[Federal Register Volume 77, Number 105 (Thursday, May 31, 2012)]
[Rules and Regulations]
[Pages 32184-32306]
From the Federal Register Online via the Government Publishing 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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \135\ See discussion infra at section IV.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
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    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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)).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \313\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 146.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \316\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 328.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \341\ Id. P 163.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \342\ Id. P 119.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \343\ Id. P 165.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \344\ Id. P 65.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \360\ Id. P 205.
    \361\ Id. P 209.
    \362\ Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

    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)).

---------------------------------------------------------------------------

[[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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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)).

---------------------------------------------------------------------------

[[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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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: 
[email protected], 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: [email protected]. 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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

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.
------------------------------------------------------------------------

     
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    \912\ A ``*'' indicates that the composition of this group has 
changed since the Final Rule proceeding.
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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

[[Page 32306]]

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