
Electric Membership Corporation; and
Seminole Electric Cooperative, Inc.; and
PowerSouth Energy Cooperative.*
Vermont Department of Public Vermont Department of Public Service and
Service and the Vermont the Vermont Public Service Board
Public Service Board.
Western Independent Western Independent Transmission Group.
Transmission Group.
[[Page 32305]]
WIRES........................ Working Group for Investment in Reliable
and Economic Electric Systems.
Wisconsin PSC................ Public Service Commission of Wisconsin.
Xcel......................... Xcel Energy Services Inc.
------------------------------------------------------------------------
---------------------------------------------------------------------------
\912\ A ``*'' indicates that the composition of this group has
changed since the Final Rule proceeding.
---------------------------------------------------------------------------
Appendix B: Pro Forma Open Access Transmission Tariff
Pro Forma OATT
Attachment K
Transmission Planning Process
Local Transmission Planning
The Transmission Provider shall establish a coordinated, open
and transparent planning process with its Network and Firm Point-to-
Point Transmission Customers and other interested parties to ensure
that the Transmission System is planned to meet the needs of both
the Transmission Provider and its Network and Firm Point-to-Point
Transmission Customers on a comparable and not unduly discriminatory
basis. The Transmission Provider's coordinated, open and transparent
planning process shall be provided as an attachment to the
Transmission Provider's Tariff.
The Transmission Provider's planning process shall satisfy the
following nine principles, as defined in Order No. 890:
Coordination, openness, transparency, information exchange,
comparability, dispute resolution, regional participation, economic
planning studies, and cost allocation for new projects. The planning
process also shall include the procedures and mechanisms for
considering transmission needs driven by Public Policy Requirements
consistent with Order No. 1000. The planning process also shall
provide a mechanism for the recovery and allocation of planning
costs consistent with Order No. 890.
The description of the Transmission Provider's planning process
must include sufficient detail to enable Transmission Customers to
understand:
(i) The process for consulting with customers;
(ii) The notice procedures and anticipated frequency of
meetings;
(iii) The methodology, criteria, and processes used to develop a
transmission plan;
(iv) The method of disclosure of criteria, assumptions and data
underlying a transmission plan;
(v) The obligations of and methods for Transmission Customers to
submit data to the Transmission Provider;
(vi) The dispute resolution process;
(vii) The Transmission Provider's study procedures for economic
upgrades to address congestion or the integration of new resources;
(viii) The Transmission Provider's procedures and mechanisms for
considering transmission needs driven by Public Policy Requirements,
consistent with Order No. 1000; and
(ix) The relevant cost allocation method or methods.
Regional Transmission Planning
The Transmission Provider shall participate in a regional
transmission planning process through which transmission facilities
and non-transmission alternatives may be proposed and evaluated. The
regional transmission planning process also shall develop a regional
transmission plan that identifies the transmission facilities
necessary to meet the needs of transmission providers and
transmission customers in the transmission planning region. The
regional transmission planning process must be consistent with the
provision of Commission-jurisdictional services at rates, terms and
conditions that are just and reasonable and not unduly
discriminatory or preferential, as described in Order No. 1000. The
regional transmission planning process shall be described in an
attachment to the Transmission Provider's Tariff.
The Transmission Provider's regional transmission planning
process shall satisfy the following seven principles, as set out and
explained in Order Nos. 890 and 1000: Coordination, openness,
transparency, information exchange, comparability, dispute
resolution, and economic planning studies. The regional transmission
planning process also shall include the procedures and mechanisms
for considering transmission needs driven by Public Policy
Requirements, consistent with Order No. 1000. The regional
transmission planning process shall provide a mechanism for the
recovery and allocation of planning costs consistent with Order No.
890.
The regional transmission planning process shall include a clear
enrollment process for public and non-public utility transmission
providers that make the choice to become part of a transmission
planning region. The regional transmission planning process shall be
clear that enrollment will subject enrollees to cost allocation if
they are found to be beneficiaries of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation. Each Transmission Provider shall maintain a list of
enrolled entities in the Transmission Provider's Tariff.
Nothing in the regional transmission planning process shall
include an unduly discriminatory or preferential process for
transmission project submission and selection.
The description of the regional transmission planning process
must include sufficient detail to enable Transmission Customers to
understand:
(i) The process for enrollment in the regional transmission
planning process;
(ii) The process for consulting with customers;
(iii) The notice procedures and anticipated frequency of
meetings;
(iv) The methodology, criteria, and processes used to develop a
transmission plan;
(v) The method of disclosure of criteria, assumptions and data
underlying transmission plan;
(vi) The obligations of and methods for transmission customers
to submit data;
(vii) Process for submission of data by nonincumbent developers
of transmission projects that wish to participate in the
transmission planning process and seek regional cost allocation;
(viii) Process for submission of data by merchant transmission
developers that wish to participate in the transmission planning
process;
(ix) The dispute resolution process;
(x) The study procedures for economic upgrades to address
congestion or the integration of new resources;
(xi) The procedures and mechanisms for considering transmission
needs driven by Public Policy Requirements, consistent with Order
No. 1000; and
(xii) The relevant cost allocation method or methods.
The regional transmission planning process must include a cost
allocation method or methods that satisfy the six regional cost
allocation principles set forth in Order No. 1000.
Interregional Transmission Coordination
The Transmission Provider, through its regional transmission
planning process, must coordinate with the public utility
transmission providers in each neighboring transmission planning
region within its interconnection to address transmission planning
coordination issues related to interregional transmission
facilities. The interregional transmission coordination procedures
must include a detailed description of the process for coordination
between public utility transmission providers in neighboring
transmission planning regions (i) with respect to each interregional
transmission facility that is proposed to be located in both
transmission planning regions and (ii) to identify possible
interregional transmission facilities that could address
transmission needs more efficiently or cost-effectively than
separate regional transmission facilities. The interregional
transmission coordination procedures shall be described in an
attachment to the Transmission Provider's Tariff.
The Transmission Provider must ensure that the following
requirements are included in any applicable interregional
transmission coordination procedures:
(1) A commitment to coordinate and share the results of each
transmission planning region's regional transmission plans to
identify possible interregional transmission facilities that could
address transmission needs more efficiently or cost-effectively than
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separate regional transmission facilities, as well as a procedure
for doing so;
(2) A formal procedure to identify and jointly evaluate
transmission facilities that are proposed to be located in both
transmission planning regions;
(3) An agreement to exchange, at least annually, planning data
and information; and
(4) A commitment to maintain a Web site or email list for the
communication of information related to the coordinated planning
process.
The Transmission Provider must work with transmission providers
located in neighboring transmission planning regions to develop a
mutually agreeable method or methods for allocating between the two
transmission planning regions the costs of a new interregional
transmission facility that is located within both transmission
planning regions. Such cost allocation method or methods must
satisfy the six interregional cost allocation principles set forth
in Order No. 1000 and must be included in the Transmission
Provider's Tariff.
[FR Doc. 2012-12418 Filed 5-30-12; 8:45 am]
BILLING CODE 6717-01-P