Document ID: FERC-2011-1229-0001
Agency: ferc
Document Type: Rule
Title: Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities
Posted Date: 2011-08-11T04:00Z

[Federal Register Volume 76, Number 155 (Thursday, August 11, 2011)]
[Rules and Regulations]
[Pages 49842-49974]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-19084]

[[Page 49841]]

Vol. 76

Thursday,

No. 155

August 11, 2011

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. 76 , No. 155 / Thursday, August 11, 2011 / 
Rules and Regulations  

[[Page 49842]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-23-000; Order No. 1000]

Transmission Planning and Cost Allocation by Transmission Owning 
and Operating Public Utilities

AGENCY: Federal Energy Regulatory Commission, Energy.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission is 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. With respect 
to transmission planning, this Final Rule requires that each public 
utility transmission provider participate in a regional transmission 
planning process that produces a regional transmission plan; requires 
that each public utility transmission provider amend its OATT to 
describe procedures that provide for the consideration of transmission 
needs driven by public policy requirements in the local and regional 
transmission planning processes; removes from Commission-approved 
tariffs and agreements a federal right of first refusal for certain new 
transmission facilities; and improves coordination between neighboring 
transmission planning regions for new interregional transmission 
facilities. Also, this Final Rule requires 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 certain new transmission facilities 
that are located in two or more neighboring transmission planning 
regions and are jointly evaluated by the regions in the interregional 
transmission coordination procedures required by this Final Rule. Each 
cost allocation method must satisfy six cost allocation principles.

DATES: Effective Date: This final rule will become effective on October 
11, 2011.

FOR FURTHER INFORMATION CONTACT:

Kevin Kelly, Federal Energy Regulatory Commission, Office of Energy 
Policy and Innovation, 888 First Street, NE., Washington, DC 20426. 
(202) 502-8850.
Maria Farinella, Federal Energy Regulatory Commission, Office of the 
General Counsel, 888 First Street, NE., Washington, DC 20426. (202) 
502-6000.

SUPPLEMENTARY INFORMATION:

Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer, 
Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur.

Order No. 1000

Table of Contents

 
                                                               Paragraph
                                                                  No.
 
I. Introduction.............................................           1
    A. Order Nos. 888 and 890...............................          15
    B. Technical Conferences and Notice of Request for                22
     Comments on Transmission Planning and Cost Allocation..
    C. Additional Developments Since Issuance of Order No.            25
     890....................................................
II. The Need for Reform.....................................          30
    A. Proposed Rule........................................          30
    B. Comments.............................................          32
    C. Commission Determination.............................          42
    D. Use of Terms.........................................          63
III. Proposed Reforms: Transmission Planning................          67
    A. Regional Transmission Planning Process...............          68
        1. Need for Reform Concerning Regional Transmission           70
         Planning...........................................
            a. Commission Proposal..........................          70
            b. Comments.....................................          72
            c. Commission Determination.....................          78
        2. Legal Authority for Transmission Planning Reforms          85
            a. Commission Proposal..........................          85
            b. Comments.....................................          86
            c. Commission Determination.....................          99
        3. Regional Transmission Planning Principles........         118
            a. Commission Proposal..........................         118
            b. Comments.....................................         120
            c. Commission Determination.....................         146
        4. Consideration of Transmission Needs Driven by             166
         Public Policy Requirements.........................
            a. Commission Proposal..........................         166
            b. Comments.....................................         169
            c. Commission Determination.....................         203
    B. Nonincumbent Transmission Developers.................         225
        1. Need for Reform Concerning Nonincumbent                   228
         Transmission Developers............................
            a. Commission Proposal..........................         228
            b. Comments.....................................         231
            c. Commission Determination.....................         253
        2. Legal Authority To Remove a Federal Right of              270
         First Refusal......................................
            a. Commission Proposal..........................         270
            b. Comments Regarding the Commission's Authority         271
             To Implement the Proposal......................
            c. Commission Determination.....................         284
        3. Removal of a Federal Right of First Refusal From          293
         Commission-Jurisdictional Tariffs and Agreements...
            a. Commission Proposal..........................         293
            b. Comments Regarding Developer Qualification            296
             and Project Identification.....................
            c. Comments Regarding Project Evaluation and             302
             Selection......................................
            d. Commission Determination.....................         313

[[Page 49843]]

 
                i. Qualification Criteria To Submit a                323
                 Transmission Project for Selection in the
                 Regional Transmission Plan for Purposes of
                 Cost Allocation............................
                ii. Submission of Proposals for Selection in         325
                 the Regional Transmission Plan for Purposes
                 of Cost Allocation.........................
                iii. Evaluation of Proposals for Selection           328
                 in the Regional Transmission Plan for
                 Purposes of Cost Allocation................
                iv. Cost Allocation for Projects Selected in         332
                 the Regional Transmission Plan for Purposes
                 of Cost Allocation.........................
                v. Rights To Construct and Ongoing                   338
                 Sponsorship................................
        4. Reliability Compliance Obligations of                     341
         Transmission Developers............................
            a. Comments Regarding Reliability Obligations...         341
            b. Commission Determination.....................         342
    C. Interregional Transmission Coordination..............         345
        1. Need for Interregional Transmission Coordination          347
         Reform.............................................
            a. Commission Proposal..........................         347
            b. Comments.....................................         351
            c. Commission Determination.....................         368
        2. Interregional Transmission Coordination                   374
         Requirements.......................................
            a. Interregional Transmission Coordination               374
             Procedures.....................................
                i. Commission Proposal......................         374
                ii. Comments................................         377
                iii. Commission Determination...............         393
            b. Geographic Scope of Interregional                     405
             Transmission Coordination......................
                i. Commission Proposal......................         405
                ii. Comments................................         406
                iii. Commission Determination...............         415
        3. Implementation of the Interregional Transmission          422
         Coordination Requirements..........................
            a. Procedure for Joint Evaluation...............         422
                i. Comments.................................         422
                ii. Commission Determination................         435
            b. Data Exchange................................         451
                i. Comments.................................         451
                ii. Commission Determination................         454
            c. Transparency.................................         456
                i. Comments.................................         456
                ii. Commission Determination................         458
            d. Stakeholder Participation....................         459
                i. Commission Proposal......................         459
                ii. Comments................................         460
                iii. Commission Determination...............         465
            e. Tariff Provisions and Agreements for                  468
             Interregional Transmission Coordination........
                i. Commission Proposal......................         468
                ii. Comments................................         469
                iii. Commission Determination...............         475
IV. Proposed Reforms: Cost Allocation.......................         482
    A. Need for Reform Concerning Cost Allocation...........         484
        1. Commission Proposal..............................         484
        2. Comments on Need for Reform......................         488
        3. Commission Determination.........................         495
    B. Legal Authority for Cost Allocation Reforms..........         504
        1. Commission Proposal..............................         504
        2. Comments on Legal Authority......................         509
        3. Commission Determination.........................         530
    C. Cost Allocation Method for Regional Transmission              550
     Facilities.............................................
        1. Commission Proposal..............................         550
        2. Comments on Cost Allocation Method in Regional            553
         Transmission Planning..............................
        3. Commission Determination.........................         558
    D. Cost Allocation Method for Interregional Transmission         566
     Facilities.............................................
        1. Commission Proposal..............................         566
        2. Comments on Interregional Cost Allocation Reforms         568
        3. Commission Determination.........................         578
    E. Principles for Regional and Interregional Cost                585
     Allocation.............................................
        1. Use of a Principles-Based Approach...............         585
            a. Commission Proposal..........................         585
            b. Comments on Use of Principles-Based Approach.         589
            c. Commission Determination.....................         603
        2. Cost Allocation Principle 1--Costs Allocated in a         612
         Way That Is Roughly Commensurate With Benefits.....
            a. Comments.....................................         612
            b. Commission Determination.....................         622
        3. Cost Allocation Principle 2--No Involuntary               630
         Allocation of Costs to Non-Beneficiaries...........
            a. Comments.....................................         630
            b. Commission Determination.....................         637
        4. Cost Allocation Principle 3--Benefit to Cost              642
         Threshold Ratio....................................
            a. Comments.....................................         642
            b. Commission Determination.....................         646
        5. Cost Allocation Principle 4--Allocation To Be             651
         Solely Within Transmission Planning Region(s)
         Unless Those Outside Voluntarily Assume Costs......

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            a. Comments.....................................         651
            b. Commission Determination.....................         657
        6. Cost Allocation Principle 5--Transparent Method           665
         for Determining Benefits and Identifying
         Beneficiaries......................................
            a. Comments.....................................         665
            b. Commission Determination.....................         668
        7. Cost Allocation Principle 6--Different Methods            673
         for Different Types of Facilities..................
            a. Comments.....................................         673
            b. Commission Determination.....................         685
        8. Whether To Establish Other Cost Allocation                694
         Principles.........................................
            a. Commission Proposal..........................         694
            b. Comments.....................................         695
            c. Commission Determination.....................         704
    F. Application of the Cost Allocation Principles........         706
        1. Whether To Have Broad Regional Cost Allocation            707
         for Extra-High Voltage Facilities..................
            a. Commission Proposal..........................         707
            b. Comments on Cost Allocation for Extra-High            708
             Voltage Facilities.............................
            c. Commission Determination.....................         713
        2. Whether To Limit the Use of Participant Funding..         715
            a. Commission Proposal..........................         715
            b. Comments on Limiting Participant Funding.....         716
            c. Commission Determination.....................         723
        3. Whether Regional and Interregional Cost                   730
         Allocation Methods May Differ......................
            a. Commission Proposal..........................         730
            b. Comments.....................................         731
            c. Commission Determination.....................         733
        4. Recommendations for Additional Commission                 736
         Guidance on the Application of the Transmission
         Cost Allocation Principles.........................
            a. Comments.....................................         737
            b. Commission Determination.....................         745
    G. Cost Allocation Matters Related to Other Commission           751
     Rules, Joint Ownership, and Non-Transmission
     Alternatives...........................................
        1. Whether To Reform Cost Allocation for Generator           752
         Interconnections...................................
            a. Comments.....................................         753
            b. Commission Determination.....................         760
        2. Pancaked Rates...................................         761
            a. Comments.....................................         761
            b. Commission Determination.....................         764
        3. Transmission Rate Incentives.....................         765
            a. Comments.....................................         766
            b. Commission Determination.....................         771
        4. Relationship of This Proceeding to the Proceeding         772
         on Variable Energy Resources.......................
            a. Comments.....................................         772
            b. Commission Determination.....................         774
        5. Joint Ownership..................................         775
            a. Comments.....................................         775
            b. Commission Determination.....................         776
        6. Cost Recovery for Non-Transmission Alternatives..         777
            a. Comment Summary..............................         777
            b. Commission Determination.....................         779
V. Compliance and Reciprocity Requirements..................         780
    A. Compliance...........................................         780
        1. Commission Proposal..............................         780
        2. Comments.........................................         781
        3. Commission Determination.........................         792
    B. Reciprocity..........................................         799
        1. Commission Proposal..............................         799
        2. Comments.........................................         800
        3. Commission Determination.........................         815
VI. Information Collection Statement........................         823
VII. Environmental Analysis.................................         831
VIII. Regulatory Flexibility Act Analysis...................         832
IX. Document Availability...................................         833
X. Effective Date and Congressional Notification............         836
Regulatory Text
Appendix A: Summary of Compliance Requirements
Appendix B: Abbreviated Names of Commenters
Appendix C: Pro Forma Open Access Transmission Tariff
 Attachment K
 

I. Introduction

    1. In this Final Rule, the Commission acts under section 206 of the 
Federal Power Act (FPA) to adopt reforms to its electric transmission 
planning and cost allocation requirements for public utility 
transmission providers.\1\ The reforms herein are intended to improve

[[Page 49845]]

transmission planning processes and cost allocation mechanisms under 
the pro forma Open Access Transmission Tariff (OATT) to ensure that the 
rates, terms and conditions of service provided by public utility 
transmission providers are just and reasonable and not unduly 
discriminatory or preferential. This Final Rule builds on Order No. 
890,\2\ in which the Commission, among other things, reformed the pro 
forma OATT to require each public utility transmission provider to have 
a coordinated, open, and transparent regional transmission planning 
process. After careful review of the voluminous record in this 
proceeding, the Commission concludes that the additional reforms 
adopted herein are necessary at this time to ensure that rates for 
Commission-jurisdictional service are just and reasonable in light of 
changing conditions in the industry. In addition, the Commission 
believes that these reforms address opportunities for undue 
discrimination by public utility transmission providers.
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    \1\ 16 U.S.C. 824e (2006).
    \2\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), 
FERC Stats. & Regs. ] 31,241, order on reh'g, Order No. 890-A, 73 FR 
2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261 (2007), order on 
reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 
2008), 123 FERC ] 61,299 (2008), order on reh'g, Order No. 890-C, 74 
FR 12540 (Mar. 25, 2009), 126 FERC ] 61,228 (2009), order on 
clarification, Order No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 
FERC ] 61,126 (2009).
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    2. The Commission acknowledges that significant work has been done 
in recent years to enhance regional transmission planning processes. 
The Commission appreciates the diversity of opinions expressed by 
commenters in response to the Notice of Proposed Rulemaking \3\ as to 
whether, in light of the progress being made in many regions, further 
reforms to transmission planning processes and cost allocation 
mechanisms are necessary at this time. On balance, the Commission 
concludes that the reforms adopted herein are necessary for more 
efficient and cost-effective regional transmission planning. As 
discussed further below, the electric industry is currently facing the 
possibility of substantial investment in future transmission facilities 
to meet the challenge of maintaining reliable service at a reasonable 
cost. The Commission concludes that it is appropriate to act now to 
ensure that its transmission planning processes and cost allocation 
requirements are adequate to allow public utility transmission 
providers to address these challenges more efficiently and cost-
effectively. In reaching this conclusion, the Commission has balanced 
competing interests of various segments of the industry and designed a 
package of reforms that, in our view, will support the development of 
those transmission facilities identified by each transmission planning 
region as necessary to satisfy reliability standards, reduce 
congestion, and allow for consideration of transmission needs driven by 
public policy requirements established by state or federal laws or 
regulations (Public Policy Requirements). By ``state or federal laws or 
regulations,'' we mean 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.
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    \3\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Notice of Proposed 
Rulemaking, FERC Stats. & Regs. ] 32,660 (2010) (Proposed Rule).
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    3. Through this Final Rule, we conclude that the existing 
requirements of Order No. 890 are inadequate. Public utility 
transmission providers are currently under no affirmative obligation to 
develop a regional transmission plan that reflects the evaluation of 
whether alternative regional solutions may be more efficient or cost-
effective than solutions identified in local transmission planning 
processes. Similarly, there is no requirement that public utility 
transmission providers consider transmission needs at the local or 
regional level driven by Public Policy Requirements. Nonincumbent 
transmission developers seeking to invest in transmission can be 
discouraged from doing so as a result of federal rights of first 
refusal in tariffs and agreements subject to the Commission's 
jurisdiction. While neighboring transmission planning regions may 
coordinate evaluation of the reliability impacts of transmission within 
their respective regions, few procedures are in place for identifying 
and evaluating the benefits of alternative interregional transmission 
solutions. Finally, many cost allocation methods in place within 
transmission planning regions fail to account for the beneficiaries of 
new transmission facilities, while cost allocation methods for 
potential interregional facilities are largely nonexistent.
    4. We correct these deficiencies by enhancing the obligations 
placed on public utility transmission providers in several specific 
ways. While focused on discrete aspects of the transmission planning 
and cost allocation processes, the specific reforms adopted in this 
Final Rule are intended to achieve two primary objectives: (1) Ensure 
that transmission planning processes at the regional level consider and 
evaluate, on a non-discriminatory basis, possible transmission 
alternatives and produce a transmission plan that can meet transmission 
needs more efficiently and cost-effectively; and (2) ensure that the 
costs of transmission solutions chosen to meet regional transmission 
needs are allocated fairly to those who receive benefits from them. In 
addition, this Final Rule addresses interregional coordination and cost 
allocation, to achieve the same objectives with respect to possible 
transmission solutions that may be located in a neighboring 
transmission planning region.
    5. Certain requirements of this Final Rule distinguish between ``a 
transmission facility in a regional transmission plan,'' and ``a 
transmission facility selected in a regional transmission plan for 
purposes of cost allocation.'' \4\ A ``transmission facility selected 
in a regional transmission plan for purposes of cost allocation'' is 
one that has been selected, pursuant to a Commission-approved regional 
transmission planning process, as a more efficient or cost-effective 
solution to regional transmission needs. As discussed in more detail 
below, this distinction is an essential component of this Final Rule.
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    \4\ See infra P 0.
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    6. Turning to the specific discrete reforms we adopt today, we 
first require public utility transmission providers to participate in a 
regional transmission planning process that evaluates transmission 
alternatives at the regional level that may resolve the transmission 
planning region's needs more efficiently and cost-effectively than 
alternatives identified by individual public utility transmission 
providers in their local transmission planning processes. This 
requirement builds on the transmission planning principles adopted by 
the Commission in Order No. 890, and the regional transmission planning 
processes developed in response to this Final Rule must satisfy those 
principles. These processes must result in the development of a 
regional transmission plan. As part of our reforms, we also require 
that the regional transmission planning process, as well as the 
underlying local transmission planning processes of public utility 
transmission providers, provide an opportunity to consider transmission 
needs driven by Public Policy Requirements. We conclude that requiring 
each local and regional transmission planning process to provide this 
opportunity is necessary to ensure that transmission planning processes 
identify and evaluate transmission needs driven by relevant

[[Page 49846]]

Public Policy Requirements, and support more efficient and cost-
effective achievement of those requirements.
    7. Second, we direct public utility transmission providers to 
remove from their OATTs or other Commission-jurisdictional tariffs and 
agreements any provisions that grant a federal right of first refusal 
to transmission facilities that are selected in a regional transmission 
plan for purposes of cost allocation.\5\ We conclude that leaving 
federal rights of first refusal in place for these facilities would 
allow practices that have the potential to undermine the identification 
and evaluation of a more efficient or cost-effective solution to 
regional transmission needs, which in turn can result in rates for 
Commission-jurisdictional services that are unjust and unreasonable or 
otherwise result in undue discrimination by public utility transmission 
providers. To implement the elimination of such federal rights of first 
refusal, we adopt below a framework that requires, among other things, 
the development of qualification criteria and protocols for the 
submission and evaluation of transmission proposals. In addition, as 
described in section III.B.3, we also 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 the incumbent transmission provider 
proposes, to ensure the incumbent can meet its reliability needs or 
service obligations. This requirement, however, applies only to 
transmission facilities that are selected in a regional transmission 
plan for purposes of cost allocation and not, for example, to 
transmission facilities in local transmission plans that are merely 
``rolled up'' and listed in a regional transmission plan without going 
through an analysis at the regional level, and therefore, not eligible 
for regional cost allocation.
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    \5\ See infra P 0.
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    8. Third, we require public utility transmission providers to 
improve coordination across regional transmission planning processes by 
developing and implementing, through their respective regional 
transmission planning process, procedures for joint evaluation and 
sharing of information regarding the respective transmission needs of 
transmission planning regions and potential solutions to those needs. 
These procedures must provide for the identification and joint 
evaluation by neighboring transmission planning regions of 
interregional transmission facilities to determine if there are more 
efficient or cost-effective interregional transmission solutions than 
regional solutions identified by the neighboring transmission planning 
regions. To facilitate the joint evaluation of interregional 
transmission facilities, we require the exchange of planning data and 
information between neighboring transmission planning regions at least 
annually.
    9. Finally, we require public utility transmission providers to 
have in place 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. We also require public utility 
transmission providers in each transmission planning region to have, 
together with the public utility transmission providers in a 
neighboring transmission planning region, a common method, or set of 
methods, for allocating the costs of a new interregional transmission 
facility that is jointly evaluated by the two or more transmission 
planning regions in their interregional transmission coordination 
procedures. Given the fact that a determination by the transmission 
planning process to select a transmission facility in a plan for 
purposes of cost allocation will necessarily include an evaluation of 
the benefits of that facility, we require that transmission planning 
and cost allocation processes be aligned. Further, all regional and 
interregional cost allocation methods must be consistent with regional 
and interregional cost allocation principles, respectively, adopted in 
this Final Rule. Nothing in this Final Rule requires either 
interconnectionwide planning or interconnectionwide cost allocation.
    10. The cost allocation reforms adopted today, and the cost 
allocation principles that each proposed regional and interregional 
cost allocation method or methods must satisfy, seek to address the 
potential opportunity for free ridership inherent in transmission 
services, given the nature of power flows over an interconnected 
transmission system. In particular, the principles-based approach 
requires that all regional and interregional cost allocation methods 
allocate costs for new transmission facilities in a manner that is at 
least roughly commensurate with the benefits received by those who will 
pay those costs. Costs may not be involuntarily allocated to entities 
that do not receive benefits.\6\ In addition, the Commission finds that 
participant funding is permitted, but not as a regional or 
interregional cost allocation method.
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    \6\ However, 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. See infra P 723-729.
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    11. As noted above, the various specific reforms adopted in this 
Final Rule are designed to work together to ensure an opportunity for 
more transmission projects to be considered in the transmission 
planning process on an equitable basis and increase the likelihood that 
those transmission facilities selected in a regional transmission plan 
for purposes of cost allocation are the more efficient or cost-
effective solutions available. At its core, the set of reforms adopted 
in this Final Rule require the public utility transmission providers in 
a transmission planning region, in consultation with their 
stakeholders, to create a regional transmission plan. This plan will 
identify transmission facilities that more efficiently or cost-
effectively meet the region's reliability, economic and Public Policy 
Requirements. To meet such requirements more efficiently and cost-
effectively, the regional transmission plan must reflect a fair 
consideration of transmission facilities proposed by nonincumbents, as 
well as interregional transmission facilities. The regional 
transmission plan must also include a clear cost allocation method or 
methods that identify beneficiaries for each of the transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation, in order to increase the likelihood that such 
transmission facilities will actually be constructed.
    12. The transmission planning and cost allocation requirements in 
this Final Rule, like those of Order No. 890, are focused on the 
transmission planning process, and not on any substantive outcomes that 
may result from this process. Taken together, the requirements imposed 
in this Final Rule work together to remedy deficiencies in the existing 
requirements of Order No. 890 and enhance the ability of the 
transmission grid to support wholesale power markets. This, in turn, 
will fulfill our statutory obligation to ensure that Commission-
jurisdictional services are provided at rates, terms, and conditions of 
service that are just and reasonable and not unduly discriminatory or 
preferential.
    13. We acknowledge that public utility transmission providers in 
some

[[Page 49847]]

transmission planning regions already may have in place transmission 
planning processes or cost allocation mechanisms that satisfy some or 
all of the requirements of this Final Rule. Our reforms are not 
intended to undermine progress being made in those regions, nor do we 
intend to undermine other planning activities that are being undertaken 
at the interconnection level. Rather, the Commission is acting here to 
identify a minimum set of requirements that must be met to ensure that 
all transmission planning processes and cost allocation mechanisms 
subject to its jurisdiction result in Commission-jurisdictional 
services being provided at rates, terms and conditions that are just 
and reasonable and not unduly discriminatory or preferential.
    14. The Commission appreciates the significant work that will go 
into the preparation of compliance proposals in response to this Final 
Rule. To assist public utility transmission providers in their efforts 
to comply, the Commission directs its staff to hold informational 
conferences within 60 days of the effective date of this Final Rule to 
review and discuss the requirements imposed herein with interested 
parties. Moreover, as public utility transmission providers work with 
their stakeholders to prepare compliance proposals, the Commission 
encourages frequent dialogue with Commission staff to explore issues 
that are specific to each transmission planning region. The Commission 
will monitor progress being made.

A. Order Nos. 888 and 890

    15. In Order No. 888,\7\ issued in 1996, the Commission found that 
it was in the economic interest of transmission providers to deny 
transmission service or to offer transmission service to others on a 
basis that is inferior to that which they provide to themselves.\8\ 
Concluding that unduly discriminatory and anticompetitive practices 
existed in the electric industry and that, absent Commission action, 
such practices would increase as competitive pressures in the industry 
grew, the Commission in Order No. 888 and the accompanying pro forma 
OATT implemented open access to transmission facilities owned, 
operated, or controlled by a public utility.
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    \7\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 
14, 1997), FERC Stats. & Regs. ] 31,048, 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 (DC Cir. 2000), 
aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \8\ Order No. 888, FERC Stats. & Regs. at 31,682.
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    16. As part of those reforms, Order No. 888 and the pro forma OATT 
set forth certain minimum requirements for transmission planning. For 
example, the pro forma OATT required a public utility transmission 
provider to account for the needs of its network customers in its 
transmission planning activities on the same basis as it provides for 
its own needs.\9\ The pro forma OATT also required that new facilities 
be constructed to meet the transmission service requests of long-term 
firm point-to-point customers.\10\ While Order No. 888-A went on to 
encourage utilities to engage in joint and regional transmission 
planning with other utilities and customers, it did not require those 
actions.\11\
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    \9\ See Section 28.2 of the pro forma OATT.
    \10\ See Sections 13.5, 15.4, and 27 of the pro forma OATT.
    \11\ Order No. 888-A, FERC Stats. & Regs. at 30,311.
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    17. In early 2007, the Commission issued Order No. 890 to remedy 
flaws in the pro forma OATT that the Commission identified based on the 
decade of experience since the issuance of Order No. 888. Among other 
things, the Commission found that pro forma OATT obligations related to 
transmission planning were insufficient to eliminate opportunities for 
undue discrimination in the provision of transmission service. The 
Commission stated that particularly in an era of increasing 
transmission congestion and the need for significant new transmission 
investment, it could not rely on the self-interest of transmission 
providers to expand the grid in a not unduly discriminatory manner. 
Among other shortcomings in the pro forma OATT, the Commission pointed 
to the lack of clear criteria regarding the transmission provider's 
planning obligation; the absence of a requirement that the overall 
transmission planning process be open to customers, competitors, and 
state commissions; and the absence of a requirement that key 
assumptions and data underlying transmission plans be made available to 
customers.
    18. In light of these findings, one of the primary goals of the 
reforms undertaken in Order No. 890 was to address the lack of 
specificity regarding how stakeholders should be treated in the 
transmission planning process. To remedy the potential for undue 
discrimination in transmission planning activities, the Commission 
required each public utility transmission provider to develop a 
transmission planning process that satisfies nine principles and to 
clearly describe that process in a new attachment to its OATT 
(Attachment K). The Order No. 890 transmission planning principles are: 
(1) Coordination; (2) openness; (3) transparency; (4) information 
exchange; (5) comparability; (6) dispute resolution; (7) regional 
participation; (8) economic planning studies; and (9) cost allocation 
for new projects.\12\
---------------------------------------------------------------------------

    \12\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 418-601.
---------------------------------------------------------------------------

    19. The transmission planning reforms adopted in Order No. 890 
apply to all public utility transmission providers, including 
Commission-approved RTOs and ISOs. The Commission stated that it 
expected all non-public utility transmission providers to participate 
in the local transmission planning processes required by Order No. 890, 
and that reciprocity dictates that non-public utility transmission 
providers that take advantage of open access due to improved planning 
should be subject to the same requirements as public utility 
transmission providers.\13\ The Commission stated that a coordinated, 
open, and transparent regional planning process cannot succeed unless 
all transmission owners participate. However, the Commission did not 
invoke its authority under FPA section 211A, which allows the 
Commission to require an unregulated transmitting utility (i.e., a non-
public utility transmission provider) to provide transmission services 
on a comparable and not unduly discriminatory or preferential 
basis.\14\ The Commission instead stated that if it found, on the 
appropriate record, that non-public utility transmission providers are 
not participating in the transmission planning processes required by 
Order No. 890, then the Commission may exercise its authority under FPA 
section 211A on a case-by-case basis.
---------------------------------------------------------------------------

    \13\ Id. P 441.
    \14\ FPA section 211A(b) provides, in pertinent part, that ``the 
Commission may, by rule or order, require an unregulated 
transmitting utility to provide transmission services--(1) at rates 
that are comparable to those that the unregulated transmitting 
utility charges itself; and (2) on terms and conditions (not 
relating to rates) that are comparable to those under which the 
unregulated transmitting utility provides transmission services to 
itself and that are not unduly discriminatory or preferential.'' 16 
U.S.C. 824j.
---------------------------------------------------------------------------

    20. On December 7, 2007, pursuant to Order No. 890, most public 
utility transmission providers and several non-public utility 
transmission providers submitted compliance filings that describe their 
proposed transmission

[[Page 49848]]

planning processes.\15\ The Commission addressed these filings in a 
series of orders that were issued throughout 2008. Generally, the 
Commission accepted the compliance filings to be effective on December 
7, 2007, subject to further compliance filings as necessary for the 
proposed transmission planning processes to satisfy the nine Order No. 
890 transmission planning principles. The Commission issued additional 
orders on Order No. 890 transmission planning compliance filings in the 
spring and summer of 2009.
---------------------------------------------------------------------------

    \15\ A small number of public utility transmission providers 
were granted extensions.
---------------------------------------------------------------------------

    21. As a result of these compliance filings, regional transmission 
organization (RTO) and independent system operators (ISO) have enhanced 
their regional transmission planning processes, making them more open, 
transparent, and inclusive. Regions of the country outside of RTO and 
ISO regions also have made significant strides with respect to 
transmission planning by working together to enhance existing, or 
create new, regional transmission planning processes.\16\ These 
improvements to transmission planning processes have given stakeholders 
the ability to participate in the identification of regional 
transmission needs and corresponding solutions, thereby facilitating 
the development of more efficient and cost-effective transmission 
expansion plans. This Final Rule expands upon the reforms begun in 
Order No. 890 by addressing new concerns that have become apparent in 
the Commission's ongoing monitoring of these matters.
---------------------------------------------------------------------------

    \16\ The regional transmission planning processes that public 
utility transmission providers in regions outside of RTOs and ISOs 
have relied on to comply with certain requirements of Order No. 890 
are the North Carolina Transmission Planning Collaborative, 
Southeast Inter-Regional Participation Process, SERC Reliability 
Corporation, ReliabilityFirst Corporation, Mid-Continent Area Power 
Pool, Florida Reliability Coordination Council, WestConnect, 
ColumbiaGrid, and Northern Tier Transmission Group.
---------------------------------------------------------------------------

B. Technical Conferences and Notice of Request for Comments on 
Transmission Planning and Cost Allocation

    22. In several of the above-noted orders issued in 2008 and early 
2009 on filings submitted to comply with the Order No. 890 transmission 
planning requirements, the Commission stated that it would continue to 
monitor implementation of these transmission planning processes. The 
Commission also announced its intention to convene regional technical 
conferences in 2009.
    23. Consistent with the Commission's announcement, Commission staff 
in September 2009 convened three regional technical conferences in 
Philadelphia, Atlanta, and Phoenix, respectively. The focus of the 
technical conferences was to: (1) Determine the progress and benefits 
realized by each transmission provider's transmission planning process, 
obtain customer and other stakeholder input, and discuss any areas that 
may need improvement; (2) examine whether existing transmission 
planning processes adequately consider needs and solutions on a 
regional or interconnectionwide basis to ensure adequate and reliable 
supplies at just and reasonable rates; and (3) explore whether existing 
transmission planning processes are sufficient to meet emerging 
challenges to the transmission system, such as the development of 
interregional transmission facilities and the integration of large 
amounts of location-constrained generation. Issues discussed at the 
technical conferences included the effectiveness of the current 
transmission planning processes, the development of regional and 
interregional transmission plans, and the effectiveness of existing 
cost allocation methods used by transmission providers and alternatives 
to those methods.
    24. Following these technical conferences, the Commission in 
October 2009 issued a Notice of Request for Comments.\17\ The October 
2009 Notice presented numerous questions with respect to enhancing 
regional transmission planning processes and allocating the cost of 
transmission. In response to the October 2009 Notice, the Commission 
received 107 initial comments and 45 reply comments.
---------------------------------------------------------------------------

    \17\ Federal Energy Regulatory Commission, Notice of Request for 
Comments, Transmission Planning Processes under Order No. 890; 
Docket No. AD09-8-000, October 8, 2009 (October 2009 Notice).
---------------------------------------------------------------------------

C. Additional Developments Since Issuance of Order No. 890

    25. Other developments with important implications for transmission 
planning have occurred amid the above-noted Order No. 890 compliance 
efforts on transmission planning and as the Commission gathered 
information through the technical conferences and the October 2009 
Notice discussed above.
    26. For example, in February 2009, Congress enacted the American 
Recovery and Reinvestment Act (ARRA), which provided $80 million for 
the U.S. Department of Energy (DOE), in coordination with the 
Commission, to support the development of interconnection-based 
transmission plans for the Eastern, Western, and Texas 
interconnections. In seeking applications for use of those funds, DOE 
described the initiative as intended to: Improve coordination between 
electric industry participants and states on the regional, 
interregional, and interconnectionwide levels with regard to long-term 
electricity policy and planning; provide better quality information for 
industry planners and state and federal policymakers and regulators, 
including a portfolio of potential future supply scenarios and their 
corresponding transmission requirements; increase awareness of required 
long-term transmission investments under various scenarios, which may 
encourage parties to resolve cost allocation and siting issues; and 
facilitate and accelerate development of renewable energy or other low-
carbon generation resources.\18\
---------------------------------------------------------------------------

    \18\ Department of Energy, Recovery Act--Resource Assessment and 
Interconnection-Level Transmission Analysis and Planning Funding 
Opportunity Announcement, at 5-6 (June 15, 2009).
---------------------------------------------------------------------------

    27. In December 2009, DOE announced award selections for much of 
this ARRA funding. In each interconnection, applicants awarded funds 
under what DOE defined as Topic A are responsible for conducting 
interconnection-level analysis and transmission planning. Applicants 
awarded funds under Topic B are to facilitate greater cooperation among 
states within each interconnection to guide the analyses and planning 
performed under Topic A.\19\ Broad participation in sessions to date 
related to this initiative suggest that the availability of federal 
funds to pursue these goals has increased awareness of the potential 
for greater coordination among regions in transmission planning.
---------------------------------------------------------------------------

    \19\ Id. at 4-8.
---------------------------------------------------------------------------

    28. In describing the activities undertaken under this transmission 
analysis and planning initiative, DOE staff leading the project has 
explained that its activities are based on the premise that the 
electricity industry faces a major long-term challenge in ensuring an 
adequate, affordable and environmentally sensitive energy supply and 
that an open, transparent, inclusive, and collaborative process for 
transmission planning is essential to securing this energy supply.\20\ 
To that end, DOE staff has stressed that all stakeholders need to be 
involved in

[[Page 49849]]

assessing options to meeting this future need and that ARRA funds are 
``seed money'' to help establish capabilities to address transmission 
planning issues.\21\ In DOE staff's view, the goal of this funding is 
to help planners develop a portfolio of long-term energy supply and 
demand for future needs and associated transmission requirements to 
assess the implications of these alternative future energy scenarios 
and identify facilities appropriate for consideration in the 
development of long-term infrastructure plans. Key deliverables of the 
DOE-funded planning activities are 10- and 20-year plans that analyze 
the transmission needs of each interconnection under a range of 
scenarios.
---------------------------------------------------------------------------

    \20\ Department of Energy, ``DOE Initiative Regarding 
Interconnection-Level Transmission Analysis and Planning;'' 
presented at the NGA Transmission Roundtable by David Meyer of DOE's 
Office of Electricity Delivery and Energy Reliability, January 25, 
2011.
    \21\ Id.
---------------------------------------------------------------------------

    29. While the results of these planning efforts are not yet 
available, there is already a growing body of evidence that, in DOE's 
words, ``[s]ignificant expansion of the transmission grid will be 
required under any future electric industry scenario.'' \22\ In its 
most recent Long-Term Reliability Assessment, North American Electric 
Reliability Corporation (NERC) identifies 39,000 circuit-miles of 
projected high-voltage transmission over the next 10 years.\23\ NERC 
estimates that roughly a third of these transmission facilities will be 
needed to integrate variable and renewable generation.\24\ Much of this 
investment in renewable generation is being driven by renewable 
portfolio standards adopted by states. Some 28 states and the District 
of Columbia have now adopted renewable portfolio standard measures. In 
addition, there are 9 states with non-binding goals. The key difference 
is that the states with requirements usually have financial penalties 
for non-compliance, known as alternative compliance payments. States 
with non-binding goals usually have no financial penalty, although some 
have instituted financial incentives for meeting the goal (e.g., 
Virginia). These measures typically require that a certain percentage 
of energy sales (MWh) or installed capacity (MW) come from renewable 
energy resources, with the target level and qualifying resources 
varying among the renewable portfolio standard measures. Most of these 
portfolio standards are set to increase annually, further amplifying 
the potential need for transmission facilities.
---------------------------------------------------------------------------

    \22\ Department of Energy, 20% Wind Energy by 2030, at 93 (July 
2008).
    \23\ NERC 2010 Assessment at 22.
    \24\ Id. at 24.
---------------------------------------------------------------------------

II. The Need for Reform

A. Proposed Rule

    30. In light of the changes occurring within the electric industry, 
and based on the Commission's experience in implementing Order No. 890 
and comments submitted in response to the October 2009 Notice, the 
Commission issued the Proposed Rule on June 17, 2010 identifying 
further reforms to the pro forma OATT in the areas of transmission 
planning and cost allocation. These reforms, discussed in detail below, 
were aimed at ensuring that the transmission planning and cost 
allocation requirements established in Order No. 890 continue to result 
in the provision of Commission-jurisdictional service at rates, terms 
and conditions that are just and reasonable and not unduly 
discriminatory or preferential. The Commission received roughly 5,700 
pages of initial and reply comments in response. Based on these 
comments, the Commission concludes that amendment of the transmission 
planning and cost allocation requirements established in Order No. 890 
is necessary at this time to ensure that Commission-jurisdictional 
services are provided at rates, terms and conditions that are just and 
reasonable and not unduly discriminatory or preferential.
    31. The Commission noted in the Proposed Rule that transmission 
planning processes, particularly at the regional level, have seen 
substantial improvement through compliance with Order No. 890. However, 
the Commission explained that changes in the nation's electric power 
industry since issuance of Order No. 890 required the Commission to 
consider additional reforms to transmission planning and cost 
allocation to reflect these new circumstances. The Commission stated 
its intention was not to disrupt the progress being made with respect 
to transmission planning and investment in transmission infrastructure, 
but rather 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 services are provided at rates, terms and conditions 
that are just and reasonable and not unduly discriminatory or 
preferential.

B. Comments

    32. A number of commenters generally support the Commission's 
decision to initiate a rulemaking proceeding that proposes reforms to 
the transmission planning and cost allocation processes.\25\ Several of 
these commenters state that inadequate transmission planning and cost 
allocation processes have impeded the development of transmission 
infrastructure.\26\
---------------------------------------------------------------------------

    \25\ E.g., 26 Public Interest Organizations; AEP; American 
Transmission; AWEA; Anbaric and PowerBridge; Atlantic Grid; Colorado 
Independent Energy Association; Conservation Law Foundation; Duke; 
East Texas Cooperatives; Energy Future Coalition; Exelon; 
Gaelectric; Green Energy Express and 21st Century; Iberdrola 
Renewables; Imperial Irrigation District; Integrys; ISO New England; 
ITC Companies; MidAmerican; Multiparty Commenters; National Audubon 
Society; National Grid; New York ISO; New York PSC; NextEra; 
Northwest & Intermountain Power Producers Coalition; Old Dominion 
Electric Cooperative; Pennsylvania PUC; Ignacio Perez-Arriaga; 
Senators Dorgan and Reid; SPP; Transmission Access Policy Study 
Group; Transmission Dependent Utility Systems; Western Grid Group; 
Wind Coalition; WIRES; and Wisconsin Electric.
    \26\ E.g., AEP; AWEA; Exelon; Iberdrola Renewables; ITC 
Companies; MidAmerican; and NextEra.
---------------------------------------------------------------------------

    33. For example, Transmission Dependent Utility Systems state that 
they support the primary objective of the Proposed Rule to correct 
deficiencies in transmission planning and cost allocation processes so 
that the transmission grid can better support wholesale markets and 
ensure that jurisdictional services are provided at rates, terms, and 
conditions that are just and reasonable and not unduly discriminatory 
or preferential. Exelon argues that the current system of disconnected 
priorities and mixed criteria is simply not working. Pennsylvania PUC 
encourages the Commission to eliminate the current uncertainty 
regarding planning and paying for future transmission expansion and 
upgrades.
    34. MidAmerican adds that transmission has grown from an industry 
sector focused on rebuilds, reliability improvements on existing 
infrastructure, and construction of generation-dependent 
interconnection facilities, to one where new and upgraded transmission 
infrastructure is necessary to effectuate the expansion of regional 
power markets, promote a more reliable transmission system, accommodate 
increasing reliance on renewable generation sources, and address the 
uncertainty of the future role of existing conventional generation. 
AWEA contends that existing processes for planning and paying for 
transmission are not sufficient to meet the emerging challenges to the 
transmission system. AWEA argues that many cost allocation 
methodologies, as they are applied today, are flawed, which together 
with the fragmented and short-term transmission planning regimes 
prevalent today, have often

[[Page 49850]]

stifled investment in, or otherwise led to the inefficient use and 
inadequate expansion of the nation's transmission network. Senators 
Dorgan and Reid state that better coordination of regional transmission 
planning and clarifying cost allocation are two important steps in 
overcoming hurdles to developing the nation's vast renewable energy 
resources and providing clean energy jobs. National Grid contends that 
the creation of a robust transmission system is imperative to achieving 
important policy goals, environmental objectives, market efficiencies, 
and the integration of renewable and distributed resources into 
electric power markets.
    35. NextEra agrees on reply that there is a need for generic reform 
at this time, stating that there is a sufficient basis for the 
Commission to proceed with a rulemaking proceeding and that there is 
ample evidence of the pressing need to enhance the transmission grid. 
NextEra states that the Proposed Rule demonstrates how and why existing 
transmission planning and cost allocation rules are inadequate.
    36. A number of commenters provide specific examples of 
developments that further demonstrate the need for reform. Colorado 
Independent Energy Association states that, in WestConnect, regional 
transmission providers are not ignoring the problem of transmission 
constraints, but that development of transmission facilities is not 
being undertaken and, second, transmission facilities are not being 
properly sized. In its view, the problems can be traced to the absence 
of cost allocation methods or the lack of means for identifying the 
most needed projects and pursuing them to completion.
    37. Iberdrola Renewables contends that the lack of transmission 
expansion in the MISO has led to significant congestion in areas with 
extensive operating wind generation. It states that the MISO has 
reported that wind curtailments primarily caused by congestion averaged 
five percent for the first six months of 2010 compared with 2 percent 
on average in 2009. Exelon adds that the lack of coordination between 
the MISO and PJM transmission planning regions has resulted in a 
significant increase in the out-of-merit dispatch of generation on the 
Commonwealth Edison system to maintain NERC reliability requirements. 
Exelon states that these events have increased from 31 in 2006 to 280 
in 2009, and they result in higher costs on the system and excessive 
wear and tear on equipment.
    38. Brattle Group states that it has identified approximately 130 
mostly conceptual and often overlapping planned transmission projects 
throughout the country with a total cost of over $180 billion.\27\ It 
contends that a large portion of these projects will not be built due 
to overlaps and deficiencies in transmission planning and cost 
allocation processes. Brattle Group states that many of the benefits 
associated with economic and public policy projects are difficult to 
quantify and, without changes to transmission planning and cost 
allocation processes, many of these projects may fail to gain the 
needed support for approval, permitting, and cost recovery.
---------------------------------------------------------------------------

    \27\ Brattle Group, Attachment at 5.
---------------------------------------------------------------------------

    39. Other commenters question the need for Commission action at 
this time, urging the Commission to be more rigorous in its proposed 
findings and holdings and arguing that the Proposed Rule is not 
supported by substantial evidence.\28\ Large Public Power Council 
disagrees with the Commission's assertions in the Proposed Rule that 
state that renewable portfolio standards have contributed to the need 
for new transmission. Large Public Power Council states that the 
Commission offers no factual evidence to support its assertions \29\ 
and that the evidence available actually weighs against the Commission. 
Large Public Power Council states that renewable portfolio standards 
have not increased meaningfully since the Commission issued Order No. 
890. Furthermore, Large Public Power Council cites a report produced by 
Edison Electric Institute that states that the members of Edison 
Electric Institute are making significant and growing investments in 
transmission infrastructure, including interstate projects and projects 
that will facilitate the integration of renewable resources. Moreover, 
Large Public Power Council contends that the Commission offers no 
evidence that the reforms of the type proposed are a necessary or 
satisfactory solution to the perceived problem.
---------------------------------------------------------------------------

    \28\ E.g., Ad Hoc Coalition of Southeastern Utilities; Salt 
River Project; Large Public Power Council (each commenter cites 
National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (DC Cir. 2006) 
(National Fuel)); Large Public Power Council (citing Associated Gas 
Distrib. v. FERC, 824 F.2d 981 (DC Cir. 1985) (Associated Gas 
Distributors)); PSEG Companies; Salt River Project; and San Diego 
Gas & Electric.
    \29\ Citing Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 
148-154 (Large Public Power Council cites to the following two 
assertions in the Proposed Rule: ``Further expansion of regional 
power markets has led to a growing need for new transmission 
facilities that cross several utility, RTO, ISO or other regions.'' 
(Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 150); and ``* * * 
the increasing adoption of state resource policies, such as 
renewable portfolio standard measures, has contributed to rapid 
growth of location-constrained renewable energy resources that are 
frequently remote from load centers, as well as a growing need for 
new transmission facilities across several utility and/or RTO or ISO 
regions.'' (Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 151)).
---------------------------------------------------------------------------

    40. Replying to commenters that stress the need for reform, 
discussed above, several commenters argue that none provides evidence 
supporting the need for a nationwide rule at this time.\30\ Ad Hoc 
Coalition of Southeastern Utilities states that commenters such as 
Exelon and Multiparty Commenters provide only anecdotes supporting 
their contention that there is a need to reform transmission planning 
and cost allocation processes, and argues that these individual issues 
can be addressed on a case-specific basis rather than through generic 
rules. Joined by Southern Companies, Ad Hoc Coalition of Southeastern 
Utilities argues that factual allegations of transmission expansion 
deficiencies are not applicable to the Southeast, pointing to their 
robust transmission grid. They state that, to the extent these 
allegations raise issues for other regions, then they should be 
addressed within those regions and that these issues do not merit 
nationwide treatment.\31\ Additionally, Ad Hoc Coalition of 
Southeastern Utilities asserts that existing planning processes under 
Order No. 890 have not been in place long enough to determine whether 
reforms are needed, and other commenters assert that existing planning 
processes are working well.\32\ PSEG Companies assert that the real 
issue is the siting process, which makes it difficult to actually build 
projects even if they are truly needed to maintain system reliability.
---------------------------------------------------------------------------

    \30\ E.g., Ad Hoc Coalition of Southeastern Utilities; Large 
Public Power Council; San Diego Gas & Electric; and Southern 
Companies.
    \31\ Ad Hoc Coalition of Southeastern Utilities, Large Public 
Power Council and Southern Companies cite to Associated Gas 
Distributors, 824 F.2d 981 at 1019.
    \32\ E.g., PSEG Companies and Salt River Project.
---------------------------------------------------------------------------

    41. Indianapolis Power & Light states that the Commission has not 
undertaken any type of analysis to find out what needs to be built, 
where it needs to be built, and who needs to build it. Indianapolis 
Power & Light asserts that the Commission has not looked closely at the 
different regions of the country to determine which areas could benefit 
from the new proposed reforms. Indianapolis Power & Light states that 
the Commission has not sufficiently demonstrated a need for this 
rulemaking and should consider whether its broad-based application is 
necessary in the first place. San Diego Gas & Electric recommends that 
the Commission not issue a Final Rule at this time, arguing

[[Page 49851]]

that doing so based on the current proposals would disrupt and delay 
the build-out of the transmission grid and cause transmission providers 
to redirect resources away from that primary objective to the 
inevitable legal and compliance challenges to this Final Rule.

C. Commission Determination

    42. The Commission concludes that it is appropriate to act at this 
time to adopt the package of reforms contained in this Final Rule. Our 
review of the record, as well as the recent studies discussed above, 
indicates that the transmission planning and cost allocation 
requirements established in Order No. 890 provide an inadequate 
foundation for public utility transmission providers to address the 
challenges they are currently facing or will face in the near future. 
Although focused on discrete aspects of transmission planning and cost 
allocation processes, the reforms adopted in this Final Rule are 
designed to work together to ensure an opportunity for more 
transmission projects to be considered in the transmission planning 
process on an equitable basis and increase the likelihood that 
transmission facilities in the transmission plan will move forward to 
construction. The Commission's actions today therefore will enhance the 
ability of the transmission grid to support wholesale power markets 
and, in turn, ensure that Commission-jurisdictional transmission 
services are provided at rates, terms, and conditions that are just and 
reasonable and not unduly discriminatory or preferential.
    43. The Commission acknowledges that transmission planning 
processes have seen substantial improvements, particularly at the 
regional level, in the relatively short time since the issuance of 
Order No. 890. Moreover, as some commenters note, transmission planning 
processes in many regions continue to evolve as public utility 
transmission providers and stakeholders explore new ways of addressing 
mutual needs. However, the Commission is concerned that the existing 
requirements of Order No. 890 regarding transmission planning and cost 
allocation are insufficient to ensure that this evolution will occur in 
a manner that ensures that the rates, terms and conditions of service 
by public utility transmission providers are just and reasonable and 
not unduly discriminatory. As a number of commenters contend, 
inadequate transmission planning and cost allocation requirements may 
be impeding the development of beneficial transmission lines or 
resulting in inefficient and overlapping transmission development due 
to a lack of coordination, all of which contributes to unnecessary 
congestion and difficulties in obtaining more efficient or cost-
effective transmission service.
    44. The increase in transmission investment in recent years, as 
noted in the report produced by Edison Electric Institute and cited by 
Large Public Power Council,\33\ does not mitigate our need to act at 
this time. To the contrary, as discussed below, the recent increase in 
transmission investment supports issuance of this Final Rule to ensure 
that the Commission's transmission planning and cost allocation 
requirements are adequate to support more efficient and cost-effective 
investment decisions moving forward. In its report, Edison Electric 
Institute states that its members have steadily increased investment in 
transmission over the period from 2001 to 2009, resulting in 
approximately $55.3 billion in new transmission facilities.\34\ NERC 
confirms the recent increase in investment in its 2010 Long-Term 
Reliability Assessment.\35\ This trend appears to be only the beginning 
of a longer-term period of investment in new transmission facilities. 
In another report commissioned by Edison Electric Institute, Brattle 
Group suggests that approximately $298 billion of new transmission 
facilities will be required over the period from 2010 to 2030.\36\ 
NERC's analysis of the past 15 years of transmission development 
confirms the significant increase in future transmission investment, 
showing that additional transmission planned for construction during 
the next five years nearly triples the average miles that have 
historically been constructed.\37\
---------------------------------------------------------------------------

    \33\ Large Public Power Council (citing Edison Electric 
Institute report, available at http://www.eei.org/ourissues/ElectricityTransmission/Documents/Trans_Project_lowres.pdf).
    \34\ Edison Electric Institute at v.
    \35\ NERC 2010 Assessment at 25; see also Brattle Group, 
Attachment at 4 (noting rapid increase in transmission development, 
from $2 billion annually in the 1990s to $8 billion annual in 2008 
and 2009).
    \36\ Transforming America's Power Industry at 37, http://www.eei.org/ourissues/finance/Documents/Transforming_Americas_Power_Industry.pdf.
    \37\ NERC 2010 Long-Term Reliability Assessment at 25.
---------------------------------------------------------------------------

    45. The need for additional transmission facilities is being 
driven, in large part, by changes in the generation mix. As NERC notes 
in its 2009 Assessment, existing and potential environmental regulation 
and state renewable portfolio standards are driving significant changes 
in the mix of generation resources, resulting in early retirements of 
coal-fired generation, an increasing reliance on natural gas, and 
large-scale integration of renewable generation.\38\ NERC has 
identified approximately 131,000 megawatts of new generation planned 
for construction over the next ten years, with the largest fuel-type 
growth in gas-fired and wind generation resources.\39\ These shifts in 
the generation fleet increase the need for new transmission. 
Additionally, the existing transmission system was not built to 
accommodate this shifting generation fleet. Of the total miles of bulk 
power transmission under construction, planned, and in a conceptual 
stage, NERC estimates that 50 percent will be needed strictly for 
reliability and an additional 27 percent will be needed to integrate 
variable and renewable generation across North America.\40\
---------------------------------------------------------------------------

    \38\ NERC 2009 Long-Term Reliability Assessment at 8; see also 
supra P 29 (summarizing current state renewable portfolio 
standards).
    \39\ NERC 2010 Long-Term Reliability Assessment at 12.
    \40\ Id. at 24.
---------------------------------------------------------------------------

    46. Rather than demonstrating a lack of need for action, as claimed 
by some commenters, the recent increases in constructed and planned 
transmission facilities supports issuance of this Final Rule at this 
time to ensure that the Commission's transmission planning and cost 
allocation requirements are adequate to support more efficient and 
cost-effective investment decisions. The increased focus on investment 
in new transmission projects makes it even more critical to implement 
these reforms to ensure that the more efficient or cost-effective 
projects come to fruition. The record in this proceeding and the 
reports cited above 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. It is therefore critical that the Commission act now to 
address deficiencies to ensure that more efficient or cost-effective 
investments are made as the industry addresses its challenges.
    47. As explained below, each of the individual reforms adopted by 
the Commission is intended to address specific deficiencies in the 
Commission's existing transmission planning and cost allocation 
requirements. Through this package of reforms, the Commission seeks to 
ensure that each public utility transmission provider will work within 
its transmission planning region to create a regional transmission plan 
that identifies transmission facilities needed to meet reliability, 
economic and Public Policy Requirements, including fair

[[Page 49852]]

consideration of lines proposed by nonincumbents, with cost allocation 
mechanisms in place to facilitate lines moving from planning to 
development. Although focused on particular aspects of the Commission's 
transmission planning and cost allocation requirements, these reforms 
are integrally related and should be understood as a package that is 
designed to reform processes and procedures that, if left in place, 
could result in Commission-jurisdictional services being provided at 
rates that are unjust and unreasonable and unduly discriminatory or 
preferential.
    48. A number of commenters maintain that the Commission in the 
Proposed Rule failed to provide adequate evidence to support a finding 
under section 206 of the FPA that the reforms adopted in this Final 
Rule are necessary to ensure that Commission-jurisdictional services 
are provided at rates, terms and conditions that are just and 
reasonable and not unduly discriminatory or preferential. Section 
313(b) of the FPA makes Commission findings of fact conclusive if they 
are supported by substantial evidence.\41\ When applied in a rulemaking 
context, ``the substantial evidence test is identical to the familiar 
arbitrary and capricious standard.'' \42\ The Commission thus must show 
that a ``reasonable mind might accept'' that the evidentiary record 
here is ``adequate to support a conclusion,'' \43\ in this case that 
this Final Rule is needed ``to correct deficiencies in transmission 
planning and cost allocation processes,'' as described.\44\ In the 
legal authority sections throughout this Final Rule, the Commission 
discusses how the cases cited by commenters demonstrate that the 
Commission has met its burden.
---------------------------------------------------------------------------

    \41\ 16 U.S.C. 825l(b).
    \42\ Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1156 (1985); see 
also Associated Gas Distributors v. FERC, 824 F.2d 981 at 1018.
    \43\ Dickenson v. Zurko, 527 U.S. 150, 155 (1999).
    \44\ Proposed Rule, FERC Stats & Regs. ] 32,660 at P 1.
---------------------------------------------------------------------------

    49. Commenters that maintain that the Commission's proposal is not 
supported by substantial evidence demand that the Commission identify 
evidence that is far in excess of what a reasonable person would 
require. We thus disagree with such comments, including Indianapolis 
Power & Light's, that it is necessary for the Commission to determine 
what needs to be built, where it needs to be built, and who needs to 
build it. That is not, and is not required to be, the intent of this 
rulemaking. This rulemaking reforms processes and is not intended to 
address such questions. No commenter has contested the need for 
additional transmission facilities, and numerous examples have been 
provided here of transmission planning and cost allocation impediments 
to the development of such facilities. Our intent here is to continue 
to ensure that public utility transmission providers use just and 
reasonable transmission planning processes and procedures, as required 
by Order Nos. 888 and 890, to provide for the needs of their 
transmission customers. Such planning may require public utility 
transmission providers--in consultation with stakeholders--to determine 
what needs to be built, where it needs to be built, and who needs to 
build it, but the Commission is not making such determinations here.
    50. We also reject the characterization of factual examples 
presented to demonstrate the need for reform as anecdotal evidence. A 
wide range of concerns have been raised by commenters, and the 
Commission need not, and should not, wait for systemic problems to 
undermine transmission planning before it acts. The Commission 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. Transmission 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 
from present out to 20, 30 years or more in the future. In addition, 
the development of transmission facilities can involve long lead times 
and complex problems related to design, siting, permitting, and 
financing. Given the need to deal with these matters over a long time 
horizon, it is appropriate and prudent that we act at this time rather 
than allowing the types of problems described above to continue or to 
increase. In light of these conditions and as explained below, we find 
that it is reasonable to take generic action through this rulemaking 
proceeding.
    51. A brief consideration of the two cases that commenters rely on 
to argue that the Commission has not satisfied the substantial evidence 
standard helps to demonstrate that the standard has been fully met. In 
National Fuel, the court found that the Commission had not met the 
substantial evidence standard when it sought to extend its standards of 
conduct that regulate natural gas pipelines' interactions with their 
marketing affiliates to their interactions with their non-marketing 
affiliates. The court noted that it had upheld the standards of conduct 
as applied to pipelines and their marketing affiliates because the 
Commission had shown both a theoretical threat that pipelines could 
grant undue preferences to their marketing affiliates and evidence that 
such abuse had occurred.\45\ In finding that the Commission had not met 
the substantial evidence standard when seeking to extend the standards 
of conduct, the court noted that the Commission had not cited a single 
example of abuse by non-marketing affiliates. It concluded that the 
Commission relied either on examples of abuse or comments from the 
rulemaking that simply reiterated a theoretical potential for 
abuse.\46\ The court remanded the matter and noted that if the 
Commission chose to proceed it could even rely solely on a theoretical 
threat if it could show how the threat justified the costs that the 
rules would create.\47\
---------------------------------------------------------------------------

    \45\ National Fuel, 468 F.3d 831 at 839.
    \46\ Id. at 841.
    \47\ Id. at 844.
---------------------------------------------------------------------------

    52. Our action in this Final Rule is entirely consistent with the 
standards that the court set forth in National Fuel. We conclude that 
the narrow focus of current planning requirements and shortcomings of 
current cost allocation practices create an environment that fails to 
promote the more efficient and cost-effective development of new 
transmission facilities, and that addressing these issues is necessary 
to ensure just and reasonable rates. In other words, the problem that 
the Commission seeks to resolve represents a ``theoretical threat,'' in 
the words of the National Fuel decision, the features of which are 
discussed throughout the body of this Final Rule in the context of each 
of the reforms adopted here. This threat is significant enough to 
justify the requirement imposed by this Final Rule. It is not one that 
can be addressed adequately or efficiently through the adjudication of 
individual complaints. The problems that we seek to resolve here stem 
from the absence of planning processes that take a sufficiently broad 
view of both the tasks involved and the means of addressing them. 
Individual adjudications by their nature focus on discrete questions of 
a specific case. Rules setting forth general principles are necessary 
to ensure that adequate planning processes are in place.
    53. Stated in another way, in the terminology of National Fuel, the 
remedy we adopt is justified sufficiently by the ``theoretical threat'' 
identified herein, even without ``record evidence of abuse.'' The 
actual experiences of problems cited in the record herein provide 
additional support for our

[[Page 49853]]

action, but are not necessary to justify the remedy.
    54. Associated Gas Distributors likewise is distinguishable from 
this proceeding. In that case, the court reviewed the Commission's 
rationale in Order No. 436 for industry-wide contract demand adjustment 
conditions, which permitted pipeline customers to reduce their contract 
demand by up to 100 percent over a period of five years.\48\ The court 
held that the Commission failed to develop an adequate rationale for 
authorizing what it characterized as the ``drastic action'' of 100 
percent contract demand reduction, and that the reasons the Commission 
provided ``seem[ed] peripheral to the problem the Commission set out to 
solve.'' \49\ The court also found that one of the Commission's 
arguments while ``highly relevant'' to contract demand reduction, 
failed to support the broad remedy the Commission adopted.\50\ The 
court explained that it was unclear why an industry-wide solution was 
necessary to solve a problem that the Commission suggested applied only 
``to a limited portion of the industry.'' \51\
---------------------------------------------------------------------------

    \48\ Associated Gas Distributors, 824 F.2d 981 at 1013.
    \49\ Id. at 1018-19.
    \50\ Id. at 1019.
    \51\ Id. at 1018-19.
---------------------------------------------------------------------------

    55. We find that the facts and findings of Associated Gas 
Distributors are in no way comparable to the matters involved in this 
Final Rule. We disagree with commenters that characterize our reasoning 
as inadequate or peripheral to the problems that the Commission has 
identified in this proceeding. To the contrary, the reforms adopted 
herein are necessary to address those problems and are supported by the 
reasons set forth in this Final Rule. As discussed herein, the 
Commission finds that the narrow focus of current planning requirements 
and shortcomings of current cost allocation practices create an 
environment that fails to promote the more efficient and cost-effective 
development of new transmission facilities. There is a close 
relationship between those problems and the Commission's actions here 
to identify a minimum set of requirements that must be met to ensure 
that transmission planning processes and cost allocation methods 
subject to its jurisdiction result in Commission-jurisdictional 
services being provided at rates, terms and conditions that are just 
and reasonable and not unduly discriminatory or preferential.
    56. We also disagree with commenters that argue that the reforms 
adopted in this Final Rule will have an impact on industry that is 
comparable to the impact at issue in Associated Gas Distributors. The 
impact in that case involved the potential losses a gas pipeline could 
face from 100 percent contract demand reduction by a customer over a 
period of five years. Such reduction represents the complete 
elimination of expected revenues from gas sales under a contract. By 
contrast, compliance with this Final Rule will involve the adoption and 
implementation of additional processes and procedures. Many public 
utility transmission providers that are subject to this Final Rule 
already engage in processes and procedures of this type.
    57. We acknowledge that some public utility transmission providers 
may need to do more than others to achieve compliance with the 
requirements of this Final Rule. Such differences, however, do not mean 
that the problems identified herein are ``limited to a portion of the 
industry,'' in the terms used in Associated Gas Distributors. Indeed, 
acting on a generic basis is necessary for the Commission to identify 
and implement a minimum set of requirements for transmission planning 
processes and cost allocation methods, as discussed above.
    58. We also disagree with commenters who assert that the Commission 
is relying 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 proposed herein. The courts have made 
clear that the Commission need not make specific factual findings of 
discrimination to promulgate a generic rule to ensure just and 
reasonable rates or eliminate undue discrimination.\52\ In Associated 
Gas Distributors, the court explained that the promulgation of generic 
rate criteria involves the determination of policy goals and the 
selection of the means to achieve them and that courts do not insist on 
empirical data for every proposition upon which the selection depends: 
``[a]gencies do not need to conduct experiments in order to rely on the 
prediction that an unsupported stone will fall.'' \53\ As discussed in 
this Final Rule, the Commission has received many comments arguing that 
commenters have experienced unjust and unreasonable, or unduly 
discriminatory or preferential practices in the transmission planning 
aspects of the transmission service provided by public utility 
transmission providers and that the lack of guidance from the 
Commission has delayed, as well as hindered, transmission projects. We 
have an obligation under section 206 to remedy these unjust and 
unreasonable, or unduly discriminatory or preferential rates, terms, 
and conditions and practices affecting rates.
---------------------------------------------------------------------------

    \52\ TAPS v. FERC, 225 F.3d 667 at 688; National Fuel, 468 F.3d 
831.
    \53\ 824 F.2d 981 at 1008.
---------------------------------------------------------------------------

    59. It is thus clear to us that, notwithstanding the Commission's 
efforts in Order No. 890, deficiencies in the requirements of the 
existing pro forma OATT must be remedied to support the more efficient 
and cost-effective development of transmission facilities used to 
provide Commission-jurisdictional services. Moreover, action is needed 
to address the opportunities to engage in undue discrimination by 
public utility transmission providers. Our actions in this Final Rule 
are necessary to produce rates, terms and conditions that are just and 
reasonable. We therefore exercise our broad remedial authority \54\ 
today to ensure that rates are not unjust and unreasonable and to limit 
the remaining opportunities for undue discrimination.
---------------------------------------------------------------------------

    \54\ Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153, 159 (DC 
Cir. 1967).
---------------------------------------------------------------------------

    60. We also disagree with the commenters that claim 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. While the concerns discussed above that are 
driving the need for these reforms may not affect each region of the 
country equally, we remain concerned that the existing transmission 
planning and cost allocation requirements of Order No. 890 are 
inadequate to ensure the development of more efficient and cost-
effective transmission. It is well established that the choice between 
rulemaking and case-by-case adjudication ``lies primarily in the 
informed discretion of the administrative agency.'' \55\ It is within 
our discretion to conclude that a generic rulemaking, not case-by-case 
adjudications, is the most efficient approach to take to resolve the 
industry-wide problems facing us.
---------------------------------------------------------------------------

    \55\ SEC v. Chenery Corp., 332 U.S. 194, 203 (1947). See also 
Alaska Power & Telephone Co., 98 FERC ] 61,092, at 61,277 (2002); 
Trailblazer Pipeline Co., 79 FERC ] 61,274, at 62,183 (1997).
---------------------------------------------------------------------------

    61. Nevertheless, the Commission recognizes that each transmission 
planning region has unique characteristics and, therefore, this Final 
Rule accords transmission planning regions significant flexibility to 
tailor regional transmission planning and cost allocation processes to 
accommodate these regional differences. The Commission recognizes that 
many transmission planning regions have or are in the process of taking 
steps to

[[Page 49854]]

address some of the concerns described in this Final Rule. We encourage 
those regions to use the objectives and principles discussed in this 
Final Rule to guide continued development and compel them to abide by 
the requirements of this Final Rule.
    62. The Commission recognizes the scope of these requirements, and 
to that end the Commission will continue to make its staff available to 
assist industry regarding compliance matters, as it did after Order No. 
890. As stated above, as public utility transmission providers work 
with their stakeholders to prepare compliance proposals, the Commission 
encourages frequent dialogue with Commission staff to explore issues 
that are specific to each transmission planning region. The Commission 
will monitor progress being made.

D. Use of Terms

    63. Before turning to the requirements of this Final Rule, the 
Commission defines several of the key terms used herein. For purposes 
of this Final Rule, there is a distinction between a transmission 
facility in a regional transmission plan and a transmission facility 
selected in a regional transmission plan for purposes of cost 
allocation. Transmission facilities selected in a regional transmission 
plan for purposes of cost allocation are transmission facilities that 
have been selected pursuant to a transmission planning region's 
Commission-approved regional transmission planning process for 
inclusion in a regional transmission plan for purposes of cost 
allocation because they are more efficient or cost-effective solutions 
to regional transmission needs. Those may include both regional 
transmission facilities, which are located solely within a single 
transmission planning region and are determined to be a more efficient 
or cost-effective solution to a regional transmission need, and 
interregional transmission facilities, which are located within two or 
more neighboring transmission planning regions and are determined by 
each of those regions to be a more efficient or cost-effective solution 
to a regional transmission need. Such transmission facilities often 
will not comprise all of the transmission facilities in the regional 
transmission plan; rather, such transmission facilities may be a subset 
of the transmission facilities in the regional transmission plan. For 
example, such transmission facilities do not include a transmission 
facility in the regional transmission plan but that has not been 
selected in the manner described above, such as a local transmission 
facility or a merchant transmission facility. A local transmission 
facility is a transmission facility located solely within a public 
utility transmission provider's retail distribution service territory 
or footprint that is not selected in the regional transmission plan for 
purposes of cost allocation.
    64. In distinguishing between transmission facilities selected in a 
regional transmission plan for purposes of cost allocation and other 
transmission facilities that also may be in the regional transmission 
plan, we seek to recognize that different regions of the country may 
have different practices with regard to populating their regional 
transmission plans. In some regions, transmission facilities not 
selected for purposes of regional or interregional of cost allocation 
nonetheless may be in a regional transmission plan for informational 
purposes, and the presence of such transmission projects in the 
regional transmission plan does not necessarily indicate an evaluation 
of whether such transmission facilities are more efficient or cost-
effective solutions to a regional transmission need, as is the case for 
transmission facilities selected in a regional transmission plan for 
purposes of cost allocation. By focusing in parts of this Final Rule on 
transmission facilities selected in a regional transmission plan for 
purposes of cost allocation, we do not intend to disturb regional 
practices with regard to other transmission facilities that also may be 
in the regional transmission plan.
    65. We also clarify that the requirements of this Final Rule 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 of this Final Rule. The requirements of this 
Final Rule will apply to the evaluation or reevaluation of any 
transmission facility that occurs after the effective date of the 
public utility transmission provider's filing adopting the transmission 
planning and cost allocation reforms of the pro forma OATT required by 
this Final Rule. We appreciate that transmission facilities often are 
subject to continuing evaluation as development schedules and 
transmission needs change, and that the issuance of this Final Rule is 
likely to fall in the middle of ongoing planning cycles. Each region is 
to determine at what point a previously approved project is no longer 
subject to reevaluation and, as a result, whether it is subject to the 
requirements of this Final Rule.\56\ Our intent here is that this Final 
Rule not delay current studies being undertaken pursuant to existing 
regional transmission planning processes or impede progress on 
implementing existing transmission plans. We direct public utility 
transmission providers to explain in their compliance filings how they 
will determine which facilities evaluated in their local and regional 
planning processes will be subject to the requirements of this Final 
Rule.
---------------------------------------------------------------------------

    \56\ We note that existing planning processes already include 
specific points at which a project will no longer be subject to 
reevaluation.
---------------------------------------------------------------------------

    66. Finally, nothing in this Final Rule should be read as the 
Commission granting approval to build a ``transmission facility in a 
regional transmission plan'' or a ``transmission facility selected in a 
regional transmission plan for purposes of cost allocation.'' For 
purposes of this Final Rule, 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 the facility in Commission-approved rates if such 
facility is built. Nothing in this Final Rule requires that a facility 
in a regional transmission plan or selected in a regional transmission 
plan for purposes of cost allocation be built, nor does it give any 
entity permission to build a facility. Also, nothing in this Final Rule 
relieves any developer from having to obtain all approvals required to 
build such facility.

III. Proposed Reforms: Transmission Planning

    67. This section of the Final Rule has three parts: (A) 
Participation in the regional transmission planning process; (B) 
nonincumbent transmission developers; and (C) interregional 
transmission coordination.

A. Regional Transmission Planning Process

    68. This part of the Final Rule adopts several reforms to improve 
regional transmission planning. First, building on the reforms that the 
Commission adopted in Order No. 890, this Final Rule requires 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. Second, this Final Rule adopts reforms under which

[[Page 49855]]

transmission needs driven by Public Policy Requirements are considered 
in local and regional transmission planning processes. By ``local'' 
transmission planning process, we mean the transmission planning 
process that a public utility transmission provider performs for its 
individual retail distribution service territory or footprint pursuant 
to the requirements of Order No. 890. 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.\57\ This, in turn, will provide assurance that 
rates for transmission services on these systems will reflect more 
efficient or cost-effective solutions for the region. Each of these 
reforms is discussed more fully below.
---------------------------------------------------------------------------

    \57\ As in Order No. 890, the transmission planning requirements 
adopted here do not address or dictate which transmission facilities 
should be either in the regional transmission plan or actually 
constructed. See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 
438. We leave such decisions in the first instance to the judgment 
of public utility transmission providers, in consultation with 
stakeholders participating in the regional transmission planning 
process.
---------------------------------------------------------------------------

    69. Part A of section III has four subsections: (1) Need for reform 
concerning regional transmission planning; (2) legal authority for 
transmission planning reforms; \58\ (3) regional transmission plan and 
Order No. 890 transmission planning principles; and (4) consideration 
of transmission needs driven by Public Policy Requirements.
---------------------------------------------------------------------------

    \58\ Because the legal authority concerns raised by commenters 
with regard to our regional transmission planning reforms and our 
interregional transmission coordination reforms are so closely 
related, we address these concerns together.
---------------------------------------------------------------------------

1. Need for Reform Concerning Regional Transmission Planning
a. Commission Proposal
    70. In the Proposed Rule, the Commission explained that, since the 
issuance of Order No. 890, it has become apparent to the Commission 
that Order No. 890's regional participation transmission planning 
principle may not be sufficient, in and of itself, to ensure an open, 
transparent, inclusive, and comprehensive regional transmission 
planning process. The Commission explained that, to meet that 
principle, each public utility transmission provider is currently 
required to coordinate with interconnected systems to: (1) Share system 
plans to ensure that the plans are simultaneously feasible and 
otherwise use consistent assumptions and data; and (2) identify system 
enhancements that could relieve congestion or integrate new 
resources.\59\ The Commission thus did not require development of a 
transmission plan by each transmission planning region. Moreover, the 
Commission did not require regional transmission planning activities to 
comply with the transmission planning principles established in Order 
No. 890.\60\ As such, the Commission proposed to require each public 
utility transmission provider to participate in a regional transmission 
planning process that satisfies the existing Order No. 890 transmission 
planning principles \61\ and that produces a regional transmission 
plan.
---------------------------------------------------------------------------

    \59\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 45 (citing 
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 523).
    \60\ See Entergy Services, Inc., 124 FERC ] 61,268, at P 104 
(2008).
    \61\ These transmission planning principles are: (1) 
Coordination; (2) openness; (3) transparency; (4) information 
exchange; (5) comparability; (6) dispute resolution; and (7) 
economic planning.
---------------------------------------------------------------------------

    71. The Commission also explained that, while it intended Order No. 
890's economic planning studies transmission planning principle to be 
sufficiently broad to identify solutions that could relieve 
transmission congestion or integrate new resources and loads, including 
transmission facilities to integrate new resources and loads on an 
aggregated or regional basis,\62\ it recognized that its statements 
with respect to the Order No. 890 economic planning studies 
transmission planning principle may have contributed to confusion as to 
whether Public Policy Requirements may be considered in the 
transmission planning process.\63\ The Proposed Rule stated that, when 
conducting transmission planning to serve native load customers, a 
prudent public utility transmission provider will not only plan to 
maintain reliability and consider whether transmission facilities or 
other investments can reduce the overall costs of serving native load, 
but also consider how to enable compliance with relevant Public Policy 
Requirements. The Proposed Rule further stated that, to avoid acting in 
an unduly discriminatory manner, a public utility transmission provider 
must consider these same needs on behalf of all of its customers. The 
Commission also noted that providing for incorporation of Public Policy 
Requirements in transmission planning processes, where applicable, 
could facilitate cost-effective achievement of those requirements.\64\ 
The Commission therefore proposed to require each public utility 
transmission provider to amend its OATT so that its local and regional 
transmission planning processes explicitly provide for consideration of 
Public Policy Requirements.
---------------------------------------------------------------------------

    \62\ Order No. 890's economic planning studies transmission 
planning principle requires that stakeholders be given the right to 
request a defined number of high priority studies annually through 
the transmission planning process, which are intended to identify 
solutions that could relieve transmission congestion or integrate 
new resources and loads, including facilities to integrate new 
resources or loads on an aggregated or regional basis. See Order No. 
890, FERC Stats. & Regs. ] 31,241 at P 547-48.
    \63\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 55-57 & 
n.76.
    \64\ Id. P 63.
---------------------------------------------------------------------------

b. Comments
    72. A number of commenters support the Commission's preliminary 
determination in the Proposed Rule that there is a need to enhance the 
regional transmission planning process.\65\ In supporting the proposal 
to implement new regional transmission planning requirements, 
Pennsylvania PUC argues that the current regional transmission planning 
process does not lend itself to the sort of open and transparent 
processes that allow state commissions to fully contribute to the 
regional transmission planning arena. Iberdrola Renewables states that 
the proposed reforms would advance the sound development of substantial 
new renewable energy resources, which it argues is critical to the 
nation's energy security, economic well-being, and the environment. 
AWEA states that existing transmission planning processes are too 
parochial in design and practice, and it suggests that the proposed 
transmission planning reforms will remedy these deficiencies.
---------------------------------------------------------------------------

    \65\ E.g., 26 Public Interest Organizations; AWEA; Atlantic 
Grid; Clean Line; East Texas Cooperatives; Energy Future Coalition 
Group; Gaelectric; Iberdrola Renewables; Massachusetts Departments; 
NextEra; Pennsylvania PUC; Western Grid Group; and Wind Coalition.
---------------------------------------------------------------------------

    73. However, other commenters argue that there is no need for 
reform of regional transmission planning requirements, at least on a 
nationwide basis.\66\ Ad Hoc Coalition of Southeastern Utilities and 
Southern Companies argue that any problems that may exist regarding 
regional transmission planning are local in nature and the Commission 
should not undertake comprehensive, generic

[[Page 49856]]

reform. They argue that the regional transmission planning concerns 
expressed in the Proposed Rule are not present in the Southeast. 
ColumbiaGrid, Bonneville Power, Avista, and Puget Sound argue that 
regional transmission planning in the Northwest is robust. WestConnect 
makes a similar point regarding its collaborative planning process. 
Avista and Puget Sound state that the proposed reforms could threaten 
the continued viability of ColumbiaGrid's successful collaborative 
approach to planning because of concerns that some ColumbiaGrid members 
may not participate in that process if the Proposed Rule's reforms are 
adopted.
---------------------------------------------------------------------------

    \66\ E.g., Ad Hoc Coalition of Southeastern Utilities; Avista 
and Puget Sound; Bonneville Power; ColumbiaGrid; Indianapolis Power 
& Light; Southern Companies; and WestConnect.
---------------------------------------------------------------------------

    74. Others argue that the Commission should allow existing regional 
transmission planning processes to mature before taking action.\67\ 
Sacramento Municipal Utility District contends that comprehensive 
transmission planning currently exists, planning studies are being 
performed, results are being evaluated, and interested stakeholders are 
actively engaged and, consequently, the Commission need not and should 
not take further action. Modesto Irrigation District states that 
existing regional and interconnectionwide transmission planning 
processes in the West provide an effective and comprehensive way to 
determine transmission needs and the transmission projects that 
efficiently address those needs in a manner that is consistent with the 
bottom up, stakeholder-driven transmission planning processes found in 
Order No. 890.\68\ In reply, California Transmission Planning Group 
states that it agrees with commenters in the Western Interconnection 
that existing regional and interconnectionwide processes should 
continue to mature. It argues that comments expressing frustration with 
its planning process are indicative of the need to provide such 
processes time to mature, noting that its work has matured rapidly in 
the year since it was formed. Coalition for Fair Transmission Policy 
states that transmission investment has accelerated in recent years 
and, as a result, current transmission planning processes are working.
---------------------------------------------------------------------------

    \67\ E.g., California Transmission Planning Group; Sacramento 
Municipal Utility District; and WestConnect.
    \68\ In describing these comments, we use the terms 
``interconnectionwide'' and ``regional'' even though many commenters 
in the western United States used the term ``regional'' for 
interconnectionwide and ``subregional'' for regional. However, we 
will continue to use the terms ``interconnectionwide'' and 
``regional'' in this Final Rule to make these comments clearer to 
readers outside of the West.
---------------------------------------------------------------------------

    75. Others argue that the Proposed Rule would lead to undesirable 
outcomes. California Transmission Planning Group argues that the 
Proposed Rule would require it to transform itself from a regional 
coordinator of transmission studies and planning into a quasi-
adjudicatory arbiter of the relative economic merits of specific 
transmission projects or alternatives and a gatekeeper to cost recovery 
and ratemaking mechanisms. California Transmission Planning Group also 
notes the legal constraints on many of its public agency members from 
assuming certain planning-related responsibilities. NorthWestern 
Corporation (Montana) does not believe the proposed approach is 
workable in the unorganized market areas in the West because the 
transmission provider, not the regional planning entity, has the 
obligation to the Commission through its tariff.
    76. North Carolina Agencies argue that transmission planning must 
be initiated at the local and regional levels subject to state-level 
authority and based on the needs of customers who bear the burdens and 
benefits of the decisions resulting from the planning process. North 
Carolina Agencies also state that transmission developers who offer 
transmission projects as an alternative to locally planned solutions 
must be required to participate in and have their proposals considered 
as part of the relevant state planning process. Imperial Irrigation 
District points to potential confusion in the West, and states that it 
believes that the creation of a new regional transmission planning 
authority would impede, not hasten, transmission development.
    77. However, Multiparty Commenters urge the Commission not to be 
swayed by arguments that reform of the transmission planning and cost 
allocation processes are not necessary simply because there has been an 
increase in transmission investment in the last few years, asserting 
that more investment does not mean that there is enough transmission 
being built to satisfy future needs, such as the interconnection of 
renewable resources. NextEra disagrees with commenters asserting that 
revising transmission planning procedures would disrupt existing 
processes under Order No. 890, arguing that those processes should be 
improved if there is a need to do so, as it would be wasteful to 
withhold needed reforms to observe how current processes would evolve. 
Powerex states that, although progress has been made in transmission 
planning processes since Order No. 890 was issued, more reforms are 
needed to ensure transparency and a level playing field for all 
stakeholders. National Grid agrees that the Commission should not wait 
to exercise its authority to require improvements to transmission 
planning processes. Twenty-six Public Interest Organizations argue that 
Southern Companies' claims that the transmission planning deficiencies 
identified in the Proposed Rule do not pertain to them and that 
implementation of the Proposed Rule would harm existing processes are 
unsupported by the facts and may reflect the inability of planning 
authorities to recognize the limits of their own procedures.
c. Commission Determination
    78. We conclude that it is necessary to act under section 206 of 
the FPA to adopt the regional transmission planning reforms of this 
Final Rule, as discussed more fully below, to ensure just and 
reasonable rates and to prevent undue discrimination by public utility 
transmission providers. Our review of the record, including the 
comments submitted by numerous entities representing a variety of 
diverse viewpoints, makes clear to us that reform is necessary at this 
time. Specifically, we conclude that the existing requirements of Order 
No. 890 are inadequate to ensure that public utility transmission 
providers in each transmission planning region, in consultation with 
stakeholders, identify and evaluate transmission alternatives 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. Moreover, 
the existing requirements of Order No. 890 do not necessarily result in 
the development of a regional transmission plan that reflects the 
identification by the transmission planning region of the set of 
transmission facilities that are more efficient or cost-effective 
solutions for the transmission planning region.
    79. As the Commission explained in the Proposed Rule, when an 
individual public utility transmission provider engages in local 
transmission planning, it considers and evaluates transmission 
facilities and non-transmission alternatives that are proposed and then 
develops a local transmission plan that identifies what transmission 
facilities are needed to meet the needs of its native load (if any), 
transmission customers, and other stakeholders.\69\ Through this 
process, the public utility transmission provider evaluates the

[[Page 49857]]

various alternatives available to determine a set of solutions that 
meet the system's needs more efficiently or cost-effectively than other 
proposed solutions. At the regional level, the Commission has relied on 
such processes when evaluating filings to help ensure that the recovery 
of costs associated with transmission facilities recovered through 
Commission-jurisdictional rates is just and reasonable.\70\
---------------------------------------------------------------------------

    \69\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 51.
    \70\ See, e.g., Transmission Technology Solutions, LLC, et al. 
v. Cal. Indep. Sys. Operator Corp., 135 FERC ] 61,077, at P 84 
(2011) (rejecting complaint regarding California ISO transmission 
planning process and stating ``we find that CAISO reasonably 
concluded that PG&E's project is ultimately the most prudent and 
cost-effective solution. We find that for each of the incumbent and 
non-incumbent proposed projects, CAISO adequately considered lower 
cost alternatives, selected economically efficient solutions, 
accounted for more than just capital costs, and considered 
additional project benefits.'').
---------------------------------------------------------------------------

    80. In some transmission planning regions, a similar level of 
analysis is undertaken by public utility transmission providers at the 
regional level, resulting in the development of a regional transmission 
plan that identifies those transmission facilities that are needed to 
meet the needs of stakeholders in the region. This occurs, for example, 
in each of the existing RTO and ISO regions, which, we note, serve over 
two-thirds of the nation's consumers.\71\ In other transmission 
planning regions, however, as permitted by Order No. 890, public 
utility transmission providers use the regional transmission planning 
process as a forum to confirm the simultaneous feasibility of 
transmission facilities contained in their local transmission plans. We 
conclude that it is necessary to have an affirmative obligation in 
these transmission planning regions to evaluate alternatives that may 
meet the needs of the region more efficiently or cost-effectively. 
Given the potential impact such investments could have on rates for 
Commission-jurisdictional service, we conclude it is necessary to act 
at this time to enhance the transmission planning-related requirements 
imposed in Order No. 890.
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    \71\ See IRC Brings Value to Reliability and Electricity 
Markets, available at http://www.isorto.org/site/c.jhKQIZPBImE/b.2603917/k.B00F/About.htm. As discussed in section V below, to the 
extent existing transmission planning processes satisfy the 
requirements of this Final Rule, public utility transmission 
providers need not revise their OATTs and, instead, should describe 
in their compliance filings how the relevant requirements are 
satisfied by reference to tariff sheets already on file with the 
Commission.
---------------------------------------------------------------------------

    81. In the absence of the reforms implemented below, we are 
concerned that public utility transmission providers may not adequately 
assess the potential benefits of alternative transmission solutions at 
the regional level that may meet the needs of a transmission planning 
region more efficiently or cost-effectively than solutions identified 
by individual public utility transmission providers in their local 
transmission planning process. For example, proactive cooperation among 
public utility transmission providers within a transmission planning 
region could better identify transmission solutions to more efficiently 
or cost-effectively meet the reliability needs of public utility 
transmission providers in the region. Further, regional transmission 
planning could better identify transmission solutions for reliably and 
cost-effectively integrating location-constrained renewable energy 
resources needed to fulfill Public Policy Requirements such as the 
renewable portfolio standards adopted by many states. Similarly, the 
development of transmission facilities that span the service 
territories of multiple public utility transmission providers may 
obviate the need for transmission facilities identified in multiple 
local transmission plans while simultaneously reducing congestion 
across the region. Under the existing requirements of Order No. 890, 
however, there is no affirmative obligation placed on public utility 
transmission providers to explore such alternatives in the absence of a 
stakeholder request to do so. We correct that deficiency in this Final 
Rule.
    82. Based on our review of the record and comments in this 
proceeding, we also require each public utility transmission provider 
to amend its OATT to explicitly provide for consideration of 
transmission needs driven by Public Policy Requirements in both local 
and regional transmission planning processes. As the Commission noted 
in the Proposed Rule, existing transmission planning processes 
generally were not designed to account for, and do not explicitly 
consider, transmission needs driven by Public Policy Requirements. 
While transmission planning processes in some regions have evolved to 
reflect compliance with Public Policy Requirements, our review of the 
comments indicates that some transmission planning processes do not 
consider transmission needs driven by Public Policy Requirements.\72\ 
As a result, some regions are struggling with how to adequately address 
transmission expansion necessary to, for example, comply with renewable 
portfolio standards. These difficulties are compounded by the fact that 
planning transmission facilities necessary to meet state resource 
requirements must be integrated with existing transmission planning 
processes that are based on metrics or tariff provisions focused on 
reliability or, in some cases, production cost savings.
---------------------------------------------------------------------------

    \72\ For example, PJM acknowledges in its comments that under 
its existing transmission planning process, it cannot build 
transmission to anticipate the development of future generation, 
including renewable energy resources, that are not associated with 
specific generator interconnection requests.
---------------------------------------------------------------------------

    83. As the Commission explained in the Proposed Rule, consideration 
of Public Policy Requirements raises issues similar to those raised in 
the Commission's discussion in Order No. 890 of the economic planning 
studies transmission planning principle.\73\ When conducting 
transmission planning to serve native load customers, a prudent 
transmission provider will not only plan to maintain reliability and 
consider whether transmission upgrades or other investments can reduce 
the overall costs of serving native load, but also consider how to plan 
for transmission needs driven by Public Policy Requirements.\74\ 
Therefore, we conclude that, to avoid acting in an unduly 
discriminatory manner against transmission customers that serve other 
loads, a public utility transmission provider must consider these same 
transmission needs for all of its transmission customers. Moreover, 
given that consideration of transmission needs driven by Public Policy 
Requirements could facilitate the more efficient and cost-effective 
achievement of those requirements, we conclude the reforms adopted 
herein are necessary to ensure that rates for Commission-jurisdictional 
services are just and reasonable.
---------------------------------------------------------------------------

    \73\ In Order No. 890, the Commission intended the economic 
planning studies principle to be sufficiently broad to identify 
solutions that could relieve transmission congestion or integrate 
new resources and loads, including facilities to integrate new 
resources and loads on an aggregated or regional basis. Order No. 
890, FERC Stats. & Regs. ] 31,241 at P 523.
    \74\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 63.
---------------------------------------------------------------------------

    84. Turning to the commenters opposed to these reforms, we are not 
persuaded by those who argue that any problems with existing 
transmission planning are local in nature and that the Commission 
should not undertake comprehensive, generic reform. As we explain above 
in the section on the general need for the reforms in this Final Rule, 
the Commission need not make specific factual findings to promulgate a 
generic rule to ensure

[[Page 49858]]

rates, terms and conditions of jurisdictional services are just and 
reasonable and not unduly discriminatory or preferential.\75\ As for 
those commenters that argue that the Commission should allow existing 
regional transmission planning processes to mature before acting, we 
believe that the discussion above illustrates that the requirements of 
the pro forma OATT are inadequate to ensure the development of more 
efficient or cost-effective solutions to regional needs. As we 
explained in section II above, while transmission planning processes 
have improved since the issuance of Order No. 890, we are concerned 
that the existing Order No. 890 requirements regarding transmission 
planning, as well as cost allocation, are insufficient to ensure that 
the evolution of transmission planning processes will occur in a manner 
that ensures that the rates, terms and conditions of jurisdictional 
services are just and reasonable and not unduly discriminatory or 
preferential. At the same time, in response to North Carolina Agencies, 
we do not intend our reforms to preclude the ability of states to 
actively plan at the local level.
---------------------------------------------------------------------------

    \75\ See discussion supra section II.C.
---------------------------------------------------------------------------

2. Legal Authority for Transmission Planning Reforms \76\
---------------------------------------------------------------------------

    \76\ As noted above, because the legal authority concerns raised 
by commenters with regard to both our regional transmission planning 
reforms and our interregional transmission coordination reforms are 
so closely related, we address these concerns together in this 
section of the Final Rule.
---------------------------------------------------------------------------

a. Commission Proposal
    85. In the Proposed Rule, the Commission explained that the 
proposed reforms in the areas of regional transmission planning and 
interregional transmission coordination are intended to correct 
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 services are provided 
at rates, terms and conditions that are just and reasonable and not 
unduly discriminatory or preferential. The Commission also noted that 
the Proposed Rule builds on Order No. 890, in which the Commission 
required each public utility transmission provider to have a 
coordinated, open, and transparent regional transmission planning 
process, among other things, in order to remedy opportunities for undue 
discrimination in the provision of transmission services.\77\
---------------------------------------------------------------------------

    \77\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 1-2.
---------------------------------------------------------------------------

b. Comments
    86. Several commenters argue that the Commission has adequate 
statutory authority to undertake the planning reforms in the Proposed 
Rule.\78\ Iberdrola Renewables contends that the Commission has a firm 
legal basis to adopt the proposed reforms and has already relied on its 
authority to require regional transmission planning efforts in Order 
No. 890. In response to comments arguing that the Proposed Rule 
oversteps the Commission's authority, Exelon states that the proposed 
coordination reforms are well within the Commission's statutory 
authority to remedy the potential for undue discrimination in 
transmission planning activities, citing FPA sections 205 and 206, as 
well as New York v. FERC.\79\ ITC Companies' reply comments also argue 
that the Commission has the legal authority to implement its proposals, 
citing the Commission's plenary authority over interstate transmission 
under FPA section 201 and noting that courts have broadly defined 
transmission in interstate commerce due to the interconnected nature of 
the transmission grid. Multiparty Commenters agree that the proposed 
reforms are within the Commission's plenary authority, and they believe 
that the Proposed Rule properly identifies deficiencies in transmission 
planning and cost allocation, and that requirements for transmission 
planning and cost allocation are necessary for fully competitive 
wholesale markets and thus fall squarely within the Commission's 
jurisdiction.
---------------------------------------------------------------------------

    \78\ E.g., Iberdrola Renewables; 26 Public Interest 
Organizations; Exelon; ITC Companies; LS Power; and Multiparty 
Commenters.
    \79\ 535 U.S. 1 (2002).
---------------------------------------------------------------------------

    87. In response to those asserting that the Commission cannot 
require interregional agreements to coordinate planning because of 
section 202(a)'s voluntary coordination language, commenters assert 
that such arguments are contrary to precedent affirming Order Nos. 888 
and 2000. Exelon notes that Public Utility District No. 1 of Snohomish 
County v. FERC,\80\ which affirmed Order No. 2000, found that mandatory 
RTO rules did not run afoul of section 202(a). ITC Companies also 
assert that section 202(a) does not prohibit interregional planning 
agreements, contrary to some comments. Multiparty Commenters also argue 
that section 202 does not impose a limitation on the Commission's 
section 206 jurisdiction. In addition, commenters such as ITC Companies 
and Multiparty Commenters argue that the proposals do not preempt state 
jurisdiction over siting decisions. Twenty-six Public Interest 
Organizations argue that the FPA requires the Commission to address 
identified transmission planning deficiencies.
---------------------------------------------------------------------------

    \80\ 272 F.3d 607 (DC Cir. 2001).
---------------------------------------------------------------------------

    88. Some commenters argue that the Commission may consider public 
policy requirements. Exelon disagrees with those asserting that the 
Commission cannot require public utility transmission providers to 
consider the impacts of public policies under federal and state laws 
and regulations, and argues that the Commission is not establishing an 
independent obligation to satisfy such public policy requirements. 
Exelon states that courts have consistently recognized the Commission's 
need to adjust its regulation under the FPA to meet the changing needs 
of the industry.\81\ LS Power explains that the proposal regarding 
public policy requirements is not an effort to pursue those goals but 
rather to ensure that transmission service is offered at just and 
reasonable rates. EarthJustice argues that, contrary to commenters 
challenging the Proposed Rule with respect to the consideration of 
public policy requirements, the Commission did not propose to infringe 
on state jurisdiction. EarthJustice argues that there is substantial 
evidence to support the Commission's conclusions in the Proposed 
Rule.\82\
---------------------------------------------------------------------------

    \81\ Exelon (citing New York v. FERC, 535 U.S. 1 (2002)), 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (DC 
Cir. 2000), and Public Util. Dist. No. 1 of Snohomish Cty v. FERC, 
272 F.3d 607 (DC Cir. 2001).
    \82\ EarthJustice (citing Louisiana Pub. Serv. Comm'n v. FERC, 
551 F.3d 1042, 1045 (DC Cir. 2008)).
---------------------------------------------------------------------------

    89. Some commenters, however, assert that the Commission lacks 
jurisdiction to mandate the transmission planning reforms included in 
the Proposed Rule.\83\ These commenters cite to section 202(a) of the 
FPA, which provides that coordination and interconnection arrangements 
are to be left to the voluntary action of public utilities. California 
ISO points to Central Iowa Power Coop. v. FERC,\84\ which held that, in 
light of the voluntary nature of coordination under FPA section 202(a), 
the Commission's authority under FPA section 206 does not include the 
authority to require modifications to an otherwise just and reasonable 
tariff or jurisdictional agreement simply because the Commission has 
concluded that

[[Page 49859]]

alternative terms and conditions would better promote the 
interconnection and coordination of transmission facilities.
---------------------------------------------------------------------------

    \83\ E.g., Ad Hoc Coalition of Southeastern Utilities; 
California ISO; ColumbiaGrid; Nebraska Public Power District; North 
Carolina Agencies; and Sacramento Municipal Utility District.
    \84\ 606 F.2d 1156 n. 36 (DC Cir. 1979) (Central Iowa).
---------------------------------------------------------------------------

    90. Several commenters state that the Commission's statutory 
authority is limited with respect to transmission siting decisions.\85\ 
North Carolina Agencies assert that, with the exception of the 
Commission's limited backstop authority under FPA section 216, 
transmission planning and expansion fall strictly within the purview of 
state regulatory agencies and the Proposed Rule takes into account 
neither the Commission's lack of authority nor the long-standing 
authority of the states. Some commenters also explain that the states 
have authority with respect to integrated resource planning.\86\
---------------------------------------------------------------------------

    \85\ E.g., North Carolina Agencies; Florida PSC; Illinois 
Commerce Commission; and Nebraska Public Power District.
    \86\ E.g., Alabama PSC; Ad Hoc Coalition of Southeastern 
Utilities; Nebraska Public Power District; Florida PSC; and 
Commissioner Skop.
---------------------------------------------------------------------------

    91. Several others state that the Commission should confirm that 
transmission planning, even with the reforms adopted by this Final 
Rule, continues to be driven by the needs of load-serving entities.\87\ 
Entities such as Ad Hoc Coalition of Southeastern Utilities, APPA, and 
Nebraska Public Power District point to FPA section 217(b)(4) as the 
only provision in the FPA that charges the Commission with transmission 
planning responsibilities, expressing concern that the proposed 
transmission planning reforms might be read to imply a greater focus on 
interests of stakeholders other than load-serving entities. National 
Rural Electric Coops argue that Order No. 890 struck an appropriate 
balance among interests and should be preserved.\88\ APPA argues that 
the failure to address section 217 makes the Proposed Rule legally 
deficient. Additionally, several commenters contend the Commission's 
proposal is inconsistent with section 217, which they state recognizes 
the primacy of a franchised utility's obligation to do what is needed 
to fulfill its obligation to service, including the implementation of 
state-authorized plans for transmission construction.\89\
---------------------------------------------------------------------------

    \87\ E.g., Ad Hoc Coalition of Southeastern Utilities; National 
Rural Electric Coops; Transmission Access Policy Study Group; and 
APPA.
    \88\ Additionally, National Rural Electric Coops request that 
the Commission to confirm that transmission planning, even with any 
reforms the Commission adopts in this rulemaking, will continue to 
be driven in the first instance by the needs of load-serving 
entities. Transmission Access Policy Study Group makes a similar 
request.
    \89\ E.g., Edison Electric Institute; Large Public Power 
Council; Nebraska Public Power; and Xcel.
---------------------------------------------------------------------------

    92. In response, ITC Companies contend that the Proposed Rule is 
compatible with section 217 regarding the needs of load-serving 
entities to fulfill their service obligations. They note that section 
217 does not mandate the planning of transmission in interstate 
commerce based on state integrated resource plans or require that the 
Commission disregard the needs of renewable power producers or other 
generators.
    93. Some commenters argue that the Commission lacks statutory 
authority to consider broad public policies.\90\ Several commenters 
cite to NAACP v. FPC \91\ for the proposition that the primary purpose 
of the Commission's statutory mission is to ensure reliable service at 
just and reasonable rates, and that Congress' direction to the 
Commission to act in furtherance of the public interest was not a broad 
license to promote the general welfare. Nebraska Public Power District 
and Ad Hoc Coalition of Southeastern Utilities add that the Commission 
has recognized this limitation in addressing its responsibility to 
consider environmental policy objectives under the National 
Environmental Policy Act.\92\ PSEG Companies argue that the 
Commission's proposed reforms related to Public Policy Requirements are 
legally flawed. PSEG Companies state that the Commission's section 206 
authority is not unbounded, citing to California Independent System 
Operator Corp. v. FERC,\93\ where the court held that the Commission 
was not empowered to remove members of CAISO's board of directors under 
section 206. Further, PSEG Companies
---------------------------------------------------------------------------

    \90\ E.g., Southern Companies; Ad Hoc Coalition of Southeastern 
Utilities; Nebraska Public Power District; and Large Public Power 
Council.
    \91\ National Ass'n for the Advancement of Colored People v. 
FPC, 425 U.S. 662 (1976).
    \92\ Nebraska Public Power District.
    \93\ 372 F.3d 395 (DC Cir. 2004) (CAISO v. FERC).
---------------------------------------------------------------------------

    argue that there is no evidence to support the Commission's claims 
of undue discrimination under section 206.
    94. Some commenters state that the Commission has not provided 
enough reasoning or adequate detail for the Proposed Rule so that 
parties can comment meaningfully on it, as required by section 553 of 
the Administrative Procedure Act (APA).\94\ The commenters who argue 
this make three basic claims. They maintain that it is unclear from the 
Proposed Rule: (1) Whether the Commission proposes that regional and 
interregional plans will serve as the basis for (a) future orders 
requiring utilities to undertake construction consistent with the plans 
or (b) orders compelling utilities to defer to nonincumbent utilities 
in connection with the construction of transmission facilities needed 
for reliability purposes; (2) what public policies must be incorporated 
in transmission plans, or in what manner such policies should be 
reflected; and (3) what rate mechanism the Commission would employ to 
allocate costs incurred by nonincumbent transmission providers to 
entities with whom they have no service or contractual 
relationship.\95\
---------------------------------------------------------------------------

    \94\ E.g., Nebraska Public Power District Comments (citing 5 
U.S.C. 553, Florida Power & Light Co. v. U.S., 846 F.2d 765, 771 (DC 
Cir. 1988), Connecticut Light and Power Co. v. NRC, 673 F.2d 525, 
530 (DC Cir. 1982)); Large Public Power Council; Salt River Project 
Comments (citing United Mine Workers or America v. MSHA, 407 F.3d 
1250, 1259 (DC Cir. 2005)).
    \95\ E.g., Large Public Power Council and Nebraska Public Power 
District.
---------------------------------------------------------------------------

    95. In addition, Electricity Consumers Resource Council and the 
Associated Industrial Groups argue that the Proposed Rule may represent 
a departure from the Commission's regulations under section 
35.35(i)(ii), which establishes a rebuttable presumption that ``[a] 
project that has received construction approval from an appropriate 
state commission or state siting authority,'' applying the specified 
criteria, qualifies as being prudently incurred.\96\ Southern Companies 
argue that, because the Proposed Rule did not identify what it would 
take to satisfy the public policy requirement, the proposal would 
violate the Due Process Clause's ``fair notice'' requirement.
---------------------------------------------------------------------------

    \96\ 18 CFR 35.35(i)(ii).
---------------------------------------------------------------------------

    96. Indianapolis Power & Light questions whether the Commission has 
satisfied FPA section 206 requirements, arguing that the Commission has 
not yet found that existing transmission planning (and cost allocation) 
provisions are unjust and unreasonable and that it has not ``fixed'' 
the rate or practice that it finds to be unjust and unreasonable.\97\
---------------------------------------------------------------------------

    \97\ Indianapolis Power & Light (citing Electrical Dist. No. 1 
v. FERC, 774 F.2d 490, 492-93 (DC Cir. 1985)).
---------------------------------------------------------------------------

    97. To ensure that any Final Rule will not directly or indirectly 
require a state or municipality to impair or violate private activity 
bond rules under section 141 of the Internal Revenue Code, City of Los 
Angeles Department of Water and Power urges the Commission to include 
in the Final Rule the following statement: ``All regional and 
interregional transmission plans and cost allocation methodologies must 
include a statement that municipal and public power participants are 
not required to take any action that would violate or impair a private 
activity bond rule for purposes of section 141 of the Internal Revenue 
Code of 1986, or any successor statute or regulation.'' Large

[[Page 49860]]

Public Power Council makes a similar comment. In its reply comments, 
APPA states that City of Los Angeles Department of Water and Power 
raises a practical and legal issue regarding the participation of 
public power systems in transmission planning and cost allocation 
activities, and APPA agrees that the statement suggested by City of Los 
Angeles Department of Water and Power would foster public power 
systems' participation in such processes.
    98. Nebraska Public Power District states that as long as it 
participates in regional and interregional transmission planning 
through the SPP, it is able to commit to enter into regional planning 
through the SPP tariff, but cannot make such commitments outside of its 
present RTO membership. Nebraska Public Power District states that it 
is unclear what commitments may be called for in any transmission 
planning agreements, such as whether these agreements: (1) Will carry 
with them specified or unanticipated liability; and/or (2) may include 
an obligation to defer to regional or interregional transmission plans 
that could, in Nebraska Public Power District's judgment, interfere 
with what must be done to remain compliant with state law.
c. Commission Determination
    99. We conclude that we have authority under section 206 of the FPA 
to adopt the reforms on transmission planning in this Final Rule. These 
reforms are intended to correct 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 services are provided at rates, terms and conditions 
that are just and reasonable and not unduly discriminatory or 
preferential. Moreover, these 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, and transparent regional transmission planning 
process. As we explained in Order No. 890, we found that the existing 
pro forma OATT was insufficient to eliminate opportunities for undue 
discrimination, including such opportunities in the context of 
transmission planning.\98\ We conclude that the reforms adopted in this 
Final Rule 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. We note that no party 
sought judicial review of the Commission's authority under Order No. 
890 to adopt those reforms that we seek to enhance and improve upon 
here.
---------------------------------------------------------------------------

    \98\ See, e.g., Order No. 890, FERC Stats. & Regs. ] 31,241 at P 
422.
---------------------------------------------------------------------------

    100. We disagree that section 202(a) of the FPA precludes us from 
adopting the transmission planning reforms contained in this Final 
Rule. 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. * * * \99\
---------------------------------------------------------------------------

    \99\ 16 U.S.C. 824(a).
---------------------------------------------------------------------------

    Section 202(a) requires that the interconnection and coordination, 
i.e., the coordinated operation, of facilities be voluntary. That 
section does not mention planning, and nothing in it can be read as 
impliedly establishing limits on the Commission's jurisdiction with 
respect to transmission planning.
    101. 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, when establishing 
transmission planning process requirements, the Commission is in no way 
mandating or otherwise impinging upon matters that section 202(a) 
leaves to the voluntary action of public utility transmission 
providers. As we discuss herein, section 202(a) refers to the 
coordinated operation of facilities.
    102. Several commenters who argue that section 202(a) prohibits our 
proposal rely primarily on Central Iowa for support.\100\ In Central 
Iowa, a party argued that the Commission should have used its authority 
under section 206 of the FPA to compel greater integration of the 
utilities in the Mid-Continent Area Power Pool (MAPP) than MAPP members 
had proposed. In seeking this goal, the party in question sought to 
have the Commission require MAPP participants ``to construct larger 
generation units and engage in single system planning with central 
dispatch.'' \101\ The court held that given ``the expressly voluntary 
nature of coordination under section 202(a),'' the Commission was not 
authorized to grant that request.\102\
---------------------------------------------------------------------------

    \100\ E.g., ColumbiaGrid; Sacramento Municipal Utility District; 
and California ISO.
    \101\ Central Iowa, 606 F. 2d 1156 at 1166.
    \102\ Id. at 1168.
---------------------------------------------------------------------------

    103. 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. We, on the other hand, are focused in this 
proceeding on the transmission planning process, which is distinct from 
any specific system operations. Nothing in this Final Rule 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. This Final Rule simply requires compliance with certain 
general principles within the 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 irrelevant here.
    104. Commenters point to dicta in Central Iowa based on section 
202(a)'s legislative history that, they state, suggests that Congress 
intended that any coordination by public utilities with respect to 
transmission planning be voluntary. Central Iowa cites to, but does not 
quote directly, the legislative history to support the conclusion that 
``Congress was convinced that `enlightened self-interest' would lead 
utilities to engage voluntarily in power planning arrangements, and it 
was not willing to mandate that they do so.'' \103\ The language from 
the legislative history is as follows:
---------------------------------------------------------------------------

    \103\ Id.

    The committee is confident that enlightened self-interest will 
lead the utilities to cooperate with the commission and with each 
other in bringing about the economies which can alone be secured 
through the planned coordination which has long been advocated by 
the most able and progressive thinkers on this subject.\104\
---------------------------------------------------------------------------

    \104\ See Otter Tail Power Co. v. United States, 410 U.S. 366, 
374 (1973) (citing S.Rep. No. 621, 74th Cong., 1st Sess. 49).

    105. In response, we note that section 202(a) does not mention the 
transmission planning process, and nothing in that section causes one 
to conclude that it was intended to address the transmission planning 
process that is the subject of this proceeding. There is thus no basis 
to resort to legislative

[[Page 49861]]

history for further clarification.\105\ Moreover, even if resorting to 
legislative history was appropriate in this context, we note that this 
passage from the legislative history also does not refer to the 
transmission planning process that is the subject of this Final Rule. 
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 facilities, not 
the planning process for the identification of transmission facilities. 
In short, neither Central Iowa nor the legislative history cited in 
that case involves or applies to the planning process for 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, this Final Rule deals with the planning 
process for transmission facilities, a separate and distinct set of 
activities that occur before the operational activities that are the 
underlying focus of section 202(a).
---------------------------------------------------------------------------

    \105\ See, e.g., Connecticut Nat'l Bank v. Germain, 503 U.S. 
249, 253-54 (1992) (``[I]n interpreting a statute a court should 
always turn first to one, cardinal canon before all others. We have 
stated time and again that courts must presume that a legislature 
says in a statute what it means and means in a statute what it says 
there.'' (citations omitted)).
---------------------------------------------------------------------------

    106. Similarly, section 202(a) has no bearing on whether the 
Commission can mandate requirements on regional and interregional cost 
allocation. The cost allocation requirements of this Final Rule do not 
mandate that any entity engage in any interconnection or coordination 
of facilities in contravention of the requirement in section 202(a) 
that these matters be left to the voluntary decisions of the entities 
in question. Section 202(a) does not address matters involved in cost 
allocation.
    107. We acknowledge that there is longstanding state authority over 
certain matters that are relevant to transmission planning and 
expansion, such as matters relevant to siting, permitting, and 
construction. However, 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. In establishing these reforms, the Commission is simply 
requiring that certain processes be instituted. This 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. For this 
reason, we see no reason why this Final Rule should create conflicts 
between state and federal requirements.
    108. We disagree with the commenters who argue that this Final Rule 
is inconsistent with or precluded by, or legally deficient for failing 
to rely on, section 217 of the FPA.\106\ Our approach in this Final 
Rule is to build on the requirements of Order No. 890 of ensuring open 
and transparent transmission planning processes to evaluate proposed 
transmission projects, a goal that does not conflict with FPA section 
217. Indeed, we believe that this Final Rule is consistent with section 
217 because it supports the development of needed transmission 
facilities, which ultimately benefits load-serving entities. The fact 
that this Final Rule serves the interests of other stakeholders as well 
does not place it in conflict with section 217. We thus cannot agree 
with Ad Hoc Coalition of Southeastern Utilities that we should ensure 
that our transmission planning and cost allocation reforms give 
systematic preference to any particular set of interests. Section 217 
does not require this result. It only requires that we use our 
authority in a way that facilitates planning and expansion of 
transmission facilities to meet the reasonable needs of load-serving 
entities. We have indicated that we will follow a flexible approach 
that accommodates the needs and characteristics of particular regions, 
and we are confident that this approach can address the needs of load-
serving entities in the Southeast and elsewhere.
---------------------------------------------------------------------------

    \106\ 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).
---------------------------------------------------------------------------

    109. We also disagree with commenters who argue that we lack 
jurisdiction to require the consideration of transmission needs driven 
by Public Policy Requirements in the transmission planning process. In 
requiring the consideration of transmission needs driven by Public 
Policy Requirements, the Commission is not mandating fulfillment of 
those requirements. Instead, the Commission is acknowledging that the 
requirements in question are facts that may affect the need for 
transmission services and these needs must be considered for that 
reason. Such requirements may modify the need for and configuration of 
prospective transmission facility development and construction. 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.
    110. Our disagreement with commenters on this point can be best 
explained by considering the case that they use to support their 
arguments, NAACP v. FPC. In that case, the Court found that the 
Commission did not have 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.'' \107\ Specifically, the Court 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.\108\ The Commission is doing nothing 
analogous when specifying that transmission needs driven by Public 
Policy Requirements be taken into account in the transmission planning 
process.
---------------------------------------------------------------------------

    \107\ NAACP v. FERC, 425 U.S. 662 at 668.
    \108\ Id. at 670.
---------------------------------------------------------------------------

    111. Requiring the development of a regional transmission plan that 
considers 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. Public Policy 
Requirements can directly affect the need for interstate transmission 
facilities, which are squarely within the Commission's jurisdiction. 
Moreover, we are not specifying the Public Policy Requirements that 
must be considered in individual local and regional transmission 
planning processes.\109\ This further confirms that, in requiring that 
the transmission planning process

[[Page 49862]]

include the evaluation of potential solutions to identified 
transmission needs driven by Public Policy Requirements, the Commission 
is simply requiring the consideration of facts that are relevant to the 
transmission planning process. In doing so, it is neither pursuing nor 
enforcing any specific policy goals.
---------------------------------------------------------------------------

    \109\ See infra section III.A.4.
---------------------------------------------------------------------------

    112. Other commenters cite CAISO v. FERC for the proposition that 
the Proposed Rule extends beyond our authority under the FPA. In that 
case, the court found that the Commission did not have 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.\110\ 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.'' \111\ Unlike the 
corporate governance matters at issue in that proceeding, the 
transmission planning activities that are the subject of this Final 
Rule have a direct and discernable affect on rates. It is through the 
transmission planning process that public utility transmission 
providers determine which transmission facilities will more efficiently 
or cost-effectively meet the needs of the region, the development of 
which directly impacts the rates, terms and conditions of 
jurisdictional service. The rules governing the transmission planning 
process are therefore squarely within our jurisdiction, whether the 
particular transmission facilities in question are planned to meet 
reliability needs, address economic considerations, or meet 
transmission needs driven by a Public Policy Requirement.
---------------------------------------------------------------------------

    \110\ CAISO v. FERC, 372 F.3d 395 at 403.
    \111\ Id.
---------------------------------------------------------------------------

    113. We disagree with the commenters who argue that the Proposed 
Rule does not comply with the APA because the Proposed Rule does not 
provide enough reasoning or adequate detail to permit parties to 
comment meaningfully on it. Section 553(b)(3) of the APA requires that 
a notice of proposed rulemaking contain ``either the terms or substance 
of the proposed rule or a description of the subjects and issues 
involved.'' \112\ The purpose of the requirement is to ensure that 
``persons are `sufficiently alerted to likely alternatives' so that 
they know whether their interests are `at stake.' '' \113\ Courts have 
held in this connection that a ``[n]otice of proposed rulemaking must 
be sufficient to fairly apprise interested parties of the issue 
involved * * *, but it need not specify every precise proposal which 
[the agency] may ultimately adopt as a rule.'' \114\ We disagree with 
commenters arguing that this requires us to identify the issues that 
might be raised in future orders by the Commission should disputes 
arise as to the construction of transmission facilities in the regional 
transmission planning process. This Final Rule is focused on ensuring 
that there is a fair regional transmission planning process, not 
substantive outcomes of that process.
---------------------------------------------------------------------------

    \112\ 5 U.S.C. 553(b)(3).
    \113\ Spartan Radiocasting Co., v. FCC, 619 F.2d 314, 321 (4th 
Cir. 1980) (citing South Terminal Corp. v. EPA, 504 F.2d 646, 659 
(1st Cir. 1974)).
    \114\ Id. 321-22 (citing Consolidation Coal Co. v. Costle, 604 
F.2d 239, 248 (4th Cir. 1979)).
---------------------------------------------------------------------------

    114. We disagree with Southern Companies' argument that the 
Proposed Rule violated the fair notice requirement of the Due Process 
Clause because it did not identify how the Public Policy Requirements 
in the transmission planning process would be satisfied. As explained 
above, fair notice requires that we apprise parties of the issues 
involved. In this respect, all interested parties have had fair notice 
and an opportunity to comment on the Commission's proposed requirement 
regarding the consideration of transmission needs driven by Public 
Policy Requirements in the transmission planning process and to provide 
their perspectives, consistent with the notice and comment requirements 
of the APA. Moreover, the case that Southern Companies cite in support 
of their argument, Trinity Broadcasting of Fla., Inc. v. FCC,\115\ is 
not on point. That case involved a denial by the Federal Communications 
Commission (FCC) of an application to renew a commercial television 
broadcast license that could have been renewed under a statutory 
preference in favor of minority-controlled firms. A majority of the 
applicant's board was made up of members of minority groups, but the 
FCC denied the application because the applicant had not satisfied its 
interpretation of minority control as de facto or ``actual'' control of 
operations. The court found that the agency had not given sufficient 
notice of its interpretation of minority control to justify punishment 
in the form of denial of the application. Nothing analogous is 
occurring here. Trinity Broadcasting did not involve a rulemaking 
proceeding, as is the case here, but rather an adjudication that raised 
the issue of ``[w]hat constitutes sufficiently fair notice of an 
agency's interpretation of a regulation to justify punishing someone 
for violating it?'' \116\ A rulemaking such as the present proceeding 
does not involve the assessment of penalties for failure to comply with 
a particular regulation, and therefore the notice that is required 
before penalties can be assessed has no relevance here.
---------------------------------------------------------------------------

    \115\ 211 F.3d 618, 628 (DC Cir. 2000) (Trinity Broadcasting).
    \116\ Trinity Broadcasting, 211 F.3d 618 at 619.
---------------------------------------------------------------------------

    115. We also disagree that this Final Rule may represent a 
departure from section 35.35(i)(ii) of the Commission's regulations, 
which establishes a rebuttable presumption that a transmission project 
that has received construction approvals from relevant state regulatory 
agencies satisfies Order No. 679's \117\ requirement that the 
transmission project is needed to ensure reliability or reduce the cost 
of delivered power by reducing congestion. The rebuttable presumption 
of prudent investment provided for in section 35.35(i)(ii) applies only 
to Commission determinations with respect to incentive-based rate 
treatments for investment in transmission infrastructure. The Proposed 
Rule does not ``represent a departure'' from this provision because the 
provision deals with matters that are not covered or affected by the 
Proposed Rule. Electricity Consumers Resource Council and Associated 
Industrial Groups therefore have not adequately explained why they 
believe the Proposed Rule represented such a departure.
---------------------------------------------------------------------------

    \117\ Promoting Transmission Investment through Pricing Reform, 
Order No. 679, FERC Stats. & Regs. ] 31,222 (2006), order on reh'g, 
Order No. 679-A, FERC Stats. & Regs. ] 31,236, order on reh'g, 119 
FERC ] 61,062 (2007).
---------------------------------------------------------------------------

    116. With respect to Indianapolis Power & Light's assertion that 
the Commission has failed to satisfy FPA section 206, we conclude that 
we have met section 206's burden. Our review of the record demonstrates 
that existing transmission planning processes are unjust and 
unreasonable or unduly discriminatory or preferential. Specifically, we 
conclude that the record shows that, for the pro forma OATT (and, 
consequently, public utility transmission providers' OATTs) to be just 
and reasonable and not unduly discriminatory or preferential, it must 
be revised in the context of transmission planning to include the 
requirement that regional transmission planning processes result in the 
production of a regional transmission plan using a process that 
satisfies the specified Order No. 890 transmission planning

[[Page 49863]]

principles and that provides an opportunity to consider transmission 
needs driven by Public Policy Requirements. We conclude that these 
reforms satisfy the section 206 standard because they help ensure just 
and reasonable rates and remove those remaining opportunities for undue 
discrimination.
    117. Finally, with respect to the concerns raised by City of Los 
Angeles Department of Water and Power, APPA, Nebraska Public Power 
District, and others regarding the legal issues associated with public 
power participation in the regional transmission planning processes, we 
make the following observations. First, as discussed in the section of 
this Final Rule addressing reciprocity, we reiterate that this Final 
Rule simply applies the reciprocity principles set forth in Order Nos. 
888 and 890 regarding non-public utility transmission provider 
participation in transmission planning processes. Second, non-
jurisdictional entities, unlike public utilities, may choose whether 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.
3. Regional Transmission Planning Principles
a. Commission Proposal
    118. The Proposed Rule would require that each public utility 
transmission provider participate in a regional transmission planning 
process that produces a regional transmission plan and that meets the 
following transmission planning principles: (1) Coordination; (2) 
openness; (3) transparency; (4) information exchange; (5) 
comparability; (6) dispute resolution; and (7) economic planning 
studies. This proposal did not include two of the Order No. 890 
transmission planning principles, namely the cost allocation 
transmission planning principle and the regional participation 
transmission planning principle. More specifically, the Commission 
would require that each regional transmission planning process consider 
and evaluate transmission facilities and other non-transmission 
solutions that may be proposed and develop a regional transmission plan 
that identifies the transmission facilities that more efficiently or 
cost-effectively meet the needs of public utility transmission 
providers, their customers and other stakeholders.\118\
---------------------------------------------------------------------------

    \118\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 51.
---------------------------------------------------------------------------

    119. The Proposed Rule also would provide that a merchant 
transmission developer that does not seek to use the regional cost 
allocation process would not be required to participate in the regional 
transmission planning process, although such a developer would be 
required to comply with all reliability requirements applicable to 
transmission facilities in the transmission planning region in which 
its transmission project would be located.\119\ To reiterate, merchant 
transmission projects are defined as those for which the costs of 
constructing the proposed transmission facilities will be recovered 
through negotiated rates instead of cost-based rates. The Proposed Rule 
states that such a merchant transmission developer would not be 
prohibited from participating--and, indeed, is encouraged to 
participate--in the regional transmission planning process.\120\
---------------------------------------------------------------------------

    \119\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at n.23.
    \120\ Id. P 99.
---------------------------------------------------------------------------

b. Comments
    120. Many commenters agree that the Commission should require 
public utility transmission providers to produce a regional 
transmission plan using a process that complies with the Order No. 890 
transmission planning principles.\121\ NextEra supports the 
Commission's proposal provided that a regional transmission planning 
process produces a regional transmission plan with identified 
transmission facilities to be built in the near-term. Iberdrola 
Renewables contends that the current piecemeal, generation-driven 
approach to transmission development is inefficient and ineffective and 
hinders development of renewable energy resources. Duke states that it 
supports the requirement that a regional transmission plan be produced 
through a regional transmission planning process. Maine PUC believes 
that in New England, the distinction between different types of 
transmission projects (i.e., reliability and market efficiency 
transmission facilities) has impeded the development of transmission 
facilities that would reduce congestion costs and provide greater 
access to low-cost supply, including renewable resources, and suggests 
that the Commission consider eliminating this distinction.
---------------------------------------------------------------------------

    \121\ E.g., Anabaric and PowerBridge; AWEA; City and County of 
San Francisco; DC Energy; Duke; Duquesne Light Company; East Texas 
Cooperatives; Energy Future Coalition Group; LS Power; MISO; 
National Grid; NEPOOL; New England States' Committee on Electricity; 
New England Transmission Owners; NextEra; Northern Tier Transmission 
Group; Ohio Consumers' Counsel and West Virginia Consumer Advocate 
Division; Wilderness Society and Western Resource Advocates; and 
Wisconsin Electric Power Company.
---------------------------------------------------------------------------

    121. Most commenters addressing the proposed transmission planning 
reforms support the Commission's proposal to require public utility 
transmission providers to adopt several of the Order No. 890 
transmission planning principles for the regional transmission planning 
process.\122\ Some commenters ask the Commission to clarify that the 
existing Order No. 890 transmission planning principles would remain 
applicable to regional transmission planning processes.\123\ Some 
commenters also seek clarification that individual transmission owners 
must comply with Order No. 890 transmission planning principles and 
have an OATT Attachment K on file with the Commission.\124\ 
Transmission Dependent Utility Systems state that transmission owners 
must comply with Order No. 890 transmission planning principles even if 
they are planning local transmission projects in an RTO.
---------------------------------------------------------------------------

    \122\ E.g., ISO New England and SPP.
    \123\ E.g., East Texas Cooperatives and Champlain Hudson.
    \124\ E.g., Transmission Dependent Utility Systems and Old 
Dominion.
---------------------------------------------------------------------------

    122. Several supporting the Proposed Rule stress that fair process, 
transparency, and robust stakeholder participation are important 
components of the transmission planning process.\125\ PPL Companies 
state that all interested parties, especially those that may be 
allocated costs for a particular transmission project, should have an 
opportunity to provide meaningful input into the regional transmission 
planning process, and urge the Commission to require that historical 
and real-time data be made available to interested stakeholders. 
Transmission Dependent Utility Systems contend that transmission 
customers need to play an integral role in the regional transmission 
planning process. 26 Public Interest Organizations, Green Energy and 
21st Century, and Western Independent Transmission Group state that 
transparency in transmission planning and access to models and data are 
critical to nonincumbent resources and grid infrastructure providers if 
these entities are to be effective participants in regional 
transmission plan development. Independent Energy Producers Association 
urges the Commission to emphasize that the

[[Page 49864]]

openness, transparency, and inclusiveness criteria of Order No. 890 
should apply to all phases of the transmission planning process. New 
Jersey Board suggests that transmission providers be required to state 
the baseline methodology on which load forecasts are based. However, 
Anbaric and PowerBridge suggest consideration of internal procedures to 
treat transmission project information as confidential, including 
protections to ensure that transmission projects that are not selected 
in the regional transmission plan will remain confidential.
---------------------------------------------------------------------------

    \125\ E.g., PPL Companies; DC Energy; Direct Energy; 26 Public 
Interest Organizations; Green Energy and 21st Century; Western 
Independent Transmission Group; City of Santa Clara; Natural 
Resources Defense Council; New Jersey Division of Rate Counsel; and 
Iberdola Renewables.
---------------------------------------------------------------------------

    123. Some commenters also address dispute resolution issues in the 
regional transmission planning process. City of Santa Clara believes 
that transmission planning processes should include an effective and 
meaningful dispute resolution process, including the ability to request 
Commission resolution of unresolved disputes. Transmission Access 
Policy Study Group argues that guidance from the Commission is needed 
to ensure that the dispute resolution process is useful, suggesting 
that use of reasonable, nondiscriminatory criteria to minimize the 
potential for discriminatory results, particularly with regard to the 
inclusion or exclusion of project proposals in a regional transmission 
plan and the consideration of public policy objectives in the 
transmission planning process. Transmission Access Policy Study Group 
suggests that the Commission establish a backstop dispute resolution or 
expedited complaint process to have a forum for addressing disputes 
regarding transmission projects selected or not selected in regional 
transmission plans.
    124. Some commenters recommend that the Commission continue to 
recognize regional flexibility with respect to transmission planning 
processes.\126\ Kansas City Power & Light and KCP&L Greater Missouri 
supports the Proposed Rule's suggestion that the Commission would defer 
to each region to develop transmission planning processes that address 
regional needs, noting that each region has developed differently and 
that not all regions are at the same level of maturity. Northern Tier 
Transmission Group states that the Commission should provide 
flexibility as to the manner in which regional plans are produced, 
emphasize expected results rather than process, and clarify that the 
region may continue to rely on a ``bottom-up'' process in developing 
the plan. SPP recommends that transmission planning authorities be 
permitted to develop, through their stakeholder processes and in 
consultation with state regulatory commissions, strategies and metrics 
to achieve region-appropriate compliance with the Final Rule.
---------------------------------------------------------------------------

    \126\ E.g., Kansas City Power & Light and KCP&L Greater 
Missouri; Edison Electric Institute; and WIRES.
---------------------------------------------------------------------------

    125. Many entities that support the Proposed Rule believe that the 
regional transmission planning process in which they participate 
already satisfies the proposed requirements.\127\ ISO/RTO Council asks 
that the Final Rule reflect that ISOs and RTOs already satisfy the 
requirements and that no further demonstration or tariff language be 
required in a future compliance filing with the exception of any new or 
altered requirements imposed by the Final Rule. In response, 26 Public 
Interest Organizations agree that the proposed reforms should not 
modify or interfere with progress being made by transmission planners 
with transmission planning processes that comply with or exceed Order 
No. 890 requirements and that only those tariff provisions that are 
affected by the Final Rule need to be filed.
---------------------------------------------------------------------------

    \127\ E.g., Bonneville Power; Duke; Massachusetts Departments; 
California ISO; Sunflower and Mid-Kansas; MISO Transmission Owners; 
California Commissions; MISO; New England States' Committee on 
Electricity; Indianapolis Power & Light; Northeast Utilities; ISO 
New England; New York ISO; Southern Companies; and Long Island Power 
Authority.
---------------------------------------------------------------------------

    126. On the other hand, Iberdrola Renewables states that the 
Commission should make clear that reliance on existing institutions and 
approaches would be adequate only if they can effectively implement the 
Commission's goals of driving needed transmission infrastructure 
investment. To that end, it states that in areas not covered by RTOs or 
ISOs, new regional agreements would be needed to ensure that the 
transmission providers in the region have a governance structure for 
undertaking the regional and interregional transmission planning 
obligations and a workable mechanism for sharing costs consistent with 
the cost allocation guidelines, and clarify the factors it would 
consider in determining whether a particular regional proposal or 
compliance filing has sufficiently broad regional support to merit any 
deference.
    127. Some commenters ask the Commission to clarify the term 
``transmission planning region'' as it relates to the requirements of 
the Proposed Rule.\128\ Indianapolis Power & Light and Powerex ask the 
Commission to define ``region'' in a Final Rule and include a 
definition of transmission planning region in whatever regulations are 
promulgated. California Municipal Utilities state that they believe 
regional consolidation of transmission planning regions should not be 
forced and that more detail is needed from the Commission for its 
members to determine if current transmission planning processes meet 
the requirements of the Proposed Rule. Solar Energy Industries and 
Large-scale Solar contend that the Commission should ensure that, on 
the review of compliance filings, the scope of the self-selected 
planning regions does not create inadvertent planning seams that 
inhibit the development of transmission projects needed to meet public 
policy requirements established by state or federal laws or 
regulations.
---------------------------------------------------------------------------

    \128\ E.g., NextEra; Clean Line; California Municipal Utilities; 
American Transmission; and Arizona Corporation Commission.
---------------------------------------------------------------------------

    128. Several commenters urge the Commission to clarify that 
existing ISOs and RTOs are considered regions for purposes of 
transmission planning.\129\ However, ITC Companies state that RTO 
boundaries are not always the right ones for transmission planning, and 
ITC Companies are concerned that, given the focus of RTOs on developing 
and running energy markets, it might be difficult for RTOs to plan 
transmission from a truly independent perspective. Instead, ITC 
Companies suggest that the planning function be split off from the 
market function so that there is a truly independent planning 
authority. In reply, California ISO argues that ITC Companies' 
recommendation is tantamount to mandating the creation of new entities, 
which it argues the Commission cannot do. AWEA asks the Commission to 
clarify that more than one organized market could form a single region 
for transmission planning and cost allocation purposes.
---------------------------------------------------------------------------

    \129\  E.g., ISO/RTO Council; California ISO; MISO Transmission 
Owners; Indianapolis Power & Light; and NextEra.
---------------------------------------------------------------------------

    129. Commenters express different views on defining transmission 
planning regions outside of the ISO and RTO context. MISO Transmission 
Owners suggest that, where ISOs or RTOs do not exist, the Commission 
should allow each transmission provider to propose its own definition 
of what it considers its transmission planning region. Further, they 
state that the Commission should not define the term ``transmission 
planning region'' to be any larger or broader than an RTO or ISO 
region. MISO states that public utility transmission providers not 
associated with existing RTOs should either be required to form 
transmission regional planning areas with each other

[[Page 49865]]

or participate in regional transmission planning with an adjacent RTO. 
Some commenters ask the Commission to determine that, in non-RTO 
regions, a single transmission provider or utility family cannot serve 
as a transmission planning region.\130\ Transmission Access Policy 
Study Group urges the Commission to specify that transmission planning 
regions in areas outside of RTOs include at least two transmission 
providers and be at least as large as the smaller of a state or one of 
NERC's Regional Entities. NextEra suggests that, in non-RTO areas, 
geographic scope should be determined by factors such as the level of 
interconnections between utilities, power flows, boundaries of existing 
NERC regions, and historical coordination practices.
---------------------------------------------------------------------------

    \130\ E.g., AWEA; Clean Line; G&T Cooperatives; Integrys; and 
NextEra.
---------------------------------------------------------------------------

    130. Ad Hoc Coalition of Southeastern Utilities claim that the 
Proposed Rule makes several incorrect statements concerning what 
constitutes a region for transmission planning purposes in the 
Southeast.\131\ They note that the Proposed Rule references both 
regional and interregional organizations and processes (including NERC 
regional entities) as being regional for purposes of the Proposed Rule 
and assert that a holding that only RTO regions are sufficiently 
encompassing to meet the proposed requirements would be arbitrary and 
capricious. Given that the Commission has previously recognized that 
the South Carolina Regional Transmission Planning (SCRTP) process 
complies with Order No. 890, and as such is a ``regional transmission 
planning process,'' South Carolina Electric & Gas asks the Commission 
to clarify that the SCRTP constitutes a ``regional transmission 
planning process'' as contemplated by the Proposed Rule. Colorado 
Independent Energy Association supports the designation of WestConnect 
as a regional transmission planning organization for the purposes of 
transmission planning and development in Colorado and to make findings 
to that effect in this Final Rule. Florida PSC and Commissioner Skop 
argue that if the Commission adopts a definition of ``region'' that 
does not recognize Florida as a distinct transmission planning region, 
and Florida becomes part of a multistate region, then it is unclear 
what role the Florida PSC would retain, if any, over the transmission 
planning and cost allocation processes in Florida.\132\
---------------------------------------------------------------------------

    \131\ In reply comments, South Carolina Office of Regulatory 
Staff state that it concurs with Ad Hoc Coalition of Southeastern 
Utilities' views regarding the uniqueness of transmission planning 
in the Southeast.
    \132\ Additionally, Florida PSC and Commissioner Skop express 
concern about the lack of Florida-based commenters, noting that 
either Florida utilities joined a broader coalition of commenters 
or, as in the case of NextEra, did not comment from the perspective 
of its Florida-based utility. Florida PSC and Commissioner Skop ask 
the Commission to take the lack of Florida-specific points of view 
into account when it considers its proposals.
---------------------------------------------------------------------------

    131. Many commenters recommend that transmission providers should 
evaluate both transmission and non-transmission solutions during the 
regional transmission planning process.\133\ 26 Public Interest 
Organizations and Dayton Power and Light assert that consideration of 
non-transmission solutions with all other resource options is needed to 
determine the most cost-effective way to meet grid needs. 26 Public 
Interest Organizations ask the Commission to establish minimum 
requirements for: what types of resources should be assessed; how 
assessments should be conducted; and what types of modeling and 
sensitivity analyses are needed to estimate and compare the costs and 
benefits of option, implementation timelines, and relative risks of 
various resource choices. New Jersey Board believes that transmission 
providers should provide peak load reduction data that demonstrate the 
effect of demand response and energy efficiency on baseline forecasts. 
MISO supports the consideration of non-traditional solutions so long as 
this process does not interfere with state authority over integrated 
resource planning. Western Grid Group and Pattern Transmission suggest 
that resource planning and transmission planning should be 
reintegrated.
---------------------------------------------------------------------------

    \133\ E.g., AWEA; California Commissions; Wisconsin Electric; 
Omaha Public Power District; Dayton Power and Light; Eastern 
Environmental Law Center; Environmental NGOs; NRG; Vermont Electric; 
EarthJustice; and SPP.
---------------------------------------------------------------------------

    132. On the other hand, Ad Hoc Coalition of Southeastern Utilities 
states that a requirement for regional transmission planning processes 
to consider both transmission and non-transmission solutions is 
inconsistent with transmission planning procedures in the Southeast. It 
explains that non-transmission solutions are typically considered in 
integrated resource planning and request for proposal processes during 
the current ``bottom-up'' transmission planning process. It states that 
including a generation resource as an alternative during the regional 
transmission planning process would convey a right of generation 
planning to the Commission that would be inconsistent with state law. 
Accordingly, it states that there are no transmission planning gaps in 
the Southeast that the Commission needs to address. In its reply 
comments, Ad Hoc Coalition of Southeastern Utilities argues that such a 
policy would be inappropriate because there would be winners and losers 
in any given state, such a ``top-down'' process would risk losing the 
emphasis on consumers that currently exists in the state-regulated 
processes. Ad Hoc Coalition of Southeastern Utilities, in responding to 
comments by Western Grid Group and Pattern Transmission, argues that 
transmission planning and resource planning in the Southeast have not 
diverged and that further reforms are unnecessary. Southern Companies 
agree.
    133. MISO Transmission Owners ask the Commission to provide 
additional guidance regarding the meaning of ``non-transmission 
solutions'' and which of these solutions transmission providers are 
required to include in their transmission planning processes. MISO 
Transmission Owners state that if non-traditional solutions must be 
considered, then the Commission should clarify that they are required 
to participate in the transmission planning process on a similar basis 
as transmission projects.
    134. Other commenters ask for clarification and guidance from the 
Commission on other transmission planning-related issues associated 
with the Proposed Rule. WIRES believes that the Commission should 
consider additional rules that promote consistent transmission planning 
cycles, stakeholder procedures, action timelines, and criteria for 
evaluating project proposals. Transmission Access Policy Study Group 
also suggests that the Commission require regular updating of regional 
transmission plans, and require jurisdictional transmission providers 
to file, for public comment, a ``planning report card'' identifying the 
projects proposed during the transmission planning process, the 
projects approved and included in the regional transmission plan, and 
the projects that were proposed but excluded from the plan and the 
reasons those proposed projects were rejected. Transmission Access 
Policy Study Group states that the Final Rule should subject decisions 
as to which facilities are included in a regional transmission plan to 
justification and objective evaluation to prevent discrimination and 
unjust and unreasonable rates.
    135. AEP asserts that a significant flaw in typical transmission 
planning processes is the failure to consider benefits beyond the near-
term.

[[Page 49866]]

Therefore, AEP recommends that the Commission direct each transmission 
planning region to develop a long-term plan that utilizes a 20-30 year 
planning horizon in the determination of need analysis (while still 
permitting RTOs to annually evaluate shorter-term projects needed to 
complement the long-term plan). AEP argues that the useful life of any 
transmission facility is likely to exceed 40 years and, consequently, 
the most efficient transmission planning process should cover a minimum 
span of 20 years, and cites to SPP's and California ISO's transmission 
planning processes, which use 20-year planning horizons.
    136. Primary Power supports the concept that every transmission 
provider must participate in a regional transmission planning process 
where specific projects are determined to be in the public convenience 
and necessity, and urges the Commission to devise threshold 
requirements ensuring that transmission planners have a degree of 
independence from market participants that would promote equitable and 
economically supportable results in terms of which transmission 
facilities are built and who ultimately pays for them. Some commenters 
also ask the Commission to clarify that least-cost planning is a driver 
of the transmission planning process. Transmission Dependent Utility 
Systems state that both the regional and interregional transmission 
planning processes adopted by the Final Rule should include 
clarification that coordination of reliability and economic 
transmission planning includes identifying optimal solutions to 
congestion for all transmission customers and load-serving entities 
across the region. Transmission Dependent Utility Systems recommend 
that the Commission clarify this concept in the Final Rule and 
explicitly recognize a joint optimization requirement.
    137. Solar Energy Industries and Large-scale Solar suggest that the 
Commission require holistic long-term planning on a regional basis, in 
which the interaction of proposed projects with other projects across 
the region, as well as the integration of renewable resources, 
distributed generation, and demand response is considered. Transmission 
Agency of Northern California asks the Commission to clarify that a 
regional transmission planning ``process'' need not be narrowly defined 
as participation in a single set of procedures and that the 
transmission planning process need not serve every planning purpose. 
Arizona Corporation Commission seeks clarification on who would 
determine whether a transmission project is a reliability project 
within the context of the regional transmission planning process. 
Arizona Corporation Commission suggests that state-level entities, such 
as state utility commissions, should continue to determine whether a 
transmission project is a reliability project during line siting and/or 
determination of need proceedings. Additionally, it states that all 
proposed transmission projects should be freshly evaluated in each 
transmission planning cycle so that projects are aligned with 
transmission needs at the time and adequately incorporate current 
public policy requirements.
    138. Some commenters seek assurance from the Commission that the 
needs of states and load-serving entities would be considered in the 
regional transmission planning process. NARUC states that the Final 
Rule should identify the states as key players in any transmission 
planning process, pointing to the primary role of states in 
transmission siting. E.ON emphasizes that the Commission should work to 
ensure that the Final Rule's planning requirements not give rise to new 
impediments to a local transmission owning utility's ability to 
efficiently satisfy customer needs under state service obligations. 
E.ON suggests that the Commission incorporate the following 
requirements in its Final Rule: regional and interregional transmission 
planning processes should be sufficiently flexible to accommodate the 
real-time requirements of a transmission owner and operator's native 
load customers; and the transmission planning process should recognize 
that the obligation to serve still exists in a number of jurisdictions 
and that any regional plan or process needs to allow for the fact that 
it is that obligation that drives transmission planning.
    139. Others are concerned about the applicability of the Proposed 
Rule to currently pending transmission projects. Atlantic Wind 
Connection seeks clarification that sponsored projects with a pending 
request for inclusion in a regional transmission plan should be studied 
under the requirements of the Final Rule without undue delay, including 
delays resulting from any proposed procedural requirements. Edison 
Electric Institute argues that the Final Rule should apply to projects 
only on a going-forward basis, and a project identified in an existing 
plan should not be subject to bumping in a revised transmission 
planning process filed in compliance with a Final Rule. Northeast 
Utilities states that the Final Rule should avoid harming projects 
already included in the transmission planning process.
    140. Some commenters ask the Commission to establish a funding 
mechanism to allow interested parties that are not market participants 
to fully participate in the regional transmission planning process. 
twenty-six Public Interest Organizations assert that an essential 
element of robust and broadly supported regional planning is the 
participation of non-market participants and that this requires ongoing 
provider assistance. They state that, because non-market stakeholders 
have neither the financial resources nor staff expertise to participate 
effectively in regional transmission plan development processes without 
special assistance, the Commission should direct transmission providers 
to facilitate participation of these stakeholders through a funding 
mechanism to cover reasonable technical assistance and other 
participation costs. They conclude that these costs can be rolled into 
the rates of the transmission service providers. Western Grid Group 
offers suggestions as to how a funding mechanism could be implemented. 
Additionally, EarthJustice and Environmental Groups urge the Commission 
to encourage meaningful public participation in the regional 
transmission planning process, arguing that non-market participation is 
vital to achieving just, reasonable, and non-discriminatory system 
plans, and explaining that substantial financial assistance is 
necessary to assure such meaningful participation.
    141. Some commenters, such as AWEA and Transmission Access Policy 
Study Group, support a requirement that there be an obligation to 
construct projects identified in regional transmission plans. AWEA 
recognizes that, while regional and interregional cost allocation 
arrangements may alleviate some of the impediments to building 
transmission facilities, an obligation to build projects identified in 
the regional transmission plan in non-RTO regions would help ensure 
that transmission facilities ultimately are constructed. In its reply 
comments, First Wind supports AWEA's comments. Transmission Access 
Policy Study Group suggests that the Commission can stimulate the 
construction of new projects, without expanding transmission providers' 
obligation to build. It suggests requiring development of a process to 
obtain construction commitments, with accountability for those 
commitments. Transmission Access Policy Study Group states that the 
Final Rule should include a timely post-plan process for: (1) securing 
commitments by transmission providers

[[Page 49867]]

(or others) to build the transmission facilities identified in the 
regional plan; and (2) holding transmission providers and others that 
commit to construct transmission facilities included in the regional 
base model accountable for doing so.
    142. On the other hand, Edison Electric Institute argues that the 
identification of transmission facilities in a transmission plan does 
not impose an obligation to build them. In addition, Salt River Project 
asserts that a transmission plan is not a specific blueprint of 
projects that must be built and states that regional planning provides 
the valuable service of comparing and contrasting individual potential 
projects with the decision to build any given project coming after the 
transmission planning process, with only those projects deemed superior 
getting built. Salt River Project states that not all projects 
identified by the plan should be or will be developed. Large Public 
Power Council points to statements in the Proposed Rule providing that 
the Commission's intention is not to require construction, and that 
this decision not to compel construction is grounded in limitations on 
the Commission's statutory authority.
    143. A number of commenters address the issue of whether merchant 
transmission developers, i.e., those transmission developers that are 
not seeking regional cost recovery for proposed transmission projects, 
should be required to participate in the regional transmission planning 
process. Some commenters state that the Commission should clarify in 
the Final Rule that merchant transmission developers should not be 
required to participate in the regional transmission planning 
process.\134\ Clean Line states that, if ratepayers are not bearing 
development risk and the developer is not seeking regional cost 
allocation for its project, then it should not be required to 
participate in the regional transmission planning process. Allegheny 
Energy Companies note that, in PJM's regional transmission planning 
process, such merchant transmission developers are not required to 
participate if they do not wish to do so. New York ISO states that it 
supports the proposal to not require transmission developers that do 
not seek to take advantage of a regional transmission cost allocation 
mechanism to participate in the regional transmission planning process. 
LS Power states that it understands that merchant transmission 
developers that did not participate in the regional transmission 
planning process would still be required to provide to public utility 
transmission providers the information that is needed, for example, for 
the reliable operation of the transmission grid.
---------------------------------------------------------------------------

    \134\ E.g., Allegheny Energy Companies; Champlain Hudson; Clean 
Line; H-P Energy Resources; LS Power; and New York ISO.
---------------------------------------------------------------------------

    144. However, others support requiring merchant transmission 
developers to participate in the regional transmission planning 
process.\135\ APPA states that the reasons for engaging in coordinated 
planning extend well beyond eligibility for inclusion in the regional 
transmission cost allocation mechanisms, noting that the development of 
transmission projects is a time-consuming and expensive endeavor. APPA 
argues that it is important for transmission planners to know about and 
fully analyze all of the various transmission alternatives to ascertain 
the impact of existing and proposed projects on other regional 
transmission facilities. Transmission Access Policy Study Group is 
concerned that exempting merchant transmission developers from the 
regional transmission planning process could cause the mandatory 
process to plan around ad hoc merchant transmission projects and would 
undermine the benefits of regional transmission planning, such as the 
development of a right-sized grid, and creates the potential for free 
ridership. In reply to Clean Line, Edison Electric Institute states 
that viable merchant transmission projects must be included in the 
regional transmission planning process, because such projects may have 
significant reliability, operational, and economic impacts on the 
transmission system.
---------------------------------------------------------------------------

    \135\ E.g., APPA; Large Public Power Council; Massachusetts 
Municipal and New Hampshire Electric; MISO Transmission Owners; 
National Rural Electric Coops; Nebraska Public Power District; New 
England States Committee on Electricity; Northern Tier Transmission 
Group; Ohio Consumers Counsel and West Virginia Consumer Advocate 
Division; Old Dominion Electric Cooperative; Six Cities; 
Transmission Agency of Northern California; Transmission Access 
Policy Study Group; and Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    145. Finally, some commenters recommend that the Commission 
strongly encourage nonincumbent participation even in cases where they 
are not seeking regional cost recovery. California Commissions state 
that nonincumbent transmission developers that seek cost recovery via 
rolled-in rates should participate fully in the regional transmission 
planning process but believes that participation by merchant 
transmission developers that do not seek such cost recovery should be 
strongly encouraged to the extent feasible with regard to planning, but 
not to cost recovery. In its reply comments, Powerex notes that many 
commenters were opposed to exempting merchant transmission developers 
and thus recommended that the Commission encourage their participation 
in the regional transmission planning process.
c. Commission Determination
    146. This Final Rule requires that each public utility transmission 
provider participate in a regional transmission planning process that 
produces a regional transmission plan and that complies with the 
transmission planning principles of Order No. 890 identified below. We 
determine that such 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.
    147. Order No. 890 required public utility transmission providers 
to coordinate at the regional level for the purpose of sharing system 
plans and identifying system enhancements that could relieve congestion 
or integrate new resources.\136\ The Commission did not specify, 
however, whether such coordination with regard to identifying system 
enhancements included an obligation for public utility transmission 
providers to take affirmative steps to identify potential solutions at 
the regional level that could better meet the needs of the region. As a 
result, the existing requirements of Order No. 890 permit regional 
transmission planning processes to be used as a forum merely to confirm 
the simultaneous feasibility of transmission facilities contained in 
their local transmission plans. Consistent with the economic planning 
requirements of Order No. 890, regional transmission planning processes 
also must respond to requests by stakeholders to perform studies that 
evaluate potential upgrades or other investments that could reduce 
congestion or integrate new resources or loads on an aggregated or 
regional basis.\137\ Again, no affirmative obligation was placed on 
public utility transmission providers within a region to undertake such 
analyses in the absence of requests by stakeholders. There is also no 
obligation for public utility transmission providers within

[[Page 49868]]

the region to develop a single transmission plan for the region that 
reflects their determination of the set of transmission facilities that 
more efficiently or cost-effectively meet the region's needs.
---------------------------------------------------------------------------

    \136\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 523.
    \137\ Id.
---------------------------------------------------------------------------

    148. We address these deficiencies in the requirements of Order No. 
890 through this Final Rule, beginning with the requirement that public 
utility transmission providers participate in a regional transmission 
planning process that produces a regional transmission plan. Through 
the regional transmission planning process, public utility transmission 
providers will be required to evaluate, 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, and/or meet transmission 
needs driven by Public Policy Requirements, as discussed further below. 
When evaluating the merits of such alternative transmission solutions, 
public utility transmission providers in the transmission planning 
region also must consider proposed non-transmission alternatives on a 
comparable basis. If the public utility transmission providers in the 
transmission planning region, in consultation with stakeholders, 
determine that an alternative transmission solution is more efficient 
or cost-effective than transmission facilities in one or more local 
transmission plans, then the transmission facilities associated with 
that more efficient or cost-effective transmission solution can be 
selected in the regional transmission plan for purposes of cost 
allocation.\138\
---------------------------------------------------------------------------

    \138\ As discussed in section IV.F.6, below, we conclude that 
the issue of cost recovery associated with non-transmission 
alternatives is beyond the scope of this Final Rule, which addresses 
the allocation of the costs of transmission facilities.
---------------------------------------------------------------------------

    149. We acknowledge that public utility transmission providers in 
some regions already meet or exceed this requirement.\139\ As with 
other requirements in this Final Rule, our intent here is to establish 
a minimum set of obligations for public utility transmission providers 
that, as some commenters note, are not currently undertaking sufficient 
transmission planning activities at the regional level. We decline, 
however, to specify in this Final Rule a particular set of analyses 
that must be performed by public utility transmission providers within 
the regional transmission planning process. There are many ways 
potential upgrades to the transmission system can be studied in a 
regional transmission planning process, ranging from the use of 
scenario analyses to production cost or power flow simulations. We 
provide 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. We will review such mechanisms on compliance, using as our 
yardstick the statutory requirements of the FPA, Order No. 890 
transmission planning principles, and our precedent regarding 
compliance with the Order No. 890 transmission planning principles, and 
issue further guidance as necessary.\140\
---------------------------------------------------------------------------

    \139\ As noted above, to the extent existing transmission 
planning processes satisfy the requirements of this Final Rule, 
public utility transmission providers need not revise their OATTs 
and, instead, should describe in their compliance filings how the 
relevant requirements are satisfied by reference to tariff sheets 
already on file with the Commission. Moreover, to the extent 
necessary, we clarify that nothing in this Final Rule is intended to 
modify or abrogate governance procedures of RTOs and ISOs.
    \140\ In developing their compliance filings, public utility 
transmission providers and interested parties should review the 
requirements as set forth in Order No. 890, Order No. 890-A, and our 
orders on compliance filings submitted by public utility 
transmission providers for guidance on what each of these 
transmission planning principles requires. For example, as a 
starting point, a public utility transmission provider should review 
the orders addressing its own compliance filings and the compliance 
filings for public utility transmission providers in its region. We 
do not address these principles in detail here, except with respect 
to the consideration of non-transmission alternatives in the 
regional transmission planning process and other discrete issues 
raised by commenters.
---------------------------------------------------------------------------

    150. Because of the increased importance of regional transmission 
planning that is designed to produce a regional transmission plan, 
stakeholders must be provided with an opportunity to participate in 
that process in a timely and meaningful manner. Therefore, we apply the 
Order No. 890 transmission planning principles to the regional 
transmission planning process, as reformed by this Final Rule. This 
will ensure that stakeholders have an opportunity to express their 
needs, have access to information and an opportunity to provide 
information, and thus participate in the identification and evaluation 
of regional solutions. Ensuring access to the models and data used in 
the regional transmission planning process will allow stakeholders to 
determine if their needs are being addressed in a more efficient or 
cost-effective manner. Greater access to information and transparency 
also will help stakeholders to recognize and understand the benefits 
that they will receive from a transmission facility in a regional 
transmission plan. This consideration is particularly important in 
light of our reforms that require that each public utility transmission 
provider have a cost allocation method or methods for transmission 
facilities selected in a regional transmission plan that reflects the 
benefits that those transmission facilities provide.
    151. Specifically, the requirements of this Final Rule build on the 
following transmission planning principles that we required in Order 
No. 890: (1) Coordination; (2) openness; (3) transparency; (4) 
information exchange; (5) comparability; (6) dispute resolution; and 
(7) economic planning.\141\ In Order No. 890, we required that each 
public utility transmission provider adopt these transmission planning 
principles as part of its individual transmission planning process. In 
this Final Rule, we expand the Order No. 890 requirements by directing 
public utility transmission providers to adopt these requirements with 
respect to the process used to produce a regional transmission plan. We 
conclude that it is appropriate to do so to ensure that regional 
transmission planning processes are coordinated, open, and 
transparent.\142\ Accordingly, we require public utility transmission 
providers to develop, in consultation with stakeholders,\143\ 
enhancements to their regional transmission planning processes, 
consistent with these transmission planning principles.
---------------------------------------------------------------------------

    \141\ We do not include the regional participation transmission 
planning principle and the cost allocation transmission planning 
principle here because we address interregional transmission 
coordination and cost allocation for transmission facilities 
selected in a regional transmission plan for purposes of cost 
allocation elsewhere in this Final Rule.
    \142\ Although the explicit requirement for a public utility 
transmission provider to participate in a regional transmission 
planning process that complies with the Order No. 890 transmission 
planning principles identified above is new, we note that the 
existing 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.
    \143\ The term ``stakeholder'' is intended to include any party 
interested in the regional transmission planning process. This is 
consistent with the approach taken in Order No. 890. See, e.g., 
Southern Co. Svcs., Inc., 127 FERC ] 61,282, at P 14-16 (2009).
---------------------------------------------------------------------------

    152. We conclude that, without the requirement to meet the Order 
No. 890 transmission planning principles, a regional transmission 
planning process will not have the information needed to

[[Page 49869]]

assess the impact of proposed transmission projects on the regional 
transmission grid. Additionally, absent timely and meaningful 
participation by all stakeholders, the regional transmission planning 
process will not determine which transmission project or group of 
transmission projects could satisfy local and regional needs more 
efficiently or cost-effectively.
    153. A number of commenters specifically address the treatment of 
non-transmission alternatives in the regional transmission planning 
process. Order No. 890's comparability transmission planning principle 
requires that the interests of public utility transmission providers 
and similarly situated customers be treated comparably in regional 
transmission planning.\144\ In response to Order No. 890, public 
utility transmission providers have identified in their transmission 
planning processes where, when, and how transmission and non-
transmission alternatives proposed by interested parties will be 
considered. As noted in Order No. 890, the transmission planning 
requirements adopted here do not address or dictate which transmission 
facilities should be either in the regional transmission plan or 
actually constructed.\145\ As also noted in Order No. 890, the ultimate 
responsibility for transmission planning remains with public utility 
transmission providers. With that said, the Commission intends that the 
regional transmission planning processes provide for the timely and 
meaningful input and participation of stakeholders in the development 
of regional transmission plans.\146\
---------------------------------------------------------------------------

    \144\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 494.
    \145\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 438.
    \146\ Id. P 454.
---------------------------------------------------------------------------

    154. We disagree with those commenters that assert that non-
transmission alternatives only should be considered in the local 
transmission planning process. We recognize that generation, demand 
response, and energy efficiency options often are considered in local 
resource planning and that transmission often is planned as a last 
resort. Therefore, when local transmission plans are brought together 
in a regional transmission planning process to determine if a regional 
solution can better meet the needs of the region than the sum of local 
transmission plans, many opportunities for the use of alternative 
resources will already have been considered. Just as there may be 
opportunities for regional transmission solutions to better meet the 
needs of the region, the same could be true for regional non-
transmission alternatives. However, the regional transmission planning 
process is not the vehicle by which integrated resource planning is 
conducted; that may be a separate obligation imposed on many public 
utility transmission providers and under the purview of the states.
    155. While we require the comparable consideration of transmission 
and non-transmission alternatives in the regional transmission planning 
process, we 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. Those considerations are best managed among the 
stakeholders and the public utility transmission providers 
participating in the regional transmission planning process.\147\ 
However, we note that in Order Nos. 890 and 890-A, as well as in orders 
addressing related compliance filings, we have provided guidance 
regarding the requirements of the Order No. 890 comparability 
transmission planning principle.\148\ Specifically, public utility 
transmission providers are required to identify how they will evaluate 
and select from competing solutions and resources such that all types 
of resources are considered on a comparable basis.\149\
---------------------------------------------------------------------------

    \147\ We also deny, as beyond the scope of this proceeding, 
NRG's requests that we direct PJM to determine why its markets are 
not sending appropriate price signals and that we direct ISOs and 
RTOs to establish a ``feedback loop.''
    \148\ See, e.g., Order No. 890-A, FERC Stats. & Regs. ] 31,261 
at P 216. See also, e.g., California Indep. Sys. Operator Corp., 123 
FERC ] 61,283 (2008); East Kentucky Power Coop., 125 FERC ] 61,077 
(2008).
    \149\ See, e.g., NorthWestern Corp., 128 FERC ] 61,040 at P 38 
(2009) (requiring the transmission provider's OATT to permit 
sponsors of transmission, generation, and demand resources to 
propose alternative solutions to identified needs and identify how 
the transmission provider will evaluate competing solutions when 
determining what facilities will be included in its transmission 
plan); El Paso Elec. Co., 128 FERC ] 61,063 at P 15 (2009) (same); 
New York Indep. Sys. Operator, Inc., 129 FERC ] 61,044, at P 35 
(2009) (same). In each of these cases, the Commission stated that 
tariff language could, for example, state that solutions will be 
evaluated against each other based on a comparison of their relative 
economics and effectiveness of performance. Although the particular 
standard a public utility transmission provider uses to perform this 
evaluation can vary, the Commission explained that it should be 
clear from the tariff language how one type of investment would be 
considered against another and how the public utility transmission 
provider would choose one resource over another or a competing 
proposal. Northwestern Corp., 128 FERC ] 61,040 at P 38, n.31; El 
Paso Elec. Co., 128 FERC ] 61,063 at P 15, n.25; New York Indep. 
Sys. Operator, Inc., 129 FERC ] 61,044 at P 35, n.26.
---------------------------------------------------------------------------

    156. We disagree with concerns raised by certain commenters that 
the Order No. 890 comparability transmission planning principle may 
interfere with integrated resource planning.\150\ As discussed above, 
this Final Rule 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 siting, 
permitting, or construction of transmission solutions.\151\ In 
addition, on compliance with Order No. 890, each public utility 
transmission provider already has put into place regional transmission 
planning processes that provide for the evaluation of proposed 
solutions on a comparable basis.\152\ In this Final Rule, the 
Commission is applying to regional transmission planning the 
comparability transmission planning principle stated in Order Nos. 890 
and 890-A.\153\
---------------------------------------------------------------------------

    \150\ E.g., Ad Hoc Coalition of Southeastern Utilities.
    \151\ See supra section III.A.2.
    \152\ See, e.g., Entergy OATT, Attachment K at Sec.  3.12; 
Florida Power and Light OATT, Appendix 1 to Attachment K, Sec. Sec.  
H and I; ISO New England OATT, Attachment K at Sec.  4.2; Puget 
Sound Energy OATT, Attachment K at Sec.  2; SPP OATT, Attachment O 
at Sec.  III.8.
    \153\ See, e.g., supra notes 148-49.
---------------------------------------------------------------------------

    157. We agree with commenters that public utility transmission 
providers should have flexibility in determining the most appropriate 
manner to enhance existing regional transmission planning processes to 
comply with this Final Rule. As a result, and consistent with our 
approach in Order No. 890, we will not prescribe the exact manner in 
which public utility transmission providers must fulfill the 
requirements of complying with the regional transmission planning 
principles. We allow public utility transmission providers developing 
the regional transmission planning processes to craft, in consultation 
with stakeholders, requirements that work for their transmission 
planning region. Consistent with this approach, we will not impose 
additional rules that would detail consistent planning cycles, impose 
stakeholder procedures, establish timelines for evaluating regional 
transmission projects in the regional transmission planning process 
(including establishing a minimum long-term planning horizons), add any 
additional requirements to the Order No. 890 dispute resolution 
transmission planning principle, or establish other planning criteria 
beyond those in this Final Rule, as requested by some commenters. These 
are matters best suited to resolution by the public utility 
transmission providers and stakeholders in the transmission planning 
region. We also reject Anbaric and PowerBridge's

[[Page 49870]]

suggestion that procedures be developed to treat transmission project 
information as confidential, outside of the Commission's Critical 
Energy Infrastructure Information (CEII) requirements and regulations, 
as this runs counter to the requirement that regional transmission 
planning processes be open and transparent.
    158. Additionally, we note that a public utility transmission 
provider's regional transmission planning process may utilize a ``top 
down'' approach, a ``bottom up'' approach, or some other approach so 
long as the public utility transmission provider complies with the 
requirements of this Final Rule. Public utility transmission providers 
have flexibility in developing the necessary enhancements to existing 
regional transmission planning processes to comply with this Final 
Rule, based upon the needs and characteristics of their transmission 
planning region.
    159. We also decline to impose obligations to build or mandatory 
processes to obtain commitments to construct transmission facilities in 
the regional transmission plan, as requested by some commenters. The 
package of transmission planning and cost allocation reforms adopted in 
this Final Rule is designed to increase the likelihood that 
transmission facilities in regional transmission plans will move from 
the planning stage to construction. In addition, public utility 
transmission providers already are required to make available 
information regarding the status of transmission upgrades identified in 
transmission plans, including posting appropriate status information on 
its Web site, consistent with the Commission's CEII requirements and 
regulations.\154\ To the extent an entity has undertaken a commitment 
to build a transmission facility in a regional transmission plan, that 
information should be included in such postings.\155\ We determine that 
this obligation, together with the reforms we adopt in this Final Rule, 
are adequate without placing further obligations on public utility 
transmission providers.
---------------------------------------------------------------------------

    \154\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 472.
    \155\ Nothing in this Final Rule limits public utility 
transmission providers from developing mechanisms to impose an 
obligation to build transmission facilities in a regional 
transmission plan, consistent with the requirements below regarding 
the treatment of nonincumbent transmission developers. Similarly, 
nothing in this Final Rule preempts or otherwise limits any such 
obligation that may exist under state or local laws or regulations.
---------------------------------------------------------------------------

    160. The Commission also acknowledges the importance of identifying 
the appropriate size and scope of the regions over which regional 
transmission planning will be performed. We clarify that for purposes 
of this Final Rule, 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. As the Commission explained in Order No. 
890, 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.\156\ We 
note that every public utility transmission provider has already 
included itself in a region for purposes of complying with Order No. 
890's regional participation transmission planning principle. We will 
not prescribe in this Final Rule the geographic scope of any 
transmission planning region. We believe that these existing regional 
processes should provide some guidance to public utility transmission 
providers in formulating transmission planning regions for purposes of 
complying with this Final Rule. However, to the extent necessary, we 
clarify that an individual public utility transmission provider cannot, 
by itself, satisfy the regional transmission planning requirements of 
either Order No. 890 or this Final Rule.
---------------------------------------------------------------------------

    \156\ See, e.g., Order No. 890, FERC Stats. & Regs. ] 31,241 at 
P 527.
---------------------------------------------------------------------------

    161. The Commission also clarifies that the obligation to 
participate in a regional transmission planning process that produces a 
regional transmission plan that meets the seven transmission planning 
principles, is not intended to appropriate, supplant, or impede any 
local transmission planning processes that public utility transmission 
providers undertake. The objective of this Final Rule is to amend the 
requirements of Order No. 890 so that regional transmission planning 
processes not only continue to meet the transmission planning 
principles established in Order No. 890 but, additionally, produce a 
regional transmission plan.
    162. With regard to comments that seek clarification as to the 
applicability of the requirements of this Final Rule to transmission 
projects currently being proposed in existing regional transmission 
planning processes, we clarify in section II.D above that the 
requirements of this Final Rule are intended to apply to new 
transmission facilities. Our intent is to enhance transmission planning 
processes prospectively to provide greater openness and transparency in 
the development of regional transmission plans. As also discussed in 
section II.D above, we recognize that this Final Rule may be issued in 
the middle of a transmission planning cycle, and we therefore direct 
public utility transmission providers to explain in their respective 
compliance filings how they intend to implement the requirements of 
this Final Rule. In response to comments requesting that the Commission 
mandate that public utility transmission providers include a funding 
mechanism to facilitate the participation of in the regional 
transmission planning process of interested entities that are not 
market participants, this Final Rule affirms the general approach the 
Commission took in Order No. 890 regarding the recovery of costs 
associated with participation in the transmission planning process. 
There, the Commission acknowledged concerns regarding ``how state 
regulators and other agencies will recover the costs associated with 
their participation in the planning process.'' \157\ The Commission 
therefore directed public utility transmission providers to ``propose a 
mechanism for cost recovery in their planning compliance filings'' and 
stated that those proposals ``should include relevant cost recovery for 
state regulators, to the extent requested.'' \158\ We decline to expand 
that directive here to include funding for other stakeholder interests, 
as requested by certain commenters. However, we also note that, to the 
extent that public utility transmission providers choose to include a 
funding mechanism to facilitate the participation of state consumer 
advocates or other stakeholders in the regional transmission planning 
process, nothing in this Final Rule precludes them from doing so.
---------------------------------------------------------------------------

    \157\ Order No. 890, FERC Stats. & Regs. ] 31,241 at n.339 and P 
586.
    \158\ Id. n.339.
---------------------------------------------------------------------------

    163. With regard to the participation of merchant transmission 
developers in the regional transmission planning process, we conclude 
that, because a merchant transmission developer assumes all financial 
risk for developing its transmission project and constructing the 
proposed transmission facilities, 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 
project that would otherwise be the basis for securing eligibility to 
use a regional cost

[[Page 49871]]

allocation method or methods.\159\ However, we acknowledge the concern 
of some commenters that a transmission project proposed or developed by 
a merchant transmission developer has broader impacts than simply cost 
recovery. Because all electric systems within an integrated network are 
electrically connected, the addition or cancellation of a transmission 
project in one system can affect the nature of power flows within one 
system or on other systems.
---------------------------------------------------------------------------

    \159\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 99.
---------------------------------------------------------------------------

    164. We therefore conclude 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. 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 this 
Final Rule.
    165. Although merchant transmission developers must provide 
information in the regional transmission planning process as discussed 
herein, to be clear, we emphasize that the transmission facilities 
proposed by a merchant transmission developer are not subject to the 
evaluation and selection processes that apply to transmission 
facilities for which regional cost allocation is sought, as a merchant 
transmission developer is not seeking to be selected in the regional 
transmission plan for purposes of cost allocation. However, nothing in 
this Final Rule prevents a merchant transmission developer from 
voluntarily participating in the regional transmission planning process 
(beyond providing the information and data required above) even if it 
is not seeking regional cost allocation for its proposed transmission 
project. As we stated in the Proposed Rule, we encourage them to do so. 
In addition, nothing in this Final Rule limits or otherwise affects the 
responsibilities a merchant transmission developer may have to fund 
network upgrades caused by the interconnection of its project with the 
transmission grid.\160\
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    \160\ We note that, to the extent a merchant transmission 
developer becomes subject to the requirements of FPA section 215 and 
the regulations thereunder, it also will be required to comply with 
all applicable obligations, including registration with NERC. Under 
section 215, all users, owners, or operators of the bulk power 
system must register with NERC for performance of applicable 
reliability functions. The registration with NERC will help ensure 
that merchant transmission developers provide all appropriate 
information to be used in transmission system planning and 
assessment studies. See 16 U.S.C. 824o(g) (``Reliability Reports--
The ERO shall conduct periodic assessments of the reliability and 
adequacy of the bulk-power system in North America.''); see also 
Rules Concerning Certification of the Electric Reliability 
Organization; and Procedures for the Establishment, Approval and 
Enforcement of Electric Reliability Standards, Order No. 672, 71 FR 
8662 (Feb. 17, 2006), FERC Stats. & Regs. ] 31,204, at P 803, order 
on reh'g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC Stats. 
& Regs. ] 31,212 (2006). Concerns regarding when NERC registration 
would be triggered should be addressed in a NERC registration 
process.
---------------------------------------------------------------------------

4. Consideration of Transmission Needs Driven by Public Policy 
Requirements \161\
---------------------------------------------------------------------------

    \161\ See supra P 2 (defining Public Policy Requirements).
---------------------------------------------------------------------------

a. Commission Proposal
    166. The Proposed Rule would require that transmission needs driven 
by Public Policy Requirements be taken into account in the local and 
regional transmission planning process to ensure that each public 
utility transmission provider's transmission planning process supports 
rates, terms, and conditions of transmission service in interstate 
commerce that are just and reasonable and not unduly discriminatory or 
preferential. The Proposed Rule would require each public utility 
transmission provider to amend its OATT such that its local and 
regional transmission planning processes explicitly provide for 
consideration of Public Policy Requirements.\162\ The Commission noted 
that this proposed requirement would be a supplement to, and would not 
replace, any existing requirements with respect to consideration of 
reliability needs and application of the Order No. 890 economic 
planning studies transmission planning principle in the transmission 
planning process.\163\ If a public utility transmission provider 
believes that its existing transmission planning processes satisfy 
these requirements, then the Proposed Rule would require that the 
public utility transmission provider must make that demonstration in 
its compliance filing.\164\
---------------------------------------------------------------------------

    \162\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 64.
    \163\ Id.
    \164\ Id. P 66.
---------------------------------------------------------------------------

    167. The Proposed Rule would require each public utility 
transmission provider to coordinate with its stakeholders to identify 
Public Policy Requirements that are appropriate to include in its local 
and regional transmission planning processes.\165\ The Proposed Rule 
stated that, after consulting with stakeholders, a public utility 
transmission provider may include in the transmission planning process 
additional public policy objectives not specifically required by state 
or federal laws or regulations.
---------------------------------------------------------------------------

    \165\ Id. P 65.
---------------------------------------------------------------------------

    168. The Proposed Rule sought comment on how planning criteria 
based on Public Policy Requirements should be formulated, including 
whether it would be more appropriate to use flexible criteria rather 
than ``bright line'' metrics when determining which transmission 
projects are to be included in a regional transmission plan, whether 
the use of flexible criteria would provide undue discretion as to 
whether a transmission project is included in a regional transmission 
plan, and whether the use of ``bright line'' metrics may 
inappropriately result in alternating inclusion and exclusion of a 
single transmission project over successive planning cycles and thus 
create inappropriate disruptions in long-term transmission 
planning.\166\
---------------------------------------------------------------------------

    \166\ Id. P 70.
---------------------------------------------------------------------------

b. Comments
    169. In general, most commenters support the Commission's proposal 
that each public utility transmission provider must amend its OATT such 
that local and regional transmission planning processes explicitly 
provide for the consideration of public policy requirements established 
by state or federal laws or regulations that may drive transmission 
needs.\167\ Support came from all sectors of the industry,

[[Page 49872]]

including public utilities, municipal and cooperative utilities, 
renewable generators, transmission developers, state commissions, and 
consumer and public interest representatives. While most commenters 
support the proposal to include public policy requirements in 
transmission planning processes, a number seek clarification or request 
that the Commission provide additional guidance.
---------------------------------------------------------------------------

    \167\ E.g., Allegheny Energy Companies; American Transmission; 
Anbaric and PowerBridge; Arizona Corporation Commission; Arizona 
Public Service Company; Atlantic Grid; AWEA; California Commissions; 
California ISO; Clean Energy Group; Connecticut & Rhode Island 
Commissions; Consolidated Edison and Orange & Rockland; DC Energy; 
Delaware PSC; Dominion; Duke; Duquesne Light Company; EarthJustice; 
Exelon; First Wind; Iberdrola Renewables; Integrys; ISO New England; 
ISO/RTO Council; Maine PUC; Massachusetts Departments; Massachusetts 
Municipal and New Hampshire Electric; MISO; MISO Transmission 
Owners; National Audubon Society; National Grid; New England States' 
Committee on Electricity; New Jersey Board; New Jersey Division of 
Rate Counsel; New York PSC; NextEra; Northeast Utilities; Northern 
Tier Transmission Group; Ohio Consumers' Counsel and West Virginia 
Consumer Advocate Division; Old Dominion; Pacific Gas & Electric; 
Pattern Transmission; Pennsylvania PUC; PHI Companies; PJM; PUC of 
Nevada; San Diego Gas & Electric; Southern California Edison; 
Sunflower and Mid-Kansas; Transmission Dependent Utility Systems; 
Transmission Access Policy Study Group; Transmission Agency of 
Northern California; Western Grid Group; and Wind Coalition.
---------------------------------------------------------------------------

    170. With regard to what constitutes a public policy requirement, 
some commenters seek to limit the definition to state and federal laws 
and regulations \168\ while others seek a more flexible approach. For 
example, Omaha Public Power District supports the Commission's proposal 
only if such public policy requirements are established by state or 
federal laws or regulations applicable to all entities in the relevant 
planning region. East Texas Cooperatives believes that Omaha Public 
Power District's proposal strikes a reasonable balance. Similarly, 
National Rural Electric Coops state that the Commission should not 
empower stakeholders to use the transmission planning process to impose 
and enforce new resource planning requirements that lack the sanction 
of state or federal law in the planning region. First Energy Service 
Company argues that only enforceable requirements that are embodied in 
state or federal law should be eligible for inclusion in transmission 
planning processes. Duke states that the Final Rule should make 
unambiguous that the public policy aspect of regional and interregional 
planning refers only to those transmission projects driven by the need 
to comply with state and/or federal laws, rules, and/or regulations and 
that it supports limiting the requirement to public policies that drive 
the need for transmission.
---------------------------------------------------------------------------

    \168\ E.g., Omaha Public Power District; Exelon; First Energy 
Services; PJM; New York ISO; and Transmission Agency of Northern 
California.
---------------------------------------------------------------------------

    171. Likewise, PJM states that the Commission should make clear 
that the responsibility of the transmission planner to plan for public 
policy criteria is triggered by the clear and formal identification of 
those public policy criteria identified by Congress or state 
policymakers through publicly issued laws or regulations and recognize 
that the transmission planner would need to refer to the states to 
reconcile conflicting policies that cannot both be reasonably 
accommodated under a cost-effective and efficient regional transmission 
plan. In their reply comments, APPA, PSEG Companies, ISO/RTO Council, 
and Illinois Commerce Commission also caution about transmission 
planners picking and choosing the public policies that would be 
considered in transmission planning processes.
    172. In their reply comments, ISO/RTO Council suggest that the 
Final Rule make clear that public policy objectives are limited to 
those developed by federal or state executive, legislative, and 
regulatory bodies with authority to adopt such objectives, that ISOs 
and RTOs may defer to regional state committees on identifying and 
reconciling individual state public policy goals, that states should 
utilize the authority under section 216(i) of the FPA to enter into 
regional compacts to ensure that recommendations pass constitutional 
muster and otherwise have a suitable legal foundation, and that 
stakeholders should advocate means of implementing state public policy 
mandates to the states rather than to ISOs/RTOs.
    173. Several comments focus on the role of states in the 
identification of public policy requirements and what constitutes such 
a requirement. Many request that the Final Rule expressly acknowledge 
the role of the state regulatory agencies and governors.\169\ For 
example, PUC of Nevada supports the Commission's concept to require 
that public policies be incorporated into transmission planning and 
states that the Final Rule should specify the role state regulatory 
commissions and governors play in ensuring that the transmission plan 
accurately reflects state policies and, where there are inconsistencies 
in the utility's interpretation of the state's public policy versus 
that of the state regulatory commissions and governors, the Commission 
should give deference to the regulatory commissions' and governors' 
interpretation. PUC of Nevada also notes that the Final Rule does not 
include an oversight mechanism.
---------------------------------------------------------------------------

    \169\ E.g., Connecticut & Rhode Island Commissions; 
Massachusetts Departments; PUC of Nevada; and New England States 
Committee on Electricity.
---------------------------------------------------------------------------

    174. New England States Committee on Electricity conditions its 
support for the Commission's proposal on states identifying the 
policies established in law and regulations to be considered in 
transmission analysis. New York PSC comments that the Commission should 
modify the process to allow states to identify which state-level 
policies should be included in the transmission planning process. It 
also asks the Commission to clarify that these policies may include 
public policies derived pursuant to such statutory or regulatory 
authority, such as those created pursuant to regulatory orders or state 
energy plans and to allow states to identify state-level policies for 
inclusion in those plans, not stakeholders. In reply comments, 
California PUC also states that the Commission should not establish 
prescriptive criteria regarding what policy goals are to be included. 
City of Los Angeles Department of Water and Power states that the 
Commission's proposal should be expanded to include local laws and 
regulations, noting that many requirements of entities such as itself 
are grounded in such local mandates.
    175. NARUC notes that states will not turn over their policy 
authority to planning entities for inclusion in a Commission tariff and 
states that, while it is valuable to have transmission planning 
processes incorporate public policy considerations, a Commission tariff 
cannot mandate particular policy approaches. NARUC explains that 
transmission planners should not be required to determine unwritten 
public policy requirements, and that the Final Rule should explicitly 
recognize the governmental role, particularly at the state level, in 
providing policy input into the transmission planning processes, rather 
than directing the planners to consult with all stakeholders. NARUC 
states that the Final Rule should make explicit that any provisions do 
not impede or interfere with state commission authority to accept or 
approve integrated resource plans, make decisions about generation, 
demand-side resources, resource portfolios, or to modify policy based 
on cost thresholds. East Texas Cooperatives, First Wind, and Florida 
PSC express their support for NARUC's position.
    176. Connecticut & Rhode Island Commissions state that the 
Commission should not prescribe any particular public policy 
requirement that must be considered or excluded from the transmission 
planning process. Moreover, they argue that the states, not 
transmission utilities and planners, must retain their jurisdiction as 
the ultimate arbiter on the issue of whether a transmission project is 
the most beneficial, lowest cost, or most prudent decision for 
achieving a state public policy goal. North Carolina Agencies assert 
that the regional transmission planning processes should not decide how 
to meet state and federal policy requirements, and that the FPA gives 
the Commission no authority to determine what resources should be used 
by load-serving entities, regardless of whether or not those resources 
are

[[Page 49873]]

needed to meet public policy requirements.
    177. Others seek more flexibility in defining what constitutes a 
public policy requirement.\170\ For example, Pacific Gas & Electric 
asks that the Final Rule clarify that local and regional transmission 
planning processes for public utility transmission providers consider 
state or federal public policy objectives rather than identifying or 
referring to specific laws and regulations. NextEra seeks clarification 
that any type of legal or regulatory requirements affecting 
transmission development should be included in the transmission 
planning process, noting that the EPA has established a schedule for 
issuing of a host of Clean Air Act rules governing other emissions from 
electric generating units. Iberdrola Renewables states that any state 
and federal renewable portfolio requirements and any state and federal 
greenhouse gas emission reduction or climate change policies, including 
requirements or standards that take effect in future years, should be 
considered in the transmission expansion plan. Atlantic Wind Connection 
states that the Commission should broaden the phrase ``public policy 
requirements'' used in the Proposed Rule to include public policy 
initiatives or something similar to reflect the broad, non-compulsory 
nature of the policy environment.
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    \170\ E.g., New Jersey Division of Rate Counsel and Integrys.
---------------------------------------------------------------------------

    178. Several commenters, including some consumer advocates and 
public interest organizations, recommend that the Commission specify 
the state and federal policy requirements that utilities, must, at a 
minimum, take into account in their transmission planning 
processes.\171\ Some suggest including: (1) Renewable portfolio 
standards; (2) energy efficiency standards and mandates; (3) 
CO2 emissions reduction targets/requirements; (4) NAAQS 
attainment and interstate air pollution reductions; (5) EPA utility 
sector regulations; and (6) federal and state land management, land 
use, wildlife conservation and zoning policies and procedures intended 
to facilitate the siting of renewable energy.\172\ In its reply 
comments, EarthJustice endorses this view. Twenty-six Public Interest 
Organizations state that comparable consideration of all resource 
options available to meet various public policy requirements is 
essential to minimizing utilities' opportunities for undue 
discrimination. Ohio Consumers' Counsel and West Virginia Consumer 
Advocate Division state that transmission providers should be required 
describe the role that each ``public policy'' would play in the 
transmission planning process. Michigan Citizens Against Rate Excess 
state that while both reliability and public policy requirements should 
be considered as part of the same plan, they should be analyzed 
separately and the transmission plan should explain how these projects 
may complement or contradict each other.
---------------------------------------------------------------------------

    \171\ E.g., EarthJustice; 26 Public Interest Organizations; and 
National Audubon Society.
    \172\ E.g., Conservation Law Foundation; Energy Future Coalition 
Group; E.ON Climate & Renewables North America; Environmental 
Defense Fund; Environmental NGOs; Natural Resources Defense Council; 
Sonoran Institute; and Wilderness Society and Western Resource 
Advocates.
---------------------------------------------------------------------------

    179. Commenters that believe that the Commission should take a 
broader view of what public policy requirements are to be considered by 
transmission providers and their stakeholders, argue, for example, that 
the transmission planning process must be sufficiently flexible to 
include reasonably foreseeable public policy objectives not yet 
explicitly required by existing law or regulation and also to consider 
``at risk'' generation.\173\ Atlantic Wind Connection suggests the 
adoption of an unambiguous requirement to plan transmission additions 
needed to accommodate public policy initiatives and suggests that the 
Commission require specific tariff provisions describing how 
transmission facilities that accommodate and facilitate public policy 
initiatives would be planned for and evaluated. AWEA states that the 
Commission should clarify that public policy requirements are not to be 
narrowly construed and that expected future public policy requirements 
as well as existing ones should be considered.
---------------------------------------------------------------------------

    \173\ E.g., Iberdrola Renewables.
---------------------------------------------------------------------------

    180. However, in reply, a number of commenters take exception with 
the suggestion that possible or likely future public policies should be 
considered in the transmission planning process stating, among other 
things, that it could result in constantly moving targets, unfocused 
transmission planning, regulatory uncertainty, and the RTOs or the 
Commission assuming the roles of Congress and the states.\174\ For 
example, Exelon argues that the Final Rule should specify that planning 
for public policy should not include aspirational goals. Likewise, 
Large Public Power Council's reply comments state that transmission 
planners should not be required to take into account anticipated public 
policies. Xcel also believes that the requirement to consider public 
policy directives in developing transmission plans should focus on 
established policies, rather than anticipated or potential future 
obligations.
---------------------------------------------------------------------------

    \174\ E.g., Ad Hoc Coalition of Southeastern Utilities; 
Coalition for Fair Transmission Policy; East Texas Cooperatives; 
Large Public Power Council; National Rural Electric Coops; and New 
England States Committee on Electricity.
---------------------------------------------------------------------------

    181. Among those seeking flexibility and recognition of regional 
differences,\175\ Edison Electric Institute and Northeast Utilities 
state that the Commission should allow flexibility in defining the 
types of public policy requirements; determining implementation 
details, such as the process to identify public policy requirements; 
and how transmission system needs would be selected once an appropriate 
public policy requirement is identified. Northern Tier Transmission 
Group states that to the extent that a transmission provider maintains 
an obligation to serve retail load, its merchant/load-serving function 
will identify and quantify the relevant public policy requirements, 
which will then be accounted for in its local transmission plan. Any 
additional public policy objectives should be at the discretion of 
regional planning groups. Transmission Access Policy Study Group states 
that the Final Rule should clarify the reference to state and federal 
policy requirements, so that it includes state regulatory commission 
orders and regulations and local governmental mandates on load-serving 
entities; and expressly identify FPA section 217(b)(4) as a federal 
public policy requirement that the regional transmission planning 
process must consider.
---------------------------------------------------------------------------

    \175\ E.g., ISO/RTO Council; ISO New England; PJM; New York ISO; 
SPP; MISO; New York Transmission Owners; NEPOOL; and MISO 
Transmission Owners.
---------------------------------------------------------------------------

    182. Other commenters have ideas on or questions about how public 
policy requirements are to be included and implemented. Exelon states 
that the Commission should adopt principles to help head off 
stalemates: (1) Transmission planning must include likely retirements 
of plants subject to environmental regulations; (2) encompass only laws 
actually in effect in determining the impact on generation capacity; 
(3) require transmission planners to take into account all the actual 
terms of state and federal laws and regulations for which transmission 
expansion is planned; (4) require a region to show that its 
stakeholder-endorsed policy would not cause any harm or costs to other 
regions; (5) the full cost of resources must be transparent and 
considered in the transmission planning process, based on

[[Page 49874]]

sound economic principles; and (6) require that planning for renewable 
energy resources be done with the objective of minimizing total costs. 
MISO states that the proposal should be expanded to include a 
requirement to, when prudent, pursue appropriate transmission expansion 
initiatives to facilitate the compliance of public policy requirements 
by entities within the transmission provider's footprint that are 
subject to such requirements.
    183. PJM states that the actual development of transmission to 
address public policy standards requires: (1) Further direction as to 
how such standards should be reflected in implementable planning 
assumptions; and (2) a legally empowered coordination among states with 
shared policy agendas allowing regional projects to be sited and 
permitted because they are ``needed'' to meet the multistate 
collective's shared policy agenda. Old Dominion and Atlantic Wind 
Connection support PJM's suggested holistic approach to transmission 
planning. In response, however, Consolidated Edison and Orange & 
Rockland argue that PJM's comments do not adequately reflect the 
Proposed Rule's objective to respect regional methods and urge the 
Commission to reject PJM's top down approach.
    184. Pattern Transmission states that the Commission should require 
public utility transmission providers to specify when transmission 
upgrade projects are categorized as public policy-driven projects and 
when the transmission facilities are considered solely through the 
generator interconnection process.
    185. Others offer for Commission consideration their desired 
outcomes from including Public Policy Requirements in regional 
transmission planning.\176\ For example, Transmission Agency of 
Northern California seeks confirmation that simply characterizing a 
project's purpose as meeting a public policy requirement should not 
provide that project a presumption of inclusion in the regional 
transmission planning process. Transmission Access Policy Study Group 
states that the Commission should urge transmission providers to adopt 
a ``no regrets'' strategy that focuses on constructing transmission 
facilities needed under multiple potential power supply and public 
policy scenarios, which lead to a ``right-sized'' grid with greater 
flexibility to respond to changing technology, resource options, and 
customer needs. Old Dominion also asks that the Final Rule make clear 
that the directive to plan for public policy laws or regulations is for 
transmission planning only, not for design and construction or to 
improve power supply.
---------------------------------------------------------------------------

    \176\ E.g., Pattern Transmission; Transmission Agency of 
Northern California; and Transmission Access Policy Study Group.
---------------------------------------------------------------------------

    186. Western Grid Group states that, at a minimum, the Commission 
should require regional plans to address a planning horizon of at least 
20 years and to evaluate environmental and economic constraints and 
public interest concerns over that horizon as a basis for the 
development of such plans. Powerex cautions that the consideration of 
public policy factors not result in transmission planning and cost 
allocation processes that elevate the needs of certain customers over 
others in the transmission planning process and should preserve 
competitive wholesale power markets.
    187. Commenters also offer ideas on timing and scope. Some 
commenters argue that only federal and state laws and regulations in 
effect during the transmission planning cycle should be considered as 
public policy requirements in the regional transmission planning 
process.\177\ East Texas Cooperatives, however, believes that a better 
approach is to let participants in the transmission planning process 
advocate for their own needs and interests (which by necessity will 
reflect the need to comply with policies contained in applicable 
federal and state law), and then allow the transmission planning 
process to sort out these interests within the existing Order No. 890 
transmission planning framework. In response to such comments, however, 
AEP contends that planning for only current regulatory requirements is 
too narrow a formulation that would result in underinvestment in 
transmission infrastructure. AEP suggests that the transmission 
planning process consider reasonably foreseeable future regulatory 
requirements given their likely impact on the power system, citing 
NERC's analysis of potential impacts of EPA regulations on generation.
---------------------------------------------------------------------------

    \177\ E.g., National Rural Electric Coops; City of Santa Clara; 
Michigan Citizens Against Rate Excess; Exelon; East Texas 
Cooperatives; and Coalition for Fair Transmission Policy.
---------------------------------------------------------------------------

    188. A number of commenters believe either that existing regional 
transmission planning processes already consider public policy 
requirements and thus OATT revisions may therefore be unnecessary.\178\ 
East Texas Cooperatives state that they agree with the Commission's 
preliminary finding, but disagree as to the need for any revisions to 
the OATT as transmission planning already takes into account public 
policy requirements established by state or federal laws or regulations 
in accordance with Order No. 890's transmission planning requirements, 
as well as with Commission policy that has evolved over the years. Many 
commenters in ISO and RTO regions argue that the transmission planning 
processes administered by those entities already address or largely 
address public policy issues.\179\ For example, New York ISO supports 
the Commission's proposal but states that existing transmission 
planning rules already provide for consideration of public policy 
requirements in many regions. Transmission Dependent Utility Systems 
recommend that the Commission clarify that nothing in the existing pro 
forma OATT prohibits the consideration of public policy requirements in 
the transmission planning processes and, to the extent a transmission 
provider believes its particular OATT does preclude such 
considerations, the Final Rule should direct compliance filings to 
remove the language allegedly prohibiting such consideration.
---------------------------------------------------------------------------

    \178\ E.g., Washington Utilities and Transportation Commission; 
Alliant Energy; Xcel; Bonneville Power; Westar; Sacramento Municipal 
Utility District; National Rural Electric Coops; East Texas 
Cooperatives; WECC; WestConnect; Georgia Transmission Corporation; 
Southern Companies; and Ad Hoc Coalition of Southeastern Utilities.
    \179\ E.g., New England Transmission Owners; Alliant Energy; and 
New York ISO.
---------------------------------------------------------------------------

    189. Some commenters raise additional concerns, including how 
public policy considerations would be incorporated into a transmission 
provider's local and regional transmission planning process including 
whether the proposal is intended to modify or incorporate generator 
interconnection requests into the ``local and regional transmission 
planning process;'' whether a project proposed to satisfy transmission 
needs driven by public policy requirements are to be planned for and 
considered separately from reliability and economic projects; whether 
regional transmission planning organizations are required to create a 
separate category of public policy-driven transmission projects or 
whether they are to be in concert with reliability and economic 
criteria during the transmission planning process.\180\
---------------------------------------------------------------------------

    \180\ E.g., NV Energy; Long Island Power Authority; and 
Bonneville Power.
---------------------------------------------------------------------------

    190. Coalition for Fair Transmission Policy is concerned that the 
Proposed Rule might be interpreted as requiring transmission planning 
processes to make decisions as to how best to meet applicable public 
policy requirements on behalf of those entities on whom the

[[Page 49875]]

requirements are placed. Therefore, it states that decisions on how 
load-serving entities within regions should meet state or federal 
public policy requirements should continue to be made by those with 
responsibilities to meet the requirements, based on federal and state 
law and applicable regulations, and recommends that the Final Rule make 
this clear.
    191. PPL Companies state that basing transmission planning 
decisions on state public policy directives may lead to undue 
discrimination among generators and, thus, run afoul of the FPA 
requirement that all users of the transmission system be treated in a 
non-discriminatory manner. It states that the Commission should direct 
transmission planners to make sure that pre-existing rights are 
preserved and accommodated under the Proposed Rule's transmission 
planning principles, just as the Commission preserved grandfathered 
transmission contracts under Order No. 888 and grandfathered 
interconnection agreements under Order No. 2000.
    192. New Jersey Board believes there needs to be recognition of 
planning for public policy goals in terms of reliability. It asserts 
that focusing solely on public policy goals as the driving force in the 
transmission planning process would raise issues as to which policy 
should receive the greatest emphasis, and would cause conflict in the 
transmission planning process over which goals to incorporate. New 
Jersey Board recommends that transmission plans incorporate public 
policy goals in a fashion that has these projects evaluated similarly 
for reliability and economic purposes.
    193. Some commenters generally oppose the proposal to require 
public policy considerations in transmission planning.\181\ PSEG 
Companies state that the Commission's public policy planning approach 
should not be adopted, arguing that the proposal would result in public 
utility transmission providers establishing an unduly preferential 
practice favoring renewable energy resources over other types of 
resources. Finally, PSEG Companies are concerned that the proposal 
could result in overbuilding or underbuilding the transmission grid. Ad 
Hoc Coalition of Southeastern Utilities asserts that there is no 
dependable means to translate abstract notions of public policy into 
the transmission planning process, except to the extent it has a 
bearing on transmission demand. Energy Consulting Group states that 
interregional planning should not be used as an instrument of public 
policy but should incent development of transmission improvements to 
afford the public access to all types of generation that is economic 
and minimizes its power costs. APPA believes that any transmission 
provider wishing to incorporate specific state policy requirements or 
other objectives into its transmission planning protocols should do so 
through case-by-case tariff filings under FPA section 205.
---------------------------------------------------------------------------

    \181\ E.g., PSEG Companies; First Energy Service Company; Ad Hoc 
Coalition of Southeastern Utilities; National Rural Electric Coops; 
Southern Companies; Large Public Power Council; Nebraska Public 
Power District; and Long Island Power Authority.
---------------------------------------------------------------------------

    194. Electricity Consumers Resource Council and the Associated 
Industrial Groups are concerned with mandatory interjection of state 
public policy considerations into the transmission planning process and 
how, in practice, this is expected to work, given public policy 
differences among states, and they are concerned that the Proposed Rule 
delegates to ISOs and RTOs the authority to impose the public policy 
requirements of one state on another without sufficient democratic or 
procedural checks and balances.
    195. Some commenters agree with the proposal to coordinate 
identification of public policy requirements. These commenters 
generally state that flexibility is needed given the regional variation 
in: public policy objectives; types and location of resources; and 
regional needs, provided that transmission providers seek input from 
state authorities and other stakeholders.\182\ MISO Transmission Owners 
ask that the Commission not mandate what public policy requirements 
must be considered, but should allow individual transmission providers 
to work with stakeholders to identify public policy requirements 
applicable to the state(s) or region in which the transmission provider 
is located; they also state that transmission planning regions should 
not be required to plan for or contribute to the costs of enabling 
compliance with public policy requirements enacted outside of their 
region without the agreement of all regions affected.
---------------------------------------------------------------------------

    \182\ E.g., American Transmission; Atlantic Grid; Consolidated 
Edison and Orange & Rockland; Edison Electric Institute; Energy 
Consulting Group; MISO Transmission Owners; NEPOOL; New England 
Transmission Owners; New York Transmission Owners; and Northeast 
Utilities.
---------------------------------------------------------------------------

    196. Some commenters agree that public utility transmission 
providers should be required to specify the procedures and mechanisms 
for evaluating transmission projects proposed to achieve public policy 
requirements. 26 Public Interest Organizations assert that the 
Commission should require all transmission providers to incorporate 
certain best practices in the OATT to achieve the Commission's goal. 
These include: (1) Minimum coordination agreement requirements for plan 
development; (2) required actions to assure robust participation in 
regional plan development by non-market participant stakeholders; and 
(3) minimum requirements to ensure fair and comparable consideration of 
all options to meet public policy requirements. Clean Energy Group 
states that transmission planners should be required to identify the 
specific public policy goals that would be considered in the planning 
cycle after consultation with stakeholders, including state policy 
makers. Additionally, it states that transmission providers should be 
required to disclose and document how public policy considerations were 
taken into account.
    197. Other commenters would like flexibility in this regard. Edison 
Electric Institute states that the Commission should not require 
transmission providers to identify in their tariff each specific public 
policy requirement that may be taken into consideration but should 
allow flexibility. ISO New England and Kansas City Power & Light and 
KCP&L Greater Missouri similarly argue that the Commission should 
specify that it would not become a requirement within the tariff to 
list each specific public policy requirement. However, in reply, 
Conservation Law Foundation argues that the policies should be 
reflected in the OATT and asks that the Final Rule hold planning 
authorities responsible for applying those policies that are germane to 
a given process or decision. In their reply comments, Maine Parties 
point to MISO tariff provisions that show that ISOs and RTOs can 
develop tariff provisions that include criteria for identifying public 
policy projects, and request that the Commission be explicit about the 
role it expects ISOs and RTOs to play in identifying state and federal 
public policies and in identifying criteria for selecting projects.
    198. In response to the Commission's question regarding the use of 
``bright line'' metrics when evaluating potential transmission 
projects, the majority of commenters that provided input on this issue 
support a flexible approach.\183\

[[Page 49876]]

They generally agree that transmission providers should be provided 
flexibility to take into account the multiple reliability, economic, 
and public policy-based benefits a single project may provide. They 
express concern that projects that address reliability, economic, and 
public policy initiatives may not be pursued because the transmission 
provider may not be allowed to include the project in the regional plan 
because of the technical failure to meet a bright line test. AWEA notes 
that existing transmission planning processes that rely on bright line 
criteria do not accommodate well the integration of renewable resources 
into the grid. NRECA states that bright line metrics are unnecessary 
because load-serving entities' planning requirements implicitly include 
established public policy requirements.
---------------------------------------------------------------------------

    \183\ E.g., Anbaric and PowerBridge; Atlantic Grid; AWEA; First 
Wind; Integrys; National Rural Electric Coops; New Jersey Division 
of Rate Counsel; New York ISO; New York Transmission Owners; 
NextEra; Northeast Utilities; Northern Tier Transmission Group; 
Organization of MISO States; PJM; SPP; WECC; and Westar.
---------------------------------------------------------------------------

    199. While expressing the need for flexibility, some commenters 
note that the Commission should establish in the Final Rule some level 
of specificity as to how the regional plan should consider projects 
designed to meet public policy requirements. NEPOOL suggests that the 
Commission grant deference to the states in a planning region with 
regard to how they would want public policy requirements to be 
considered in the context of regional planning. SPP echoes this, 
stating that the Commission should afford transmission providers, state 
regulatory commissions, and stakeholders flexibility to develop 
strategies and metrics that appropriately consider the needs and 
reflect the existing structure of the transmission system in the 
region. First Wind recognizes that certain public policy considerations 
could require a bright line metric to ensure they be included in a 
regional plan, while others could be more general and flexible.
    200. Others, however, argue that bright line metrics are necessary 
to avoid discrimination in the transmission planning process.\184\ City 
and County of San Francisco and LS Power both assert that removing 
bright line criteria would lead to unfair results. City and County of 
San Francisco assert that without bright line criteria, end-users could 
be penalized because of different cost allocation methods associated 
with each distinct criterion.
---------------------------------------------------------------------------

    \184\ E.g., City and County of San Francisco; LS Power; New 
Jersey Division of Rate Counsel; and Western Independent 
Transmission Group.
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    201. Some commenters support a balanced approach of using both 
bright line and flexible metrics. While Organization of MISO States 
cautions against the establishment of rigid bright line metrics, it 
notes that an overly flexible approach could allow for higher cost 
projects than are actually needed. It states that the Commission should 
seek a reasonable balance by ordering transmission planners to start 
with defined criteria and then look further into more flexible options 
that could provide an optimal solution to a number of perceived needs. 
Dominion states that both flexible and bright line criteria may be 
needed for some multi-purpose projects. Dominion explains that the 
benefit of reliability projects must be assessed against bright line 
criteria. However, when considering other benefits, Dominion states 
that more flexibility is needed. Minnesota PUC and Minnesota Office of 
Energy Security recommend that bright line metrics be used as a first 
pass in the transmission planning process, but more flexible criteria 
could be used to assess each project further.
    202. Finally, there are some commenters that argue that the 
Commission's proposal may lead to undesirable outcomes. Large Public 
Power Council states that requiring each public utility transmission 
provider to coordinate with customers and other stakeholders to 
identify relevant state and federal laws and regulations would be 
unnecessary, potentially confusing, and ultimately counterproductive. 
Long Island Power Authority states that the Proposed Rule did not 
identify how a regional transmission planning group encompassing 
multiple states is to decide which state's ``public policy 
requirements'' must be satisfied through the transmission planning 
process. It expresses concern that the apparent default solution of 
incorporating every state's public policy requirements into the 
transmission planning process to the extent feasible, may distort the 
transmission planning process, lead to over-construction of 
transmission facilities and consequently increase the costs to be 
allocated. Nebraska Public Power District states that the discretion 
that this approach would interject into the transmission planning 
process would seem to be an open door to potential discrimination, and 
a nightmare to enforce, as parties debate whether planning adequately 
responds to a variety of potentially competing policies.
c. Commission Determination
    203. The Commission requires public utility transmission providers 
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.\185\ As discussed in section II above, the reforms adopted 
below are intended to ensure that the local and regional transmission 
planning processes support the development of more efficient or cost-
effective transmission facilities to meet the transmission needs driven 
by Public Policy Requirements, which will help ensure that the rates, 
terms and conditions of jurisdictional service are just and reasonable. 
Moreover, these reforms will remedy opportunities for undue 
discrimination by requiring public utility transmission providers to 
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, rather than the public utility 
transmission provider planning only for its own needs or the needs of 
its native load customers. Our decision here to require transmission 
planning to include the consideration of transmission needs driven by 
Public Policy Requirements is supported by the numerous commenters who 
generally agree with the proposed reforms.\186\
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    \185\ To 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.
    \186\ E.g., Allegheny Energy Companies; American Transmission; 
Anbaric and PowerBridge; Arizona Corporation Commission; Arizona 
Public Service Company; Atlantic Grid; AWEA; California Commissions; 
California ISO; Clean Energy Group; Connecticut & Rhode Island 
Commissions; Consolidated Edison and Orange & Rockland; DC Energy; 
Delaware PSC; Dominion; Duke; Duquesne Light Company; EarthJustice; 
Exelon; First Wind; Iberdrola Renewables; Integrys; ISO New England; 
ISO/RTO Council; Maine PUC; Massachusetts Departments; Massachusetts 
Municipal and New Hampshire Electric; MISO; MISO Transmission 
Owners; National Audubon Society; National Grid; New England States' 
Committee on Electricity; New Jersey Board; New Jersey Division of 
Rate Counsel; New York PSC; NextEra; Northeast Utilities; Northern 
Tier Transmission Group; Ohio Consumers' Counsel and West Virginia 
Consumer Advocate Division; Old Dominion; Pacific Gas & Electric; 
Pattern Transmission; Pennsylvania PUC; PHI Companies; PJM; PUC of 
Nevada; San Diego Gas & Electric; Southern California Edison; 
Sunflower and Mid-Kansas; Transmission Dependent Utility Systems; 
Transmission Access Policy Study Group; Transmission Agency of 
Northern California; Western Grid Group; and Wind Coalition.
---------------------------------------------------------------------------

    204. Under the existing requirements of Order No. 890, there is no 
affirmative obligation placed on public utility transmission providers 
to consider in the transmission planning process the effect that Public 
Policy Requirements may have on local and regional transmission 
needs.\187\ We agree with

[[Page 49877]]

the concerns of many commenters that, without having in place 
procedures to consider transmission needs driven by Public Policy 
Requirements, the needs of wholesale customers may not be accurately 
identified.\188\ While we understand that some public utility 
transmission providers already do have processes in place to determine 
whether transmission needs reflect Public Policy Requirements, others 
do not. We correct this deficiency through the requirements below, 
which are intended to enhance, rather than replace, existing 
transmission planning obligations under Order No. 890. Moreover, as 
with other reforms adopted in this Final Rule, these requirements are 
intended to be an additional set of minimum obligations for public 
utility transmission providers and are not intended to preclude 
additional transmission planning related activities.
---------------------------------------------------------------------------

    \187\ In response to Transmission Dependent Utility Systems, we 
note that nothing in the existing pro forma OATT affirmatively 
prohibits consideration of the effect of Public Policy Requirements 
on transmission needs.
    \188\ E.g., National Grid; NextEra; AWEA; Atlantic Grid; 
Delaware PSC; Anbaric and PowerBridge; and Conservation Law 
Foundation.
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    205. In response to commenters seeking greater clarity as to how 
transmission needs driven by Public Policy Requirements must be 
considered by public utility transmission providers, we clarify that by 
considering transmission needs driven by Public Policy Requirements, we 
mean: (1) The identification of transmission needs driven by Public 
Policy Requirements; and (2) the evaluation of potential solutions to 
meet those needs. We therefore direct public utility transmission 
providers to amend their OATTs to describe the procedures by which 
transmission needs driven by Public Policy Requirements will be 
identified in the local and regional transmission planning processes 
and how potential solutions to the identified transmission needs will 
be evaluated in the local and regional transmission planning processes. 
We discuss each of these requirements in turn.
    206. First, public utility transmission providers must establish, 
in consultation with stakeholders, procedures under which public 
utility transmission providers and stakeholders will identify those 
transmission needs driven by Public Policy Requirements for which 
potential transmission solutions will be evaluated. Various commenters 
express concern that a public utility transmission provider should not 
have an open-ended obligation to undertake costly and time-consuming 
studies to evaluate the potential impact that every Public Policy 
Requirement might have on transmission development. As noted by 
Connecticut & Rhode Island Commissions, for example, entities subject 
to particular requirements may intend to meet them in ways that do not 
involve the planning of transmission within the local or regional 
transmission planning processes. In other circumstances, there may be 
disagreement among the various entities subject to competing Public 
Policy Requirements as to whether it is appropriate to consider the 
impact of complying with those laws and regulations in the transmission 
planning process.
    207. We do not in this Final Rule require the identification of any 
particular transmission need driven by any particular Public Policy 
Requirements. Instead, we require each public utility transmission 
provider to establish procedures for identifying those transmission 
needs driven by Public Policy Requirements for which potential 
transmission solutions will be evaluated in the local or regional 
transmission planning processes. As part of the process for identifying 
transmission needs driven by Public Policy Requirements, such 
procedures must allow stakeholders an opportunity to provide input, and 
offer proposals regarding the transmission needs they believe are 
driven by Public Policy Requirements. To the extent such procedures 
identify no transmission needs driven by a Public Policy Requirement, 
the relevant public utility transmission providers are under no 
obligation to evaluate potential transmission solutions.
    208. We allow for local and regional flexibility in designing the 
procedures for identifying the transmission needs driven by Public 
Policy Requirements for which potential solutions will be evaluated in 
the local or regional transmission planning processes. The effects of 
Public Policy Requirements on transmission needs are highly variable 
based on geography, existing resources, and transmission constraints. 
We therefore conclude that it is appropriate to require public utility 
transmission providers, in consultation with their 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 our review on compliance. At a minimum, however, 
we require that all such procedures allow for input from stakeholders, 
including but not limited to those responsible for complying with the 
Public Policy Requirement(s) at issue and developers of potential 
transmission facilities that are needed to comply with one or more 
Public Policy Requirements.
    209. We decline to require that transmission needs driven by Public 
Policy Requirements be identified by a particular entity or subset of 
stakeholders. However, all stakeholders must have an opportunity to 
provide input and offer proposals regarding the transmission needs they 
believe should be so identified, as discussed above. In other words, 
while the procedures adopted by public utility transmission providers 
in response to this Final Rule must allow all stakeholders to bring 
forth any transmission needs they believe are driven by Public Policy 
Requirements, those procedures must also establish a just and 
reasonable and not unduly discriminatory process through which public 
utility transmission providers will identify, out of this larger set of 
needs, those needs for which transmission solutions will be evaluated. 
Some public utility transmission providers might conclude, in 
consultation with stakeholders, to develop procedures that rely on a 
committee of load-serving entities, a committee of state regulators, or 
a stakeholder group to identify those transmission needs for which 
potential solutions will be evaluated in the transmission planning 
processes.\189\ Another example would be the case where a public 
utility transmission provider identifies such transmission needs itself 
on behalf of its customers, following consultation with stakeholders, 
including participating state regulators. However, to ensure that 
requests to include transmission needs are reviewed in a fair and non-
discriminatory manner, we require 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 be evaluated. We conclude that this posting requirement is 
necessary to provide the Commission and interested parties with 
information as to how the identification procedures are

[[Page 49878]]

implemented by public utility transmission providers.
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    \189\ As noted below, we strongly encourage states to 
participate actively in the identification of transmission needs 
driven by Public Policy Requirements. Public utility transmission 
providers, for example, could rely on committees of state regulators 
or, with appropriate approval from Congress, compacts between 
interested states to identify transmission needs driven by Public 
Policy Requirements for the public utility transmission providers to 
evaluate in the transmission planning process.
---------------------------------------------------------------------------

    210. We decline in this Final Rule to require the identification of 
any particular set of transmission needs driven by any particular 
Public Policy Requirements in the local and regional transmission 
planning processes of public utility transmission providers. To the 
extent that implementation of the procedures required here results in a 
suggested transmission need not being evaluated for potential solutions 
in the local or regional transmission planning process, the relevant 
public utility transmission provider(s) are under no obligation under 
this Final Rule to evaluate the potential effect of the associated 
Public Policy Requirement on transmission development. This includes 
proposals to evaluate the need for particular transmission facilities 
proposed by transmission developers to comply with Public Policy 
Requirements. While these entities may continue to offer their proposed 
transmission facilities in the local or regional transmission planning 
process as a potential solution to transmission needs, such proposals 
would not be evaluated in the transmission planning process as driven 
by a Public Policy Requirement.
    211. With regard to the evaluation of potential solutions to the 
identified transmission needs driven by Public Policy Requirements, we 
again leave to public utility transmission providers to determine, in 
consultation with stakeholders, the procedures for how such evaluations 
will be undertaken, subject to the Commission's review on compliance 
and with the objective of meeting the identified transmission needs 
more efficiently and cost-effectively.\190\ As noted in our discussion 
of regional transmission planning in section III.A above, there are 
many ways potential upgrades to the transmission system can be 
evaluated, ranging from the use of scenario analyses to production cost 
or power flow simulations. At a minimum, however, this process must 
include the evaluation of proposals by stakeholders for transmission 
facilities proposed to satisfy an identified transmission need driven 
by Public Policy Requirements.\191\ However, as with any proposed 
solution offered in the local or regional transmission planning 
processes for transmission needs driven by reliability issues or 
economic considerations, there is no assurance that any proposed 
transmission facility will be found to be an efficient or cost-
effective solution to meet local or regional needs.
---------------------------------------------------------------------------

    \190\ To the extent a public utility transmission provider 
determines that existing provisions of its OATT must be amended in 
order to implement its evaluation process, it may include such 
tariff revisions in its compliance filing. For example, evaluation 
of transmission needs driven by a particular Public Policy 
Requirement could require the gathering of additional information 
from interconnected generators regarding retirements or from network 
customers regarding resource preferences.
    \191\ This requirement is consistent with the existing 
requirements of Order Nos. 890 and 890-A which permit sponsors of 
transmission and non-transmission solutions to propose alternatives 
to identified needs. See supra note 149.
---------------------------------------------------------------------------

    212. In response to commenters that urge us to recognize the role 
of the states in transmission planning, especially as it relates to 
compliance with Public Policy Requirements, we clarify that nothing in 
this Final Rule is intended to alter the role of states in that regard. 
Through this Final Rule, we are requiring public utility transmission 
providers to provide an opportunity to all stakeholders, including 
state regulatory authorities, to provide input on those transmission 
needs they believe are driven by Public Policy Requirements, to the 
extent they are not already doing so. We are not dictating any 
substantive result with regard to compliance with Public Policy 
Requirements. In Order No. 890, the Commission stated its expectation 
that ``all transmission providers will respect states' concerns'' when 
engaging in the regional transmission planning process.\192\ This is 
equally true with regard to the consideration of transmission needs 
driven by Public Policy Requirements. We strongly encourage states to 
participate actively in both the identification of transmission needs 
driven by Public Policy Requirements and the evaluation of potential 
solutions to the identified needs.
---------------------------------------------------------------------------

    \192\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 574.
---------------------------------------------------------------------------

    213. We therefore do not believe our reforms are inconsistent with 
state authority with respect to integrated resource planning, as 
suggested by some commenters. Indeed, we believe that the requirements 
imposed herein complement state efforts by helping to ensure that 
potential solutions to identified transmission needs driven by Public 
Policy Requirements of the states can be evaluated in local and 
regional transmission planning processes. To be clear, however, while a 
public utility transmission provider is required under this Final Rule 
to evaluate in its local and regional transmission planning processes 
those identified transmission needs driven by Public Policy 
Requirements, that obligation does not establish an independent 
requirement to satisfy such Public Policy Requirements. In other words, 
the requirements established herein do not convert a failure of a 
public utility transmission provider to comply with a Public Policy 
Requirement established under state law into a violation of its OATT.
    214. We do 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 as some commenters have suggested. Based on 
the record before us, we believe it is sufficient to ensure just and 
reasonable rates and to avoid the potential for undue discrimination to 
restrict the requirement for public policy consideration to state or 
federal laws or regulations that drive transmission needs. Likewise, we 
will not require restrictions on the type or number of Public Policy 
Requirements to be considered as long as any such requirements arise 
from state or federal laws or regulations that drive transmission needs 
and as long as the requirements of the procedures required herein are 
met.
    215. Some commenters request that we specify EPA regulations or FPA 
section 217 as Public Policy Requirements driving potential 
transmission needs relevant for consideration in the transmission 
planning process. While we decline to mandate the consideration of 
transmission needs driven by any particular Public Policy Requirement, 
we intend that the procedures required above be flexible enough to 
allow for stakeholders to suggest consideration of transmissions needs 
driven by any Public Policy Requirement, including potential 
consideration of requirements under EPA regulations, FPA section 217, 
or any other federal or state law or regulation that drive transmission 
needs. Because we are not mandating the consideration of any particular 
transmission need driven by a Public Policy Requirement, we disagree 
with PSEG Companies that we are favoring renewable energy resources 
over other types of resources.
    216. We reiterate here and clarify a statement of the Proposed Rule 
that generated significant comment; that is, this 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

[[Page 49879]]

state or federal laws or regulations.\193\ By providing this 
clarification, we are neither affirmatively granting new rights to nor 
imposing an obligation on a public utility transmission provider. 
Instead, the statement is a recognition that a public utility 
transmission provider has, and has 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. We 
believe that public utility transmission providers, in consultation 
with stakeholders, are in the best position to determine whether to 
consider in a transmission planning process any public policy 
objectives beyond those required by this Final Rule. We reiterate that 
this Final Rule creates no obligation for any public utility 
transmission provider or its transmission planning processes to 
consider transmission needs driven by a public policy objective that is 
not specifically required by state or federal laws or regulations. If 
public utility transmission providers, in consultation with 
stakeholders, do identify public policy objectives not specifically 
required by state or federal laws or regulations, we note that 
transmission facilities designed to meet these objectives may be 
eligible for cost allocation under the transmission planning process.
---------------------------------------------------------------------------

    \193\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 64. For 
example, a public utility transmission provider and its stakeholders 
are not precluded under this Final Rule from choosing to plan for 
state public policy goals that have not yet been codified into state 
law, which they nonetheless consider to be important long-term 
planning considerations.
---------------------------------------------------------------------------

    217. We note that identifying a set of transmission needs and 
projects for inclusion in a transmission planning study does not ensure 
that any particular transmission project will be in the regional 
transmission plan. Alternative solutions to the identified needs may 
prove better from cost, siting, or other perspectives. Similarly, 
elimination of a transmission project or need from the transmission 
planning process would not prevent any planner or developer from 
independently seeking to satisfy the need or develop the transmission 
project, but any resulting transmission facility would not be eligible 
for cost allocation under a regional cost allocation method or methods 
required under this Final Rule.
    218. Some commenters have expressed concerns that the consideration 
of transmission needs driven by Public Policy Requirements in the 
transmission planning process will result in costs being assigned to 
regions that do not benefit from those requirements or to regions that 
did not create the need for new transmission. We understand these 
commenters to be concerned that a requirement to consider transmission 
needs driven by Public Policy Requirements in the local and regional 
transmission planning processes will result in cross-subsidization of 
the costs of meeting Public Policy Requirements.
    219. We clarify that any such consideration of transmission needs 
driven by Public Policy Requirements, to the extent that it results in 
new transmission costs, must follow the cost allocation principles 
discussed separately herein.\194\ Particularly, the costs of new 
transmission facilities allocated within the planning region must be 
allocated within the region in a manner that is at least roughly 
commensurate with estimated benefits.\195\ 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 facilities. That is, a utility or other entity that 
receives 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 facilities.
---------------------------------------------------------------------------

    \194\ See discussion infra section IV.
    \195\ See discussion infra section IV.E.2.
---------------------------------------------------------------------------

    220. Further, we are not requiring that a separate class of 
transmission projects be created in the transmission planning process 
related to compliance with Public Policy Requirements, although nothing 
in this Final Rule prohibits the development of a separate class of 
transmission projects if the public utility transmission provider and 
its stakeholders believe that it is appropriate to do so. Some public 
utility transmission providers might comply with this Final Rule by 
implementing procedures to consider transmission needs driven by Public 
Policy Requirements separately from transmission addressing reliability 
needs or economic considerations. Other public utility transmission 
providers might comply with this Final Rule by identifying and 
evaluating all transmission needs, whether driven by Public Policy 
Requirements, compliance with reliability criteria, or economic 
considerations. While we provide flexibility for public utility 
transmission providers to develop procedures appropriate for their 
local and regional transmission planning processes, we reiterate that 
all stakeholders must be provided an opportunity to provide input 
during the identification of transmission needs driven by Public Policy 
Requirements and the evaluation of potential solutions to the 
identified needs, as discussed above.
    221. In response to Northern Tier Transmission Group, we understand 
that a public utility transmission provider with a native load 
obligation may already have addressed compliance with Public Policy 
Requirements in developing its resource assumptions to be used in the 
transmission planning process. In such circumstances, the procedures 
used to identify transmission needs driven by Public Policy 
Requirements should take that into account. Similarly, the evaluation 
of potential solutions to those transmission needs identified in a 
local or regional transmission planning process should reflect the 
resource decisions of the transmission planning process.
    222. The Proposed Rule stated that, if a public utility 
transmission provider believes that its existing transmission planning 
process already meets the requirements to consider Public Policy 
Requirements, then it may make that demonstration in compliance with 
the Final Rule.\196\ Certain commenters question the need for these 
requirements altogether because they assert they are already obligated 
to follow all state or federal laws or regulations, including laws or 
regulations related to public policy objectives. Other commenters, 
particularly those in ISO and RTO regions, assert that the transmission 
planning processes administered by those entities already address 
public policy issues so their compliance obligation should be minimal. 
In this Final Rule, the Commission is expanding the requirements of the 
pro forma OATT to require that transmission planning processes 
affirmatively consider transmission needs driven by Public Policy 
Requirements. Each public utility transmission provider will have the 
opportunity to demonstrate compliance with these requirements by 
specifying the procedures in its local and regional transmission 
planning processes, whether existing or new, for identifying 
transmission needs driven by Public Policy Requirements and for 
evaluating potential solutions to meet those identified needs. As with 
other requirements of this Final Rule, we

[[Page 49880]]

decline here to prejudge any compliance filings or predetermine whether 
any public utility transmission provider may already be in compliance.
---------------------------------------------------------------------------

    \196\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 66.
---------------------------------------------------------------------------

    223. Finally, we considered the many comments on whether it is more 
appropriate to use flexible criteria in lieu of ``bright line'' metrics 
when determining which transmission projects are in the regional 
transmission plan. While we have in the past required adoption of a 
formulaic approach to applying such metrics,\197\ we sought comment on 
this issue in the Proposed Rule to gain insight as to whether such a 
formulaic approach was appropriate or if providing additional 
flexibility was a more effective approach. Our review of the comments 
suggests that most commenters prefer flexible planning criteria for 
identifying transmission needs not only driven by Public Policy 
Requirements and evaluation of solutions to those identified needs, but 
also for the identification and evaluation of transmission needs 
related to reliability issues and economic considerations as well.\198\ 
These commenters have convinced us that, although there are benefits to 
each kind of planning criteria, there is merit in allowing for flexible 
planning criteria to mitigate the possibility that bright line metrics 
may exclude certain transmission projects from long-term transmission 
planning.
---------------------------------------------------------------------------

    \197\ See, e.g., PJM Interconnection, L.L.C., 119 FERC ] 61,265 
(2007).
    \198\ E.g., AWEA; PJM; New York ISO; SPP; WECC; and Westar.
---------------------------------------------------------------------------

    224. Hence, we will permit public utility transmission providers to 
include within their compliance filings in response to this Final Rule 
any tariff revisions they believe necessary to implement flexible 
transmission planning criteria, including changes to existing bright 
line criteria. This could include procedures to address alternating 
inclusion and exclusion of a single transmission project in a regional 
transmission plan over successive planning cycles. Because such tariff 
revisions will be included as part of the compliance filings in 
response to this Final Rule, they will be submitted pursuant to section 
206 of the FPA rather than under section 205. However, those with 
existing bright line criteria are not required to make this change if 
they do not wish to do so. As we evaluate the compliance filings to 
this Final Rule, we also will evaluate both bright line and flexible 
criteria for whether they permit unjust and unreasonable rates or undue 
discrimination through planning criteria and whether they will ensure 
fair consideration of transmission needs driven by Public Policy 
Requirements as well as by reliability needs and economic 
considerations.

B. Nonincumbent Transmission Developers

    225. This part of the Final Rule addresses the removal from 
Commission-jurisdictional tariffs and agreements of provisions that 
grant a federal right of first refusal to construct transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation. To implement the elimination of such rights, we adopt 
below 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 in the regional 
transmission planning process. We further require that any nonincumbent 
developer of a transmission facility selected in the regional 
transmission plan have an opportunity comparable to that of an 
incumbent transmission developer to allocate the cost of such 
transmission facility through a regional cost allocation method or 
methods. For purposes of this Final Rule, ``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, and as we 
explained in the Proposed Rule, an ``incumbent transmission developer/
provider'' is an entity that develops a transmission project within its 
own retail distribution service territory or footprint.\199\
---------------------------------------------------------------------------

    \199\ See Proposed Rule, FERC Stats. & Regs. ] 32,660 at n.23.
---------------------------------------------------------------------------

    226. We conclude these reforms are necessary in order to eliminate 
practices that have the potential to undermine the identification and 
evaluation of more efficient or cost-effective alternatives to regional 
transmission needs, which in turn can result in rates for Commission-
jurisdictional services that are unjust and unreasonable, or otherwise 
result in undue discrimination by public utility transmission 
providers. As discussed in detail below, our focus here is 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 not on transmission facilities included in local 
transmission plans that are merely ``rolled up'' and listed in a 
regional transmission plan without going through a needs analysis at 
the regional level (and therefore, not eligible for regional cost 
allocation). Similarly, our reforms are not intended to affect the 
right of an incumbent transmission provider to build, own and recover 
costs for upgrades to its own transmission facilities, nor to alter an 
incumbent transmission provider's use and control of an existing right 
of way.
    227. In developing the framework below, we have sought to provide 
flexibility for public utility transmission providers in each region to 
propose, in consultation with stakeholders, how best to address 
participation by nonincumbents as a result of removal of the federal 
right of first refusal from Commission-jurisdictional tariffs and 
agreements. However, we note that nothing in this Final Rule 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. Public utility transmission providers must 
establish this framework in consultation with stakeholders and we 
encourage stakeholders to fully participate.
1. Need for Reform Concerning Nonincumbent Transmission Developers
a. Commission Proposal
    228. As discussed above, Order No. 890 sought to reduce 
opportunities for undue discrimination and preference in the provision 
of transmission service. With regard to the transmission planning 
process, the Commission established nine transmission planning 
principles to prevent undue discrimination. However, Order No. 890 did 
not specifically address the potential for, or effect of, undue 
preference to incumbent utilities over nonincumbent transmission 
developers through practices applied within transmission planning 
processes. The Commission observed in the October 2009 Notice \200\ 
that, as a result of existing practices in some areas, a nonincumbent 
transmission developer may lose the opportunity to construct its 
proposed transmission project to the incumbent transmission owner if 
that owner has a federal right of first refusal to construct any 
transmission facility in

[[Page 49881]]

its service territory. The October 2009 Notice sought comment whether 
such a federal right of first refusal for incumbent transmission owners 
unreasonably impedes the development of merchant and independent 
transmission and, if so, how that impediment could be addressed.
---------------------------------------------------------------------------

    \200\ Federal Energy Regulatory Commission, Notice of Request 
for Comments; Transmission Planning Processes under Order No. 890; 
Docket No. AD09-8-000, October 8, 2009 (October 2009 Notice).
---------------------------------------------------------------------------

    229. Based on the comments received, the Commission determined that 
if a regional transmission planning process does not consider and 
evaluate transmission projects proposed by nonincumbents that regional 
transmission planning process cannot meet the Order No. 890 
transmission planning principle of being ``open.'' Moreover, the 
Commission stated that such regional planning process may not result in 
a cost-effective solution to regional transmission needs, and 
transmission projects in a regional transmission plan therefore may be 
developed at a higher cost than necessary.\201\ As a result, regional 
transmission services may be provided at rates, terms and conditions 
that are not just and reasonable. In addition, the Commission 
determined in the Proposed Rule that there appeared to be opportunities 
for undue discrimination and preferential treatment against 
nonincumbent transmission developers within existing regional 
transmission planning processes. The Commission explained that, where 
an incumbent transmission owner has a federal right of first refusal, a 
nonincumbent transmission developer risks losing its investment to 
develop a transmission project that it proposed in the regional 
transmission planning process, even if the transmission project that 
the nonincumbent transmission developer proposed is in a regional 
transmission plan. The Commission noted that nonincumbent transmission 
developers may be less likely to participate in the regional 
transmission planning process under these circumstances.
---------------------------------------------------------------------------

    \201\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 87-88.
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    230. To address these issues, the Commission proposed to reform 
provisions in public utility transmission providers' OATTs or other 
agreements subject to the Commission's jurisdiction that establish a 
federal right of first refusal for an incumbent transmission provider 
with respect to transmission facilities that are in a regional 
transmission plan.
b. Comments
    231. A number of commenters support the Commission's proposal to 
address federal rights of first refusal in Commission-jurisdictional 
tariffs and agreements.\202\ For example, Federal Trade Commission 
states that the existence of a federal right of first refusal in 
jurisdictional tariffs and agreements reduces capital investment 
opportunities for potential nonincumbent developers by increasing their 
risk, encourages free ridership among incumbent developers, and creates 
a barrier to entry. A number of state utility commissions and consumer 
advocates agree, arguing that such provisions impede transmission 
development and that removing the provisions would provide a level 
playing field for incumbent and nonincumbent transmission 
developers.\203\
---------------------------------------------------------------------------

    \202\ E.g., Federal Trade Commission; American Antitrust 
Institute; Ohio Consumers' Counsel and West Virginia Consumer 
Advocate Division; American Forest & Paper; DC Energy; Elmer John 
Tompkins; EIF Management; 26 Public Interest Organizations; and 
Boundless Energy; Pennsylvania PUC; Connecticut & Rhode Island 
Commissions; Northern California Power Agency; Eastern Massachusetts 
Consumer-Owned System; and Transmission Dependent Utility Systems; 
Arizona Corporation Commission; New Jersey Board; and California 
PUC; NextEra; AWEA; Anbaric and PowerBridge; Clean Line; LS Power; 
Northwest & Intermountain Power Producers Coalition; Pattern 
Transmission; FirstWind; Green Energy and 21st Century; Colorado 
Independent Energy Association; Enbridge; Primary Power; and Western 
Independent Transmission Group.
    \203\ E.g., Arizona Corporation Commission; Connecticut & Rhode 
Island Commissions; New England States Committee on Electricity; New 
Jersey Board; Massachusetts Departments; Ohio Consumer's Counsel; 
Pennsylvania PUC; and West Virginia Consumer Advocate.
---------------------------------------------------------------------------

    232. For example, California Department of Water Resources states 
that competition among transmission providers that promotes 
efficiencies and innovation should be supported in regulatory policy 
and transmission planning. New Jersey Board, Connecticut & Rhode Island 
Commissions and Massachusetts Departments support the proposal to 
remove a federal right of first refusal, also stating that competition 
among project sponsors will result in lower cost approaches to meeting 
system needs. They caution, however, that equal rights must be followed 
by equal responsibilities and obligations at the federal, regional, 
state and local level. New England States Committee on Electricity 
contends that increased competition about which entity will build 
transmission facilities could help improve cost controls over time. 
Pennsylvania PUC supports the proposal to eliminate undue 
discrimination against nonincumbent transmission developers and the 
attempt to eliminate some of the barriers to full participation by 
nonincumbent transmission developers. Pennsylvania PUC cautions the 
Commission, however, to continue to respect Pennsylvania PUC's 
statutory responsibility to review and approve the siting of 
transmission projects located in Pennsylvania. Ohio Commission agrees 
that eliminating rights of first refusal has merit to the extent that 
parameters are established to ensure that ratepayers see cost savings 
and enhanced reliability. Ohio Consumers' Counsel and West Virginia 
Consumer Advocate Counsel state that eliminating barriers to 
participation can encourage additional transmission development that 
could be constructed at lower cost to consumers. Arizona Corporation 
Commission supports the removal of rights of first refusal, but states 
that it does not see this as having an impact on an incumbent utility's 
obligations to serve or affecting the transmission planning process 
currently utilized in Arizona.
    233. Some commenters representing transmission-dependent and 
municipal utilities express support for the Commission's proposal.\204\ 
Transmission Dependent Utility Systems state that a right of first 
refusal can prevent or delay construction of needed transmission 
facilities proposed by nonincumbent transmission developers and also 
can be used to block transmission access for generation resources that 
are not associated with the incumbent transmission provider. Northern 
California Power Agency states that any entity, whether an investor-
owned utility, municipal entity, or independent developer, should have 
the right to propose, construct, and own transmission projects, subject 
to minimum safety and reliability requirements. Eastern Massachusetts 
Consumer-Owned System states that eliminating the right of first 
refusal should help open the door to municipal utility participation in 
transmission ownership on a larger scale.
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    \204\ E.g., Eastern Massachusetts Consumer-Owned System; 
Northern California Power Agency; Transmission Agency of Northern 
California; and Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    234. Others supporting the proposal include entities representing 
independent developers of transmission and generation.\205\ NextEra 
states that allowing the right of first refusal to continue would 
impede development of innovative transmission solutions in that a 
transmission project is unlikely to advance very far if its developer 
cannot

[[Page 49882]]

be confident that it can see the transmission project to its 
completion. Clean Line supports the elimination of the right of first 
refusal and states that encouraging the participation of nonincumbent 
transmission developers in the regional transmission planning process 
would increase competition and expand development, which can ultimately 
lead to lower costs for ratepayers. LS Power states that a right of 
first refusal and all other discriminatory rules should be eliminated 
from transmission planning processes inside and outside of RTOs and 
ISOs.\206\ Pattern Transmission states that rights of first refusal and 
similar preferences favoring incumbent transmission owners do not 
result in transmission rates that are just and reasonable, are 
inherently preferential and unduly discriminatory, and suggests that 
the right of first refusal allows incumbent transmission owners to 
engage in gaming. Primary Power contends that removing a right of first 
refusal from all Commission-jurisdictional tariffs and agreements would 
provide an opportunity for a wider variety of technical and financial 
resources to participate in transmission infrastructure development. 
Western Independent Transmission Group contends that the ability of 
incumbent transmission owners to construct transmission projects 
proposed by other transmission developers under a right of first 
refusal is equivalent to the seizure of intellectual property.
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    \205\ E.g., NextEra; AWEA; Anbaric and PowerBridge; Clean Line; 
LS Power; Northwest & Intermountain Power Producers Coalition; 
Pattern Transmission; FirstWind; Green Energy and 21st Century; 
Colorado Independent Energy Association; Enbridge; Primary Power; 
and Western Independent Transmission Group.
    \206\ LS Power citing Primary Power, LLC, 131 FERC ] 61,015 
(2010) (reh'g pending); Central Transmission, LLC v. PJM 
Interconnection L.L.C., 131 FERC ] 61,243 (2010).
---------------------------------------------------------------------------

    235. Some commenters cite to examples that they believe show the 
benefits of removing barriers to competition by nonincumbent 
transmission developers. For example, Western Independent Transmission 
Group points to the success of Texas's Competitive Renewable Energy 
Zone planning process in supporting transmission development by 
nonincumbent developers. Also, Western Independent Transmission Group 
points to the Trans Bay Cable, Neptune, and Cross Sound Cable 
transmission projects, which were developed by nonincumbent 
transmission developers. Pattern Transmission cites the benefits 
associated with increased competition in the telecommunications and 
railroad industries, arguing that comparable benefits are available in 
the electric industry.
    236. Some commenters supporting the Commission proposal argue that 
the record in this proceeding is sufficient to support taking action at 
this time. Primary Power states that Commission is ``not required to 
make specific findings so long as the agency's factual determinations 
are reasonable.'' \207\ LS Power states that the Commission has legal 
authority to address discrimination against prospective transmission 
owners, it has a substantial record that rights of first refusal are 
unreasonable and result in undue discrimination, thus satisfying the 
National Fuel standard.
---------------------------------------------------------------------------

    \207\ Primary Power cites to Transmission Access Policy Study 
Group v. FERC, 225 F.3d 667, 688 (DC Cir. 2000).
---------------------------------------------------------------------------

    237. Commenters supporting the Proposed Rule generally contend that 
the elimination of rights of first refusal in Commission-jurisdictional 
tariffs and agreements would not be in conflict with the 
responsibilities of incumbent transmission providers, such as the 
obligation imposed under RTO and ISO membership agreements to build 
transmission facilities identified as needed in regional transmission 
plans.\208\ These commenters state that, to the extent that an 
incumbent transmission owner feels unreasonably burdened by its 
obligations to build, a nonincumbent transmission developer would 
welcome the opportunity to respond to competitive solicitations to 
build the obligatory transmission projects. Such commenters further 
note that, as independent transmission developers build transmission 
projects and become transmission owners themselves, they also may be 
subject to appropriate obligations to build adjacent or connecting 
transmission facilities. Northwest & Intermountain Power Producers 
Coalition states that an incumbent's service obligation would come into 
play only if no alternative proposal is available to meet the 
identified need and that, where better alternatives are identified in 
the planning process, there is no good reason to prevent the better 
alternative from being constructed merely because the incumbent has an 
obligation to construct where a better alternative does not exist. 
Western Independent Transmission Group suggests that the obligation to 
build is a benefit, not a burden, because an incumbent transmission 
developer that constructs a transmission project pursuant to an 
obligation will receive full cost-of-service recovery, including a fair 
rate of return on its investment.
---------------------------------------------------------------------------

    \208\ E.g., Anbaric and PowerBridge; Green Energy and 21st 
Century; LS Power; Northwest & Intermountain Power Producers 
Coalition; Pattern Transmission; Primary Power; Transmission Agency 
of Northern California; and Western Independent Transmission Group.
---------------------------------------------------------------------------

    238. Others urge the Commission to provide thoughtful consideration 
to the potential impacts of its proposal.\209\ Energy Future Coalition 
states that, while a right of first refusal should not give incumbent 
utilities the ability to block or stall construction of needed 
infrastructure within their service territories, or to inflate the 
costs of such projects, transmission goals will be frustrated if 
elimination of such provisions bogs down the transmission planning 
process. New England Transmission Owners state that, before taking 
action to eliminate any right of first refusal, the Commission should 
consider the unique way in which transmission projects are identified 
for development, the success of the current planning process, and the 
unique characteristics of the New England system that make the current 
process appropriate for this region. National Rural Electric Coops 
suggest that, prior to proceeding with the proposed reforms, the 
Commission consider adoption of principles to allow load-serving 
entities to participate in projects developed by traditional and 
independent transmission providers and to have the right to acquire an 
ownership participation in any project that it built within their 
service territories.
---------------------------------------------------------------------------

    \209\ E.g., Energy Future Coalition; New England Transmission 
Owners; and MidAmerican.
---------------------------------------------------------------------------

    239. A number of commenters oppose any alteration of rights of 
first refusal in Commission-jurisdictional tariffs and agreements, 
arguing that there is insufficient evidence to justify removal of the 
right of first refusal.\210\ Edison Electric Institute states that, on 
the contrary, there has been substantial evidence submitted to the 
Commission that a right of first refusal benefits consumers and results 
in lower rates, evidence that the Commission has not sought to rebut. 
Southern California Edison alleges that the Commission provides nothing 
more than speculative and vague statements that a right of first 
refusal may preclude nonincumbent transmission developers from 
participating in the regional transmission planning process and, in 
turn, affect rates for transmission service. ITC Companies contend that 
a right of first refusal is not the primary barrier to new market 
entrants and that they see no impediment to

[[Page 49883]]

nonincumbent transmission developers pursuing development opportunities 
through a partnership model whereby right of first refusal rights are 
delegated. Oklahoma Gas & Electric notes that a number of transmission-
only companies have announced significant transmission projects in SPP 
and, joined by MISO Transmission Owners, argues that it is premature 
for the Commission to determine that further reforms are needed to 
further encourage development.
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    \210\ E.g., California ISO; SPP; CapX2020 Utilities; Edison 
Electric Institute; Southern California Edison; Indianapolis Power & 
Light; ITC Companies; MidAmerican; Oklahoma Gas & Electric; PSEG 
Companies Comments; and San Diego Gas & Electric.
---------------------------------------------------------------------------

    240. Citing National Fuel,\211\ some commenters argue that the 
Commission points to no evidence of actual discrimination or adverse 
impact on rates and that it must identify something more than 
theoretical possibilities to justify elimination of federal rights of 
first refusal.\212\ Indicated PJM Transmission Owners assert that, if 
the Commission intends to rely solely on the effects of potential 
discrimination, in the absence of evidence of abuse, it must explain 
why the historical right of incumbent transmission owners to construct 
additions in their service territories so endangers open access to 
transmission service at just and reasonable rates as to justify a 
complete rearrangement of the relationship between public utilities, 
state regulators, and ultimate customers. MISO Transmission Owners 
state that the Proposed Rule fails to demonstrate why the existing 
complaint procedures under section 206 do not protect third parties 
from such theoretical harm.
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    \211\ National Fuel, 468 F.3d 831.
    \212\ E.g., Ad Hoc Coalition of Southeastern Utilities; Edison 
Electric Institute; Indicated PJM Transmission Owners; Large Public 
Power Council; MidAmerican; MISO Transmission Owners; Oklahoma Gas & 
Electric; PSEG Companies; Salt River Project; and San Diego Gas & 
Electric. Large Public Power Council also cites to Associated Gas 
Distributors.
---------------------------------------------------------------------------

    241. Many of these commenters argue that preserving a federal right 
of incumbent transmission owners to build within their service 
territories is the best method to achieve the Commission's overall 
transmission goals. Such commenters contend that incumbent transmission 
owners are better situated to build new transmission facilities.\213\ 
For example, Oklahoma Gas & Electric argues that incumbent transmission 
owners are often in the best position to determine where new 
transmission is needed on their system. CapX2020 Utilities and 
MidAmerican state that load serving transmission providers have a long 
history and relationship with state regulatory bodies that brings value 
to getting needed transmission developed. Ad Hoc Coalition of 
Southeastern Utilities and Southern Companies contend that incumbent 
transmission owners are better situated to obtain any necessary 
approval from state regulators to recover the cost of transmission 
facilities through bundled retail tariffs and that nonincumbent 
developers may have no obligation or ability to do so, depriving the 
state of an opportunity to determine that the proposal is the most 
reliable and cost-effective alternative. Ad Hoc Coalition of Southern 
Utilities adds that a nonincumbent developer's lack of a funding 
mechanism based on retail rates is a function of the state-based 
ratemaking process, not a preference for incumbent transmission owners.
---------------------------------------------------------------------------

    \213\ E.g., PJM; CapX2020 Utilities; Edison Electric Institute; 
Georgia Transmission Corporation; MidAmerican; Omaha Public Power 
District; Pacific Gas & Electric; Sunflower and Mid-Kansas; and 
Transmission Access Policy Study Group.
---------------------------------------------------------------------------

    242. Other commenters question the potential impact removal of a 
federal right of first refusal may have on transmission rates.\214\ 
North Dakota & South Dakota Commissions argue that there is no evidence 
to suggest that nonincumbents are better situated to provide lower cost 
or more reliable service, and note that nonincumbents are not regulated 
by state commissions and not subject to state law obligations regarding 
reliability or state law oversight of their operations. Alabama PSC 
states concern that the proposed elimination of the incumbent's federal 
right of first refusal could increase costs to Alabama consumers. 
Edison Electric Institute argues that the Commission's proposal ignores 
longstanding policy that a public utility's investment is assumed to be 
prudent when a range of options are available, arguing that the 
Proposed Rule would have a reasonable rate depend upon the identity of 
the builder of the transmission facility.
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    \214\ E.g., Alabama PSC; City of Santa Clara; Dominion; Edison 
Electric Institute; MidAmerican; Oklahoma Gas & Electric; PSEG 
Companies; Southern California Edison; Sunflower and Mid-Kansas; and 
Xcel.
---------------------------------------------------------------------------

    243. Some commenters argue that any lower costs that result from 
competition to own and construct transmission projects is likely to be 
more than offset by inefficiencies created in the transmission planning 
process and a loss of economies of scale and scope.\215\ Pacific Gas & 
Electric states that competition may have cost impacts to incumbent 
transmission owners relating to their obligation to maintain or improve 
reliability and security of the existing transmission system to comply 
with current and future reliability standards. Southern Companies 
contend that consumers bear the risk of nonincumbent developers 
declaring bankruptcy or becoming unable or unwilling to complete a 
transmission project, suggesting that the Commission require ``step 
in'' rights in such circumstances to facilitate an incumbent 
transmission owner's assumption of the project, should it voluntarily 
choose to do so. Transmission Dependent Utility Systems state that the 
proposal could raise costs by causing customers outside of an RTO/ISO 
region to pay both the full costs of the incumbent transmission 
provider's transmission system and the full incremental costs of any 
nonincumbent transmission projects necessary to serve its load.
---------------------------------------------------------------------------

    \215\ E.g., Dominion; PSEG Companies; North Dakota & South 
Dakota Commissions; and Oklahoma Gas & Electric Company.
---------------------------------------------------------------------------

    244. Indicated PJM Transmission Owners assert that, even if a 
nonincumbent were to propose a less expensive transmission project for 
recovery through cost-based rates, there is no assurance that its final 
costs will be equal to or lesser than its estimate, or that it has a 
greater likelihood of staying within its cost estimate than an 
incumbent transmission owner. They contend that the Commission 
misapplies cost-effectiveness principles to non-rate matters beyond its 
authority, without factual or logical support. PPL Companies agree, 
arguing that consumers will bear the risk of cost overruns by 
nonincumbent transmission developers. California ISO notes that the 
Trans Bay Cable, cited by Western Independent Transmission Group, had 
significant cost overruns, and that the Neptune and Cross Sound Cable 
transmission projects were merchant transmission projects that, as 
direct current transmission lines, involved fewer concerns about system 
compartmentalization and fragmentation. Southern California Edison 
states that under the Proposed Rule, there does not appear to be any 
incentive for project participants to develop cost-efficient proposals 
because it is not clear if and how customer costs would be considered 
in project selection.
    245. Several comments suggest that the proposal is based on a false 
assumption that providing for greater competition in the provision of 
transmission development will produce benefits to consumers.\216\ They 
state that unlike generation, a competitive model cannot be adopted for 
wholesale transmission because customers have no meaningful alternative 
transmission provider and the development cycle for transmission is 
much longer than for

[[Page 49884]]

generation. California ISO disagrees that the benefits of competition 
cited by Western Independent Transmission Group and Pattern 
Transmission are relevant to its transmission planning process. PPL 
Companies similarly argues that commenters arguing that eliminating the 
right of first refusal benefits competition misunderstand the nature of 
the transmission planning process, noting that RTO planning processes 
do not involve price competition or consumer choice. PPL Companies 
contend that eliminating the right of first refusal would not add 
choice for consumers since the transmission projects included in RTO 
plans are driven by needs, and not by proposals from incumbent or 
nonincumbent developers.
---------------------------------------------------------------------------

    \216\ E.g., California ISO; Indianapolis Power & Light; Oklahoma 
Gas & Electric Company; and Pacific Gas & Electric.
---------------------------------------------------------------------------

    246. A number of commenters assert that removing a federal right of 
first refusal would complicate and undermine the transmission planning 
process.\217\ Delaware PSC states that the Proposed Rule would 
fundamentally change the way transmission facilities are proposed, 
selected, and built, and requires thoughtful consideration of all its 
implications. MISO states that placing regional planners in a role of 
deciding who should build introduces a level of financial competition 
to the planning process that is fundamentally at odds with the high 
level of openness and collaboration under the current approach. Kansas 
City Power & Light and KCP&L Greater Missouri contend that the proposal 
would exacerbate an already complex and arduous process to study, plan 
and implement regional transmission infrastructure. Dominion states 
that eliminating a federal right of first refusal would create a model 
where competitively sensitive information will be withheld from open 
discussion, thus making the planning process less collaborative. Xcel 
agrees that the proposal could harm the planning process and that 
disagreements about transmission project selection could have negative 
impacts on state-level siting and routing approval processes.
---------------------------------------------------------------------------

    \217\ E.g., AEP; Allegheny Energy Companies; Baltimore Gas & 
Electric; Dominion; Edison Electric Institute; First Energy Service 
Company; Indianapolis Power & Light; Kansas City Power & Light and 
KCP&L Greater Missouri; MidAmerican; MISO; MISO Transmission Owners; 
Pacific Gas & Electric; and Southern California Edison.
---------------------------------------------------------------------------

    247. Some commenters caution that implementation of the proposed 
reforms could have unintended consequences affecting reliability.\218\ 
These commenters generally contend that eliminating federal rights of 
first refusal could cause, or exacerbate, operational and reliability 
challenges for transmission system operations and could produce 
operational issues as each transmission provider will have to 
coordinate with more entities to address specific reliability issues. 
Many of these commenters contend that increasing the number of entities 
involved in transmission ownership and grid operations would make 
coordination, maintenance, and service restoration more difficult by 
further fragmenting the transmission system, which they note has been a 
concern of the Commission in the past.
---------------------------------------------------------------------------

    \218\ E.g., Baltimore Gas & Electric; California ISO; Edison 
Electric Institute; MidAmerican; Oklahoma Gas & Electric; Pacific 
Gas & Electric; PJM; PSEG Companies; Southern California Edison; and 
Xcel.
---------------------------------------------------------------------------

    248. Several commenters contend that the right of first refusal is 
inextricably linked to the obligation to build imposed under RTO and 
ISO membership agreements, justifying any difference in treatment 
between incumbent transmission owners and nonincumbent transmission 
developers.\219\ These commenters generally argue that retention of an 
obligation to build without a corresponding right of first refusal 
would impose a serious and unjust and unreasonable burden on incumbent 
transmission owners and is in violation of the FPA. Some state 
commissions express concern that the Commission's proposal may 
undermine the ability of utilities to meet their load service 
obligations.\220\ Other commenters state that it is important to 
maintain an obligation to build for its transmission owning members to 
ensure transmission projects needed for reliability can be developed 
promptly.\221\ Some commenters contend that the Commission's proposed 
reforms would result in undue discrimination against incumbent 
utilities, giving nonincumbent transmission developers the opportunity 
to propose and build a transmission facility, whereas incumbents would 
be required to build any needed transmission facility, including those 
that may be abandoned or not completed by the nonincumbent 
developer.\222\ Many of these commenters contend this would permit 
nonincumbent transmission developers to ``cherry pick'' only the most 
advantageous projects in terms of financial reward and development 
risk.\223\ Southern California Edison contends that the Commission's 
proposal amounts to establishing a free call on a utility's capital 
without any return to compensate it for the time period in which that 
capital had to be held in reserve to meet a backstop obligation to 
build.
---------------------------------------------------------------------------

    \219\ E.g., ISO New England; PJM; SPP; Federal Trade Commission; 
SPP; MISO Transmission Owners; Edison Electric Institute; Georgia 
Transmission Corporation; Indianapolis Power & Light; Large Public 
Power Council; Nebraska Public Power District; Arizona Public 
Service Company; Oklahoma Gas & Electric; MidAmerican; PSEG 
Companies; San Diego Gas & Electric; Southern California Edison; 
Tucson Electric; Xcel; Allegheny Energy Companies; Duke; Baltimore 
Gas & Electric; Dominion; E.ON; Exelon; Westar Integrys; and 
FirstEnergy Service Company.
    \220\ E.g., Florida PSC; Minnesota PUC; and Minnesota Office of 
Energy Security.
    \221\ E.g., ISO New England; MidAmerican; and MISO Transmission 
Owners.
    \222\ E.g., Baltimore Gas & Electric; Edison Electric Institute; 
FirstEnergy Service Company; Large Public Power Council; 
MidAmerican; MISO Transmission Owners; PPL Companies; PSEG 
Companies; and Xcel.
    \223\ E.g., Baltimore Gas & Electric; California ISO; CapX2020 
Utilities; Indianapolis Power & Light; Oklahoma Gas & Electric; 
Southern California Edison; and Xcel.
---------------------------------------------------------------------------

    249. Several commenters express concern about the impact that 
removing a federal right of first refusal in Commission-jurisdictional 
tariffs and agreements may have on RTO and ISO participation.\224\ For 
example, MISO states that the right of its transmission owner members 
to build transmission facilities identified through the planning 
process was, and remains, one of the key considerations for its 
transmission owners to have formed, and to remain a part of, the 
voluntary RTO. MISO Transmission Owners argue that the Proposed Rule 
would result in undue discrimination between transmission owners 
voluntarily participating in RTOs and transmission owners that have not 
joined an RTO. MISO Transmission Owners state that, without a right to 
construct new transmission facilities within their own systems, a 
transmission owner could experience substantial erosion of its revenues 
over time as a result of RTO participation. MISO Transmission Owners 
add that construction obligations and rights in RTOs and ISOs have been 
carefully designed to ensure that RTOs, ISOs, and their members can 
comply with all applicable state and federal service obligations and 
reliability standards. Southern Companies state that the Commission 
should clarify that the reforms relating to nonincumbent transmission 
developers do not apply in non-RTO regions. On the other hand, 
Transmission Agency of Northern California emphasizes that the 
Commission's proposal to remove a right of first refusal from all 
Commission-approved tariffs and agreements should apply in both non-
RTO/ISO and RTO/ISO regions.
---------------------------------------------------------------------------

    \224\ E.g., MISO; MISO Transmission Owners; Edison Electric 
Institute; Alliant Energy; MidAmerican; and Indianapolis Power & 
Light.

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

[[Page 49885]]

    250. Some commenters argue that the existence of native load and 
state franchise obligations further distinguish incumbent transmission 
owners from nonincumbent transmission developers, justifying retention 
of federal rights of first refusal.\225\ These commenters assert that 
nonincumbent developers are not similarly situated because they can 
select the transmission projects they wish to pursue and ignore those 
they deem too risky or insufficiently profitable, unencumbered by a 
``duty to serve'' requiring the construction and maintenance of 
facilities necessary to render reliable, cost-effective service to 
customers in their service territories. For example, Baltimore Gas & 
Electric states that it and others view their licensed obligations to 
protect their service territory from power outages as being paramount 
over their mere financial interests. Edison Electric Institute and MISO 
Transmission Owners argue that differing state law obligations have 
been found to be legitimate factors in determining that two entities 
are not similarly situated.\226\ San Diego Gas & Electric contends that 
removal of federal rights of first refusal raises constitutional 
concerns since, as regulated entities, public utility transmission 
providers are entitled under well-established law to receive a 
reasonable rate of return on their investment in transmission 
infrastructure in discharging their state-mandated service 
obligations.\227\
---------------------------------------------------------------------------

    \225\ E.g., Ad Hoc Coalition of Southeastern Utilities; Edison 
Electric Institute; Large Public Power Council; MISO Transmission 
Owners; Nebraska Public Power District; Xcel; PPL Companies; and 
Xcel. In support, Ad Hoc Coalition of Southeastern Utilities cites 
to California Indep. Sys. Operator Corp., 119 FERC ] 61,076, at P 
369 (2007); Calpine Oneta Power, L.P., 116 FERC ] 61,282, at P 36 
(2006); and Sebring Utils. Comm'n v. FERC, 591 F.2d 1003, 1009 n.24 
(5th Cir. 1979). MISO Transmission Owners also cite to S. Cal. 
Edison Co., 59 FPC 2167, 2185-86 (1977).
    \226\ Edison Electric Institute and MISO Transmission Owners 
cite to Town of Norwood v. FERC, 202 F.3d 392, 403 (1st Cir. 2000).
    \227\ San Diego Gas & Electric supports these assertions by 
citing FPC v. Hope Natural Gas Co., 320 U.S. 591 (1944) and 
Bluefield Water Works v. Public Serv. Comm'n, 262 U.S. 679 (1923).
---------------------------------------------------------------------------

    251. A number of commenters suggest that the Commission consider 
partial elimination of federal rights of refusal.\228\ Many of these 
commenters endorse SPP's current mechanism, under which an incumbent 
utility has a 90-day time limit to exercise its right to construct a 
facility included in the regional transmission plan. AEP suggests that 
the Commission consider a phased approach, beginning with a time limit 
on the exercise of any right of first refusal and, if this does not 
substantially address the Commission's concerns, then consider further 
modification or elimination of the right of first refusal. AEP suggests 
that the Commission also could require each region to report back to 
the Commission within two years on its experience implementing the 
time-limited right of first refusal as a basis for the Commission to 
consider whether a fundamental change of the existing regional 
transmission planning process is needed. California PUC and Exelon 
argue that incumbent transmission owners should maintain the right of 
first refusal for reliability projects located within a single zone. 
Transmission Access Policy Study Group recommends that the Commission 
retain a limited right of first refusal that can be exercised only when 
the incumbent transmission provider forgoes transmission incentives for 
the project and offers meaningful joint ownership opportunities on 
reasonable terms. Other commenters disagree with proposals to maintain 
limited rights of first refusal, generally arguing that such proposals 
would perpetuate the entry barrier.\229\
---------------------------------------------------------------------------

    \228\ E.g., California PUC; Transmission Dependent Utility 
Systems; SPP; AEP; Iberdrola Renewables; Indianapolis Power & Light; 
ITC Companies; MidAmerican; Oklahoma Gas & Electric; Southern 
California Edison; Westar; Xcel; CapX2020 Utilities; and SPP.
    \229\ E.g,, American Antitrust Institute; Anbaric and 
PowerBridge; LS Power; NextEra; Pattern Transmission; and Western 
Independent Transmission Group.
---------------------------------------------------------------------------

    252. Finally, some commenters suggest that the Commission engage in 
additional outreach on this issue before altering federal rights of 
first refusal.\230\ They encourage the Commission to host a technical 
conference or initiate other proceedings so that all of these issues 
can be examined and potential solutions developed in a collaborative 
manner. Sunflower and Mid-Kansas contend that, if problems relating to 
a right of first refusal exist in a particular region, the issue should 
be addressed locally rather than imposing a one-size-fits-all solution 
across all regions.
---------------------------------------------------------------------------

    \230\ E.g., Delaware PSC; NextEra; San Diego Gas & Electric; and 
Tucson Electric.
---------------------------------------------------------------------------

c. Commission Determination
    253. The Commission concludes that there is a need to act at this 
time to remove provisions from Commission-jurisdictional tariffs and 
agreements that grant incumbent transmission providers a federal right 
of first refusal to construct transmission facilities selected in a 
regional transmission plan for purposes of cost allocation.\231\ 
Failure to do so would leave in place practices that have the potential 
to undermine the identification and evaluation of more efficient or 
cost-effective solutions to regional transmission needs, which in turn 
can result in rates for Commission-jurisdictional services that are 
unjust and unreasonable or otherwise result in undue discrimination by 
public utility transmission providers. The Commission addresses the 
need for eliminating such practices in this section and, in the 
sections that follow, our legal authority to do so and the procedures 
by which public utility transmission providers must implement the 
removal of federal rights of first refusal from Commission-
jurisdictional tariffs and agreements.
---------------------------------------------------------------------------

    \231\ As explained in more detail in section III.B.3 below, the 
Commission purposely refers to ``federal rights of first refusal'' 
in this Final Rule because the Commission's action on this issue in 
this Final Rule addresses only rights of first refusal that are 
created by provisions in Commission-jurisdictional tariffs or 
agreements. Nothing in this Final Rule 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. This Final Rule does not require removal of references 
to such state or local laws or regulations from Commission-approved 
tariffs or agreements.
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    254. As the Commission recognized in Order Nos. 888 and 890, it is 
not in the economic self-interest of public utility transmission 
providers to expand the grid to permit access to competing sources of 
supply.\232\ In Order No. 890, the Commission required greater 
coordination in transmission planning on a regional level to remedy the 
potential for undue discrimination by transmission providers that have 
an incentive to avoid upgrading transmission capacity with 
interconnected neighbors where doing so would allow competing suppliers 
to serve the customers of the public utility transmission 
provider.\233\ Although basing its actions on its authority to remedy 
undue discrimination, the Commission found that ``[t]he coordination of 
planning on a regional basis will also increase efficiency through the 
coordination of transmission upgrades that have region-wide benefits, 
as opposed to pursuing transmission expansion on a piecemeal basis.'' 
\234\
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    \232\ Order No. 888, FERC Stats. & Regs. at 31,682; Order No. 
890, FERC Stats. & Regs. ] 31,241 at P 524.
    \233\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 524.
    \234\ Id.
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    255. In response to Order No. 890, regions across the country have 
implemented transmission planning processes that allow for 
consideration of alternative transmission projects proposed at the 
regional level to determine if they better meet the

[[Page 49886]]

region's needs.\235\ The evaluation of alternative transmission 
solutions at the regional level is often referred to as ``top down'' 
planning.\236\ In some regions, heavy emphasis is placed on ``top 
down'' regional planning for all or certain classes of transmission 
facilities. In other regions, local transmission plans are developed in 
which individual public utility transmission providers within the 
region identify solutions to their own local needs prior to the ``top 
down'' consideration of regional alternatives. This is often referred 
to as ``bottom up, top down'' planning.\237\ Although the relative 
weight placed on ``bottom up'' or ``top down'' processes varies by 
region, all of these existing processes allow at some point for 
transmission project developers to offer alternative solutions for 
evaluation on a comparable basis pursuant to criteria that is set forth 
in the public utility transmission providers' OATTs.\238\ By requiring 
the comparable evaluation of all potential transmission solutions, the 
Commission has sought to ensure that the more efficient or cost-
effective solutions are in the regional transmission plan.\239\
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    \235\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 494; 
Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 215-16. Sponsors 
of generation and demand response solutions are provided comparable 
opportunities to offer their proposals in the regional transmission 
planning process. Id.
    \236\ See, e.g., Pacific Gas & Electric Initial Comments 
describing top down planning.
    \237\ See, e.g., Large Public Power Council Initial Comments 
describing bottom up planning.
    \238\ See, e.g., Entergy OATT, Attachment K at Sec.  3.12; 
Florida Power and Light OATT, Appendix 1 to Attachment K, Sec. Sec.  
H and I; ISO New England OATT, Attachment K at Sec.  4.2; Puget 
Sound Energy OATT, Attachment K at Sec.  2; SPP OATT, Attachment O 
at Sec.  III.8.
    \239\ See, e.g., Northwestern Corp., 128 FERC ] 61,040, at P 38 
(2009); El Paso Electric Co., 128 FERC ] 61,063, at P 15 (2009); New 
York Independent System Operator, Inc., 129 FERC ] 61,044, at P 35 
(2009).
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    256. The Commission is concerned that the existence of federal 
rights of first refusal may be leading to rates for jurisdictional 
transmission service that are unjust and unreasonable. Allowing federal 
rights of first refusal to remain in Commission-jurisdictional tariffs 
and agreements would undermine the consideration of potential 
transmission solutions proposed at the regional level. Just as it is 
not in the economic self-interest of public utility transmission 
providers to expand transmission capacity to allow access to competing 
suppliers, it is not in the economic self-interest of incumbent 
transmission providers to permit new entrants to develop transmission 
facilities, even if proposals submitted by new entrants would result in 
a more efficient or cost-effective solution to the region's needs. We 
conclude that an incumbent transmission provider's ability to use a 
right of first refusal to act in its own economic self-interest may 
discourage new entrants from proposing new transmission projects in the 
regional transmission planning process.
    257. Federal rights of first refusal exacerbate these problems by, 
as the Federal Trade Commission and other commenters explain, creating 
a barrier to entry that discourages nonincumbent transmission 
developers from proposing alternative solutions for consideration at 
the regional level. Many commenters note that significant investment is 
needed to support the development of a successful transmission project, 
yet there is a disincentive for a nonincumbent transmission developer 
to commit its resources to a potential transmission project when it 
runs the risk of an incumbent transmission provider exercising its 
federal right of first refusal once the benefits of the transmission 
project are demonstrated. The Commission recognizes that removing 
federal rights of first refusal in Commission-jurisdictional tariffs 
and agreements will not eliminate all obstacles to transmission 
development that may exist under state or local laws or regulations 
and, therefore, may not address all challenges facing nonincumbent 
transmission development in those jurisdictions. It does not follow, 
however, that the Commission should leave in place federal rights of 
first refusal. Moreover, the number of state commission commenters 
supporting the Commission's proposal indicate that, at a minimum, there 
is interest in those jurisdictions to explore the benefits of 
nonincumbent transmission development.
    258. The Commission shares the concerns of some commenters that 
elimination of federal rights of first refusal from Commission-
jurisdictional tariffs and agreements, if not implemented properly, 
could adversely impact the collaborative nature of current regional 
transmission planning processes. The Commission addresses these 
concerns in section III.B.3 by modifying and clarifying the proposed 
framework for implementing our reforms, including elimination of the 
proposed requirement to allow a transmission developer to maintain for 
a defined period a right to build and own a transmission facility. In 
addition, this Final Rule does not require removal of a federal right 
of first refusal for a local transmission facility, as that term is 
defined herein.\240\ The Commission disagrees with commenters asserting 
that reforming federal rights of first refusal would fundamentally 
alter regional transmission planning processes. Public utility 
transmission providers already are required to evaluate whether 
alternative transmission solutions proposed by other developers better 
meet the needs of the region. Therefore, existing regional transmission 
planning processes have mechanisms in place to weigh various 
alternatives against one another. Indeed, this is the fundamental 
nature of ``bottom-up, top-down'' transmission planning, in which local 
needs and solutions are combined within a region and analyzed to 
determine whether regional solutions would be more efficient or cost-
effective than the local solutions identified by individual public 
utility transmission providers.\241\
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    \240\ See definition supra section II.D of this Final Rule.
    \241\ Similarly, the Commission believes that concerns regarding 
the cost-effectiveness of nonincumbent transmission development are 
misplaced. For one solution to be chosen over another in the 
transmission planning process, there must be an evaluation of the 
relative economics and effectiveness of performance for each 
alternative. See, e.g., New York Independent System Operator, Inc., 
129 FERC ] 61,044 at P 35, n.26.
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    259. The Commission understands that the degree to which existing 
transmission planning processes will be impacted by the elimination of 
federal rights of first refusal will vary by region, just as the 
current mechanisms used to evaluate competing transmission projects 
vary by region. For example, the public utility transmission providers 
in a region may, but are not required to, use competitive solicitation 
to solicit projects or project developers to meet regional needs. To 
the extent a region already has in place processes to rely on market 
proposals or competitive solicitations when identifying solutions to 
the region's needs, such existing processes may require relatively 
modest modifications to provide nonincumbent transmission providers 
with the opportunity to propose and construct transmission projects, 
consistent with state and local laws and regulations. In regions 
relying more heavily on local planning with less robust mechanisms to 
identify alternative transmission solutions at the regional level, more 
effort may be needed to implement the Commission's reforms. Within the 
implementation framework adopted below, the Commission provides each 
region with the flexibility necessary to identify the modifications to 
existing transmission planning processes that may be required as a 
result of removing

[[Page 49887]]

federal rights of first refusal from Commission-jurisdictional tariffs 
and agreements.
    260. The Commission is not persuaded to abandon our proposed 
reforms to federal rights of first refusal based on arguments that 
incumbent transmission providers are better situated to build and 
operate transmission facilities. While we acknowledge that incumbent 
transmission providers may have unique knowledge of their own 
transmission systems, familiarity with the communities they serve, 
economies of scale, experience in building and maintaining transmission 
facilities, and access to funds needed to maintain reliability, we do 
not believe removing the federal right of first refusal diminishes the 
importance of these factors. 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. However, we do not believe that, just because an incumbent 
public utility transmission provider may have certain strengths, a 
nonincumbent transmission developer should be categorically excluded 
from presenting its own strengths in support of its proposals or bids.
    261. Various commenters argue that federal rights of first refusal 
are inextricably tied to obligations to build placed on incumbent 
transmission providers, such as those under RTO and ISO member 
agreements. We acknowledge that a public utility transmission provider 
may have accepted an obligation to build in relation to its membership 
in an RTO or ISO, but we do not believe 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. There are many benefits and obligations associated with 
membership in an RTO or ISO and an obligation to build at the direction 
of the RTO or ISO is only one aspect of the agreement. While 
implementation of reforms to federal rights of first refusal may change 
the package of benefits and burdens currently in place for transmission 
owning members of RTOs and ISOs, we find that such changes are 
necessary to correct practices that may be leading to rates for 
jurisdictional transmission service that are unjust and unreasonable.
    262. Some commenters also contend that the federal right of first 
refusal is necessary for incumbent transmission providers to develop 
transmission facilities needed to comply with a reliability standard or 
an obligation to serve customers. We clarify that our actions today are 
not intended to diminish the significance of an incumbent transmission 
provider's reliability needs or service obligations. Currently, an 
incumbent transmission provider may meet its reliability needs or 
service obligations by building new transmission facilities that are 
located solely within its retail distribution service territory or 
footprint. The Final Rule 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 submitted for regional cost allocation. Alternatively, an 
incumbent transmission provider may rely on transmission facilities 
selected in a regional transmission plan for purposes of cost 
allocation. Our decision today does not prevent an incumbent 
transmission provider from continuing to propose transmission projects 
for consideration in the regional transmission planning process and to 
receive regional cost allocation if those projects are selected in a 
regional transmission plan for such purposes, even if they are located 
entirely within its retail distribution service territory or footprint.
    263. Given that incumbent transmission providers may rely on 
transmission facilities selected in a regional transmission plan for 
purposes of cost allocation to comply with their reliability and 
service obligations, delays in the development of such transmission 
facilities could adversely affect the ability of the incumbent 
transmission provider to meet its reliability needs or service 
obligations. To avoid this result, in section III.B.3 below, we 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 the incumbent transmission 
provider proposes, to ensure the incumbent can meet its reliability 
needs or service obligations.
    264. One function of the regional transmission planning process is 
to identify those transmission facilities that are needed to meet 
identified needs on a timely basis and, in turn, enable public utility 
transmission providers to meet their service obligations. Given the 
familiarity incumbent transmission providers have with their own 
systems, we expect that they will continue to participate actively in 
the regional transmission planning process to share their unique 
perspectives regarding whether various potential solutions meet 
particular needs of their systems. To the extent an incumbent 
transmission provider has concerns that a regional transmission 
alternative does not address the identified reliability needs or 
service obligations that would allow it to serve its customers reliably 
to meet state or local laws, whether upon initial evaluation or, as 
relevant, subsequent reevaluation, it can make such concerns known so 
that all relevant information regarding a regional transmission 
alternative can be considered.
    265. The Commission disagrees that elimination of federal rights of 
first refusal would result in discrimination against incumbent 
transmission providers in favor of nonincumbent transmission 
developers. Once a member of an RTO or ISO, a nonincumbent transmission 
developer will be subject to the relevant obligations that apply to the 
RTO or ISO members. While it is true that the obligation of 
nonincumbent transmission developers to expand their transmission 
facilities, once within an RTO or ISO, may apply to fewer transmission 
facilities than those of an incumbent with a large footprint, and that 
some incumbent transmission providers may be subject to different 
requirements under state and local laws, it does not follow that 
eliminating federal rights of first refusal amounts to discrimination 
in favor of nonincumbent transmission developers. Rather, we are merely 
removing a barrier to participation by all potential transmission 
providers. With regard to concerns that our reforms will discourage 
entities from joining or maintaining membership in RTOs and ISOs, we 
note that a variety of factors must be weighed when evaluating the 
benefits and burdens of RTO/ISO membership. In addition, we reject 
Southern Companies' request that we clarify that the reforms related to 
nonincumbent transmission developers do not apply in non-RTO regions; 
the reforms apply equally to public utility

[[Page 49888]]

transmission providers in all regions. The Commission believes that the 
modifications and clarifications provided below with regard to the 
framework under which transmission developers will participate in the 
transmission planning process will alleviate some of the concerns 
expressed by commenters.
    266. We are not persuaded by commenters who argue that the 
reliability of the transmission system is a function of the number of 
public utility transmission providers of that system. In fact, to 
enhance reliability, among other reasons, public utility transmission 
providers have historically connected to the transmission systems of 
others, as well as jointly owned transmission facilities, and have 
therefore developed experience, protocols, and business models for 
coordinated operations with multiple transmission providers, operators, 
and users. Moreover, many of the same commenters that raise reliability 
concerns also suggest that nonincumbent transmission developers instead 
pursue the merchant model of development, which similarly increases 
rather than decreases the number of transmission providers within a 
region. All providers of bulk-power system transmission facilities, 
including nonincumbent transmission developers, that successfully 
develop a transmission project, are required to be registered as 
functional entities and must comply with all applicable reliability 
standards.\242\ Together with the additional requirements we adopt in 
section III.B.4 below, the Commission finds these protections 
sufficient to support our decision here to eliminate the federal rights 
of first refusal contained in Commission-jurisdictional tariffs and 
agreements.
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    \242\ 18 CFR 39.2(a) (2011).
---------------------------------------------------------------------------

    267. The Commission recognizes that there may be circumstances when 
an incumbent transmission provider may be called upon to complete a 
transmission project that it did not sponsor. For example, a situation 
may arise where an incumbent transmission provider is called upon to 
complete a transmission project that another entity has abandoned. 
There also may be situations in which an incumbent transmission 
provider has an obligation to build a project that is selected in the 
regional transmission plan for purposes of cost allocation but has not 
been sponsored by another transmission developer. We clarify that both 
of these situations 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. In addition, the Commission addresses reliability concerns that 
may arise under those circumstances below.
    268. For the foregoing reasons, and in light of the evaluation 
procedures required in section III.B.3 below, the Commission finds that 
there is sufficient justification in the record to implement the 
requirements regarding rights of first refusal contained in Commission-
jurisdictional tariffs or agreements. The Commission is not required to 
identify specific evidence to justify our actions today. Our task in 
this respect is to show that there is `` `ground for reasonable 
expectation that competition may have some beneficial impact.' '' \243\ 
Although the Commission has previously accepted, in some cases, and 
rejected, in others, a federal right of first refusal, we find more 
persuasive in light of the comments in this proceeding, the 
Commission's reasoning in rejecting the federal right of first refusal. 
In particular, the Commission rejected a right of first refusal based 
on an expectation that ``[t]he presence of multiple transmission 
developers would lower costs to customers.'' \244\ We have carefully 
considered the record in the proceeding and therefore find further 
procedures to evaluate the need for the reforms adopted herein to be 
unnecessary.
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    \243\ Wisconsin Gas Company v. FERC, 770 F.2d 1144, 1158 (DC 
Cir. 1985) (citing FCC v. RCA Communications, Inc., 346 U.S. 86, 96 
(1953)).
    \244\ 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).
---------------------------------------------------------------------------

    269. Finally, we disagree with San Diego Gas & Electric that the 
elimination of a federal right of first refusal raises concerns under 
FPC v. Hope Natural Gas Co. and Bluefield Water Works v. Public Serv. 
Comm'n. As San Diego Gas & Electric notes, these cases stand for the 
principle that utilities are entitled to receive a reasonable return on 
their investment. They do not, however, speak to the issue of who may 
make an investment. They thus require only that a utility receive a 
reasonable rate of return on the investments that it makes, not that 
the utility receive a preferential right to make those investments.
2. Legal Authority To Remove a Federal Right of First Refusal
a. Commission Proposal
    270. In the Proposed Rule, the Commission explained that the 
existing planning process may not result in a cost-effective solution 
to regional transmission needs and transmission projects that are in a 
regional transmission plan therefore may be developed at a higher cost 
than necessary. The Commission stated that the result may be that 
regional transmission services may be provided at rates, terms and 
conditions that are not just and reasonable.\245\ The Commission also 
stated that it may be unduly discriminatory or preferential to deny a 
nonincumbent public utility transmission developer that sponsors a 
project that is in a regional transmission plan the rights of an 
incumbent public utility transmission developer that are created by a 
public utility transmission provider's tariffs or agreements subject to 
the Commission's jurisdiction. Under these circumstances, the 
Commission noted that nonincumbent transmission developers may be less 
likely to participate in the regional transmission planning process. 
The Commission stated that, if the regional transmission planning 
process does not consider and evaluate transmission projects proposed 
by nonincumbents, it cannot meet the principle of being ``open.''
---------------------------------------------------------------------------

    \245\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 87-88.
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b. Comments Regarding the Commission's Authority To Implement the 
Proposal
    271. Several commenters argue that the Commission has adequate 
statutory authority to undertake the reforms in the Proposed Rule.\246\ 
Some of the commenters supporting the Commission's proposal to 
eliminate federal rights of first refusal from Commission-
jurisdictional tariffs and agreements specifically addressed the scope 
of the Commission's authority under section 206 of the FPA. Primary 
Power contends that the Commission is authorized under section 206 to 
remove or limit the right of first refusal, which is a rule, practice, 
or contract condition subject to its jurisdiction. Primary Power states 
that, while the proposal to eliminate the right of first refusal 
represents a change in the Commission's policy of tolerance or 
occasional acceptance of the right of first refusal, this change in 
policy is justified as in the public interest. Primary Power

[[Page 49889]]

argues that rights of first refusal are creatures of regulated services 
that are subject to federally-regulated tariffs and, therefore, 
proponents of rights of first refusal must find some independent legal 
basis for the property rights they seek to protect.
---------------------------------------------------------------------------

    \246\ E.g., Iberdrola Renewables; 26 Public Interest 
Organizations; Exelon; ITC Companies; LS Power; Multiparty 
Commenters; and Primary Power.
---------------------------------------------------------------------------

    272. LS Power argues that the Commission has a duty to stamp out 
all forms of discrimination in the form of a right of first refusal, 
whether written in the OATT or other agreement, or simply as part of a 
long-standing bias arising from a closed planning process. LS Power 
contends that eliminating rights of first refusal is a critical step 
toward true competition in the electric industry, and essential to 
ensuring that new transmission infrastructure is provided to consumers 
at just and reasonable rates. LS Power notes that the Commission has 
historically required the elimination of provisions that are 
anticompetitive on their face.\247\ Joined by American Forest & Paper, 
LS Power further argues that elimination of a federal right of first 
refusal would not be inconsistent with existing state laws, noting the 
support for the Commission proposal by a number of state commissions 
submitting comments.
---------------------------------------------------------------------------

    \247\ LS Power (citing Gulf States Utils. Co., 5 FERC ] 61,066 
(1978)).
---------------------------------------------------------------------------

    273. Other commenters contend that the Commission does not have the 
legal authority to implement the proposed reforms related to rights of 
first refusal in Commission-jurisdictional tariffs or agreements. Some 
commenters argue that the FPA does not give the Commission the 
authority to address discrimination between incumbent and nonincumbent 
transmission developers, arguing that the FPA's protection against 
undue discrimination is concerned with the protection of consumer 
interests and does not extend to nonincumbent transmission 
developers.\248\ Ad Hoc Coalition of Southeastern Utilities states that 
precedent shows that the rights of competitors are neither protected 
nor contemplated in FPA section 205(b)'s proscription against undue 
discrimination.\249\ Edison Electric Institute agrees, arguing that an 
undue discrimination analysis in the context of the right of first 
refusal provisions and planning processes is unsupportable, explaining 
that such provisions are not rates, terms, and conditions of a service 
that a transmission owner provides to its customers. Edison Electric 
Institute states that the Commission previously has not taken the step 
of characterizing transmission planning as an obligation or service to 
non-customers to facilitate their competing efforts to own transmission 
facilities. Edison Electric Institute further states that the 
comparability analysis for undue discrimination could not apply because 
ownership is not a service that a transmission owner provides to 
itself.
---------------------------------------------------------------------------

    \248\ E.g., Ad Hoc Coalition of Southeastern Utilities; Large 
Public Power Council; Nebraska Public Power District; Omaha Public 
Power District; Xcel; and Indicated PJM Transmission Owners (citing 
Grand Council of the Crees v. FERC, 198 F.3d 950, 956 (DC Cir. 
2000)).
    \249\ Ad Hoc Coalition of Southeastern Utilities cites to 
Brunswick Corp. v. Pueblo Bowl-O-Mat, Inc., 429 U.S. 477, 487-89 
(1977), Cargill, Inc. v. Montfort of Colorado, Inc., 479 U.S. 104, 
115-17 (1976), City of Frankfort v. FERC, 678 F.2d 699, 707 (7th 
Cir. 1982).
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    274. Indicated PJM Transmission Owners contend that the undue 
discrimination concerns underlying Order. No. 888, regarding access to 
transmission facilities for loads and for competing suppliers of 
wholesale electricity, are not present here. Indicated PJM Transmission 
Owners argue the Commission does not and cannot find that relying on 
incumbent transmission owners to build necessary upgrades to their 
systems discriminates either in the terms of service available to 
different classes of transmission customers or in the terms upon which 
wholesale sellers and buyers gain access to the transmission system.
    275. Some commenters analogize to the Commission's jurisdiction 
under section 205 of the FPA, arguing that there are only two types of 
undue discrimination actionable under section 205: treating similar 
customers differently or affording similar treatment to dissimilar 
customers.\250\ Some of these commenters assert that the court in City 
of Frankfort v. FERC \251\ noted that section 205 provisions focus on 
the fair treatment of customers. Similarly, Nebraska Public Power 
District states Public Service Commission of Indiana \252\ stands for 
the proposition that the antidiscrimination policy in section 205(b) is 
violated where one consumer has its rates raised significantly above 
what other similarly situated consumers are paying.
---------------------------------------------------------------------------

    \250\ E.g., Nebraska Public Power District; Large Public Power 
Council; and MISO Transmission Owners. Some of these commenters cite 
to Alabama Elec. Coop., Inc. v. FERC, 684 F.2d 20, 27-28 (DC Cir. 
1984), Sacramento Mun. Util. Dist. v. FERC, 474 F.3d 797, 802 (DC 
Cir. 2007), City of Vernon v. FERC, 845 F.2d 1042, 1046 (DC Cir. 
1988), Ohio Power Co. v. FERC, 744 F.2d 162, 165 n.3 (DC Cir. 1984), 
and ``Complex'' Consol. Edison Co. v. FERC, 165 F.3d 992, 1012 (DC 
Cir. 1999).
    \251\ City of Frankfort v. FERC, 678 F.2d 699, 704 (7th Cir. 
1982).
    \252\ Pub. Serv. Comm'n of Indiana, Inc. v. FERC, 575 F.2d 1204, 
1213 (7th Cir. 1978).
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    276. Other commenters also argue that the Commission lacks general 
jurisdiction over the siting, construction, or ownership of 
transmission facilities, matters they assert Congress intentionally 
left to the states, as demonstrated by a comparison between the FPA and 
the Natural Gas Act.\253\ Commenters assert that the proposal to adopt 
rules governing who can build transmission within an incumbent 
transmission owner's zone exceeds the authority conferred upon the 
Commission under the FPA to regulate the terms and conditions of 
service and, in essence, create a federal franchise for transmission 
service.\254\
---------------------------------------------------------------------------

    \253\ E.g., Ad Hoc Coalition of Southeastern Utilities; Nebraska 
Public Power District; Oklahoma Gas and Electric Company; Omaha 
Public Power District; PPL Companies; Large Public Power Council; 
Xcel; Indianapolis Power & Light; Edison Electric Institute; 
Indicated PJM Transmission Owners; and Virginia State Corporation 
Commission. Indicated PJM Transmission Owners cite to Altamont Gas 
Transmission Co. v. FERC, 92 F.3d 1239, 1248 (DC Cir. 1996).
    \254\ E.g., PPL Companies and PSEG Companies.
---------------------------------------------------------------------------

    277. Other commenters argue that the Commission is provided only 
limited backstop siting authority under section 216 of the FPA, a grant 
of authority that the courts have emphasized is subservient to the 
primary jurisdiction of the states.\255\ Oklahoma Gas & Electric 
Company argues that, in enacting section 215 of the FPA, Congress 
expressly declined to grant the Commission the authority to require the 
construction of facilities or the expansion of the grid. PPL Companies 
contend that the Commission's jurisdiction under FPA sections 210 and 
211 to order existing utilities to enlarge their facilities, if 
necessary to permit transmission service or interconnection, can be 
invoked only pursuant to specific procedures and after specific 
findings are made.
---------------------------------------------------------------------------

    \255\ E.g., Ad Hoc Coalition of Southeastern Utilities; 
Indicated PJM Transmission Owners; Oklahoma Gas & Electric Company; 
and PPL Companies. Indicated PJM Transmission Owners cite to 
Piedmont Envtl. Council v. FERC, 558 F.3d 304 (4th Cir. 2009).
---------------------------------------------------------------------------

    278. Oklahoma Gas & Electric Company asserts that, for the 
Commission to extend its jurisdiction over actions that indirectly 
affect activity otherwise governed by the states, the Commission must 
show that the action in question has a direct and significant effect on 
jurisdictional rates. Oklahoma Gas & Electric Company argues that the 
courts are unwilling to allow the Commission to regulate activity if, 
in so doing, the Commission is directly regulating activity that was 
specifically reserved for the states.\256\

[[Page 49890]]

Oklahoma Gas & Electric Company cites to National Association of 
Regulatory Utility Commissioners v. FERC, 475 F.3d 395, 401 (DC Cir. 
2004), where the court found that Commission regulations related to 
generator interconnection procedures bore a close enough relationship 
to its authority over jurisdictional transmission services that the 
exercise of jurisdiction over interconnection service was permissible.
---------------------------------------------------------------------------

    \256\ Oklahoma Gas & Electric Company (citing Northwest Central 
Pipeline Corp. v. State Corp. Comm'n of Kansas, 489 U.S. 493 (1989); 
Connecticut Dept. of Pub. Util. Control v. FERC, 569 F.3d 477, 484 
(DC Cir. 2009); Mississippi Indus. v. FERC, 808 F.2d 1525, 1542-43 
(DC Cir. 1987)).
---------------------------------------------------------------------------

    279. Commenters opposing the Commission's proposed reforms 
generally reject the notion that the Commission is acting only to 
eliminate the federal right of first refusal, stating that the Proposed 
Rule would go much farther by regulating the protocols for determining 
the entity responsible to construct an upgrade. Indicated PJM 
Transmission Owners argue that, to the extent a state-created right is 
reflected in an RTO or ISO tariff or agreement, it cannot then be 
converted by the Commission into a federal based right that the 
Commission can eliminate by its own regulation. Indicated PJM 
Transmission Owners assert that the fact that the transmission provider 
may be an RTO or ISO does not expand the Commission's jurisdiction 
because the transmission owner is still the public utility that makes 
and supports financial investments. They argue that the Commission 
cannot use such a voluntary association to require utilities to 
surrender their statutory rights, in accordance with Atlantic City 
Electric Co. v. FERC.\257\
---------------------------------------------------------------------------

    \257\ 295 F.3d 1 (DC Cir. 2002) (Atlantic City).
---------------------------------------------------------------------------

    280. Other commenters similarly agree that not every provision of a 
Commission-jurisdictional rate schedule or tariff governs the terms and 
conditions of jurisdictional services.\258\ For example, PPL Companies 
argues that there are numerous provisions in agreements required to be 
filed with the Commission that are not rates or other terms or 
conditions that affect rates, such as provisions addressing force 
majeure and indemnification. PPL Companies and others point to 
provisions in transmission owner agreements or RTO operating agreements 
that establish governance as an example of terms that are beyond the 
Commission's jurisdiction.\259\ Indicated PJM Transmission Owners argue 
that, consistent with CAISO v. FERC, section 206 is not implicated 
because the building and owning of an upgrade is not a practice or 
contract that affects a rate, charge, or classification for 
transmission. Indicated PJM Transmission Owners argue that regulation 
of the determination of which entity constructs transmission additions 
and expansions is a regulation of whether the utility can provide a 
service at all, not the rate for the service. Indicated PJM 
Transmission Owners explain that CAISO v. FERC noted that the FPA 
provides the Commission with limited power regarding corporate 
governance in section 305, which involves interlocking directorates, 
and this supports the proposition that section 206 was not intended to 
reach such matters.\260\
---------------------------------------------------------------------------

    \258\ E.g., Oklahoma Gas & Electric; and PPL Companies. In 
support, Oklahoma Gas & Electric Company cites to PSI Energy, Inc., 
55 FERC ] 61,254, at 61,811 (1991), reh'g denied, 56 FERC ] 61,237 
(1991).
    \259\ PPL Companies (citing CAISO v. FERC, 372 F.3d 395 (DC Cir. 
2004)).
    \260\ In addition, FirstEnergy Service Company states that the 
court in CAISO v. FERC 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 authority.
---------------------------------------------------------------------------

    281. Indicated PJM Transmission Owners contend that each of the 
choices a utility's management makes potentially constitutes a 
``practice'' that eventually affects rates insofar as the utility seeks 
to recover the resulting costs. If the Commission concludes that an 
investment or other business decision is the product of imprudent 
management, Indicated PJM Transmission Owners contend that the 
Commission has authority to consider denying recovery of excessive 
costs resulting from that decision, not to supplant the public 
utility's management's decision-making authority.\261\ Joined by 
FirstEnergy Service Company, Indicated PJM Transmission Owners argue 
that a fundamental premise of the FPA is that a utility has a right to 
recover prudently incurred costs, and a corollary of this principle is 
that a utility must have the right to decide whether to make those 
investments.\262\
---------------------------------------------------------------------------

    \261\ Indicated PJM Transmission Owners (citing Town of Norwood 
v. FERC, 80 F.3d 526, 531 (DC Cir. 1996)).
    \262\ Indicated PJM Transmission Owners (citing Mo. ex. rel. 
Southwestern Bell Tel. Co. v. Pub. Serv. Comm'n, 262 U.S. 276, 289 
n.1 (1923)). Indicated PJM Transmission Owners also note that 
Congress did provide similar authority in laws that parallel the 
FPA, such as section 402 of the Transportation Act of 1920, and 
sections 5 and 7 of the Natural Gas Act.
---------------------------------------------------------------------------

    282. Indicated PJM Transmission Owners disagree with the 
Commission's statement that the regional transmission planning 
processes that do not consider and evaluate of projects proposed by 
nonincumbent transmission developers cannot meet the principle of being 
``open.'' They argue that the Commission cannot, by relying upon 
nondiscrimination principles, bootstrap authority it does not have for 
mandating the sponsorship model. Citing Office of Consumers' Counsel v. 
FERC,\263\ Indicated PJM Transmission Owners argue that the Commission 
cannot redefine the transmission planning principles adopted in Order 
No. 890 to encompass matters that were never contemplated when it was 
issued. Indicated PJM Transmission Owners assert that nothing about the 
transmission owners' construction rights and obligations prohibits 
parties from participating in the process or proposing transmission 
projects. They state that the Commission has offered no rationale for 
concluding that the requirement of openness must be redefined to 
include a new sponsorship model.
---------------------------------------------------------------------------

    \263\ Office of Consumers' Counsel v. FERC, 655 F.2d 1132, 1148 
(DC Cir. 1980).
---------------------------------------------------------------------------

    283. National Grid notes that the rights and obligations of 
transmission owners in New England to own and construct transmission 
facilities or upgrades located within or connected to their existing 
electric systems were extensively litigated in the proceeding where the 
Commission found that ISO New England satisfied the requirements to be 
an RTO. National Grid states that in that proceeding, the Commission-
approved contractual language in Section 3.09 of ISO New England's 
Transmission Operating Agreement providing that, absent agreement of 
ISO New England and the participating transmission owners to an 
amendment to these provisions, they will be subject to the Mobile-
Sierra doctrine. Therefore, National Grid argues that the subject 
provisions cannot be modified by the Commission unless it finds they 
are contrary to the public interest. It submits that there is no 
evidence to meet this high standard. National Grid requests that 
Commission should either clarify that Commission-approved rights to 
build of transmission owners like those in New England would not be 
affected by the proposed NOPR requirements, or modify those 
requirements in the Final Rule to allow transmission owners in New 
England to continue to meet regional needs under the existing planning 
process.
c. Commission Determination
    284. The Commission determines that it has the authority under 
section 206 of the FPA to implement the reforms adopted to eliminate 
provisions in Commission-jurisdictional tariffs and agreements that 
grant federal rights of first refusal to incumbent transmission

[[Page 49891]]

providers with respect to the construction of transmission facilities 
selected in a regional transmission plan for purposes of cost 
allocation. The Commission's remedial authority under FPA section 206 
of the FPA is broad and allows us to act, as we do here, to revise 
terms in jurisdictional tariffs and agreements that may cause the 
rates, terms or conditions of transmission service to become unjust and 
unreasonable or unduly discriminatory or preferential.\264\ As 
explained in the preceding section, granting incumbent transmission 
providers a federal right of first refusal with respect to transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation effectively restricts the universe of transmission 
developers offering potential solutions for consideration in the 
regional transmission planning process. This is unjust and unreasonable 
because it may result in the failure to consider more efficient or 
cost-effective solutions to regional needs and, in turn, the inclusion 
of higher-cost solutions in the regional transmission plan. It is 
squarely within our authority under FPA section 206 to correct this 
deficiency.
---------------------------------------------------------------------------

    \264\ Associated Gas Distributors, 824 F.2d 981, 1008 (DC Cir. 
1985).
---------------------------------------------------------------------------

    285. A federal right of first refusal is, in the language of 
section 206(a), a ``rule, regulation, practice, or contract'' affecting 
the rates for jurisdictional transmission service. Where the Commission 
finds that such rules, regulations, practices or contracts are 
``unjust, unreasonable, unduly discriminatory, or preferential,'' the 
Commission must determine ``the just and reasonable rate, charge, 
classification, rule, regulation, practice, or contract to be 
thereafter observed and in force, and shall fix the same by order.'' In 
light of our finding above that 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, the Commission is compelled under section 206(a) to 
take corrective action here. 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.'' \265\ The Commission here 
is 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. As explained 
in greater depth below, these matters fall directly within the ambit of 
the court's interpretation of a practice affecting rates.
---------------------------------------------------------------------------

    \265\ CAISO v. FERC, 372 F.3d 395 at 403.
---------------------------------------------------------------------------

    286. In addition, federal rights of first refusal create 
opportunities for undue discrimination and preferential treatment 
against nonincumbent transmission developers within existing regional 
transmission planning processes. The Commission has long recognized 
that it has a responsibility to consider anticompetitive practices and 
to eliminate barriers to competition.\266\ Indeed, the Supreme Court 
has said that ``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.'' \267\ In 
requiring the elimination of federal rights of first refusal from 
Commission-jurisdictional tariffs and agreements, we are acting in 
accordance with our duty to maintain competition.
---------------------------------------------------------------------------

    \266\ Gulf States Utils. Co., 5 FERC ] 61,066 at 61,098.
    \267\ Otter Tail Power Co. v. United States, 410 U.S. 366 at 374 
(1973).
---------------------------------------------------------------------------

    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. The reforms are 
focused solely on public utility transmission provider tariffs and 
agreements subject to the Commission's jurisdiction. While many 
commenters indicate that they disagree with these statements, none of 
them has explained adequately how our actions will override or conflict 
with state laws or regulations. The Commission acknowledges that there 
may be restrictions on the construction of transmission facilities by 
nonincumbent transmission providers under rules or regulations enforced 
by other jurisdictions. Nothing in this Final Rule 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. It does not follow that the Commission has no authority to 
remove such restrictions in the tariffs or agreements subject to its 
jurisdiction.
    288. The Commission disagrees with commenters arguing that the 
effect of a federal right of first refusal on jurisdictional rates is 
too tenuous to support action. These commenters argue that the holding 
of CAISO v. FERC,\268\ prevents us from treating a federal right of 
first refusal as a practice that affects transmission rates. In that 
case, the court held that the Commission has no authority to replace 
the selection method or membership of the governing board of the 
California ISO, which had been established under state law.\269\ The 
court found that such internal governance practices were too remote 
from the California ISO's rate structure to be considered practices 
that affect rates for purposes of section 206 and, as a result, 
rejected the Commission's attempt to impose governance requirements 
that conflicted with state law.\270\
---------------------------------------------------------------------------

    \268\ 372 F.3d 395 at 399.
    \269\ CAISO v. FERC, 372 F.3d 395 at 398.
    \270\ Id. at 403.
---------------------------------------------------------------------------

    289. Here, however, the Commission is focused on the effect that 
federal rights of first refusal in Commission-approved tariffs and 
agreements have on the rates for jurisdictional transmission services 
and on undue discrimination. This extends well beyond the internal 
corporate governance matters at issue in CAISO v. FERC. The federal 
rights of first refusal at issue in this proceeding can have the effect 
of limiting the identification and evaluation of potential solutions to 
regional transmission needs and, as a result, increasing the cost of 
transmission development that is recovered from jurisdictional 
customers through rates. The selection of transmission facilities in a 
regional transmission plan for purposes of cost allocation is 
therefore, unlike corporate governance matters, directly related to 
costs that will be allocated to jurisdictional ratepayers.
    290. Other commenters rely on Mo. ex. rel. Southwestern Bell Tel. 
Co. v. Pub. Serv. Comm'n for the proposition that, because a utility 
has a right to recover prudently incurred costs, it has a corollary 
right to decide whether to incur those costs, which the Commission 
cannot violate by eliminating a federal right of first refusal. In that 
case, the court explained that a utility's right to make investment 
decisions is grounded in the business judgment rule, which prevents 
courts from substituting their judgment on the prudence of investment 
decisions for that of corporate directors and officers.\271\ Nothing in 
that case, however, supports a claim to an exclusive right to make 
investments under a federal right of first refusal, only the need to 
defer to business judgment when investment decisions are in fact

[[Page 49892]]

made. In removing a federal right of first refusal from Commission-
jurisdictional tariffs and agreements, the Commission is drawing no 
conclusion regarding the prudence of any investment decision, nor is 
the Commission seeking to determine which particular entity should 
construct any particular transmission facility. The effect of these 
reforms is to allow more types of entities to be considered for 
potential construction responsibility, not to make choices among those 
transmission developers or their proposed transmission facilities.
---------------------------------------------------------------------------

    \271\ See Mo. ex. rel. Southwestern Bell Tel. Co. v. Pub. Serv. 
Comm'n, 262 U.S. 276, 289 (1923).
---------------------------------------------------------------------------

    291. The Commission therefore determines that these reforms 
regarding elimination of federal rights of first refusal from 
Commission-jurisdictional tariffs and agreements are not prevented by 
state law or otherwise limited by the FPA. In directing the removal of 
a federal right of first refusal from Commission-jurisdictional tariffs 
and agreements, the Commission 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 our 
authorities under section 215 or 216. Similarly, nothing in our actions 
today is inconsistent with our obligations under section 217. Indeed, 
section 217(b)(4) directs the Commission to exercise its authority ``in 
a manner that facilitates the planning and expansion of transmission 
facilities to meet the reasonable needs of load serving entities to 
satisfy [their] load serving obligations.'' 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.
    292. We decline to address at this time the merits of National 
Grid's arguments 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 makes the findings that National 
Grid contends are required by application of the Mobile-Sierra 
doctrine.\272\ We find that the record is not sufficient to address the 
specific issues raised by National Grid in this generic proceeding. 
Moreover, we generally do not interpret an individual contract in a 
generic rulemaking, and we are not persuaded to do so here given the 
limited record developed so far on section 3.09. Thus, we conclude that 
these arguments, including National Grid's argument as to the 
applicable standard of review, are better addressed as part of the 
proceeding on ISO New England's compliance filing pursuant to this 
Final Rule, where interested parties may provide additional 
information.
---------------------------------------------------------------------------

    \272\ In support of its argument, National Grid cites ISO New 
England, Inc., 109 FERC ] 61,147, at P 78 (2004). In that order, the 
Commission stated, ``We will grant Mobile-Sierra treatment, as 
requested by the Filing Parties. Section 3.09 provides direction to 
the Transmission Owners and the ISO-NE RTO to follow planning 
procedures contained in the ISO-NE RTO OATT. As such, this provision 
will have no adverse impact on third parties or the New England 
market.''
---------------------------------------------------------------------------

3. Removal of a Federal Right of First Refusal From Commission-
Jurisdictional Tariffs and Agreements
a. Commission Proposal
    293. In the Proposed Rule, the Commission sought comment on a 
framework to eliminate from a transmission provider's OATT or 
agreements subject to the Commission's jurisdiction provisions that 
establish a federal right of first refusal for an incumbent 
transmission provider with respect to transmission facilities that are 
included in a regional transmission plan. The Commission proposed to 
require each public utility transmission provider to revise its OATT 
to: (1) Establish appropriate qualification criteria for determining an 
entity's eligibility to propose a project in the regional transmission 
planning process, whether that entity is an incumbent transmission 
owner or a nonincumbent transmission developer; (2) include a form by 
which a prospective project sponsor would provide information in 
sufficient detail to allow the proposed project to be evaluated in the 
regional transmission planning process, and provide a single, specified 
date by which proposals must be submitted; (3) describe a transparent 
and not unduly discriminatory or preferential process used by the 
region for evaluating whether to include a proposed transmission 
facility in a regional transmission plan; (4) remove, along with 
corresponding changes in any other Commission-jurisdictional agreement, 
provisions that establish a federal right of first refusal for an 
incumbent transmission provider and include a description of how the 
regional transmission planning process provides a right to construct a 
selected project to the project sponsor, including potential 
modifications to proposed projects; (5) provide the right to develop a 
project for a defined period of time if not initially included in a 
regional transmission plan; and, (6) provide a comparable opportunity 
for incumbent and nonincumbent transmission project developers to 
recover the cost of a transmission facility through a regional cost 
allocation method.\273\
---------------------------------------------------------------------------

    \273\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 90-96.
---------------------------------------------------------------------------

    294. Under this framework, the Commission proposed that neither 
incumbent nor nonincumbent transmission facility developers should, as 
a result of a Commission-approved OATT or agreement, receive different 
treatment in a regional transmission planning process. The Commission 
stated that both should share similar benefits and obligations 
commensurate with that participation, including the right, consistent 
with state or local laws or regulations, to construct and own a 
transmission facility that it sponsors in a regional transmission 
planning process and that is selected in the regional transmission 
plan. The Commission proposed that the tariff changes to implement 
these proposed reforms would be developed through an open and 
transparent process involving the public utility transmission provider, 
its customers, and other stakeholders.
    295. Given the interrelated nature of comments regarding the first 
two and the remaining four elements of the Commission's proposed 
framework, the Commission groups comments accordingly and then turns to 
addressing the comments collectively.
b. Comments Regarding Developer Qualification and Project 
Identification
    296. A number of commenters address issues related to the first two 
aspects of the Commission's proposed framework, governing mechanisms by 
which entities could propose a project in the regional transmission 
planning process.\274\ San Diego Gas & Electric contends that any 
qualification criteria for potential transmission developers should 
address all of the technical and financial capabilities necessary for 
the entity to support the transmission project, if approved, for its 
expected lifetime, including provisions of security and insurance, as 
well as other requirements, such as those relating to the proponent's 
capital structure. Wind Coalition agrees that transmission project 
developers should be required to satisfy certain financial standards to 
ensure that they can properly construct and maintain their proposed 
projects. According to Wind Coalition, the experience of the 
Competitive

[[Page 49893]]

Renewable Energy Zones in ERCOT has demonstrated the need for a 
selection procedure that provides for: Clearly defined standards for 
selection; selection within a reasonable time period; and a definite 
beginning and ending date to avoid unnecessary delay in selection and 
construction and to prevent a strategy of delay or gamesmanship.
---------------------------------------------------------------------------

    \274\ E.g., American Transmission; Connecticut & Rhode Island 
Commissions; Federal Trade Commission; Integrys; ISO-NE; Large 
Public Power Council; MidAmerican; Massachusetts Departments; 
NEPOOL; New England States Committee on Electricity; New England 
Transmission Owners; New Jersey Board; NextEra; Northeast Utilities; 
and Western Independent Transmission Group.
---------------------------------------------------------------------------

    297. Most commenters that weighed in on this issue urge the 
Commission not to adopt a one-size-fits-all set of requirements and, 
instead, allow each region to develop criteria appropriate for the 
region.\275\ A number of commenters, however, encourage the Commission 
to identify the types of criteria that must be addressed to codify 
expectations and ensure that all entities are operating under the same 
requirements.\276\ Old Dominion recommends that the following criteria 
be used to evaluate proposers of projects: Financial viability; 
technical expertise; authority or ability to obtain and meet all 
necessary regulatory requirements, including condemnation where 
necessary; and an exit strategy to address how the facilities can or 
will be transferred if an entity is no longer able to meet financial or 
other obligations associated with the project. PJM supports a 
requirement that each project developer demonstrate that it has 
received up-front authority to site its project from the relevant 
states because, without such authority, it would be fruitless to 
designate a project to the prospective project developer. In reply, 
however, Atlantic Wind Connection disagrees with PJM, instead 
suggesting that developers receive state siting approval within a 
reasonable time after selection of the project in a regional 
transmission plan.
---------------------------------------------------------------------------

    \275\ E.g., New York ISO; Transmission Agency of Northern 
California; California Commissions; Arizona Public Service Company; 
Northeast Utilities; and SPP.
    \276\ E.g., Edison Electric Institute; California ISO; Pacific 
Gas & Electric; Exelon; Southern California Edison; Southern 
Companies; PJM; and National Grid.
---------------------------------------------------------------------------

    298. While many commenters endorse requiring project developers to 
meet qualification criteria showing their financing and technical 
capabilities, some argue that the rules cannot be one-sided against 
nonincumbents so as to amount to a backdoor right of first 
refusal.\277\ LS Power states, for example, that an entity that is 
financially qualified but is deemed to not be technically qualified 
should be permitted to partner with a technically qualified entity. 
Pattern Transmission states that, if a transmission provider determines 
that a project developer does not meet the qualification criteria, it 
should be required to provide the rationale for that determination to 
the applicant in writing so that any future attempt to meet the 
qualification criteria will be better informed. Other commenters 
express concern that the qualification criteria not be so onerous that 
they cannot be readily satisfied by existing transmission owners.\278\ 
APPA and Transmission Access Policy Group suggest that qualification 
criteria be crafted in a way that supports a variety of ownership 
arrangements, including joint ownership by public power systems.
---------------------------------------------------------------------------

    \277\ E.g., Anbaric and PowerBridge; LS Power; and Pattern 
Transmission; and Primary Power. Anbaric and PowerBridge cite to New 
England Indep. Transmission Co., L.L.C., 118 FERC ] 61,127 (2007).
    \278\ E.g., New York ISO; Transmission Agency of Northern 
California; California Commissions; Arizona Public Service Company; 
Northeast Utilities; and SPP.
---------------------------------------------------------------------------

    299. Some commenters oppose or otherwise raise concerns regarding 
the use of qualification criteria to determine eligibility to propose 
projects in the regional transmission planning process.\279\ PPL 
Companies state that RTOs do not have experience in evaluating the 
capabilities of nonincumbent transmission developers and that both the 
establishment and application of the criteria are likely to result in 
disputes and litigation. Indianapolis Power & Light states that, 
because incumbents have existing state obligations to serve, incumbent 
transmission owners should be deemed to meet any qualification criteria 
without any additional showing. Pacific Gas & Electric similarly argues 
that qualification criteria should take into consideration the ability 
of incumbent transmission owners to provide cost and efficiency 
benefits that may not be available from a single-project transmission 
owner, such as in obtaining siting and permitting approvals.
---------------------------------------------------------------------------

    \279\ E.g., PPL Companies; Indianapolis Power & Light; and 
Pacific Gas & Electric.
---------------------------------------------------------------------------

    300. Several commenters address the use of a form to obtain 
information from prospective transmission developers as to projects 
submitted for evaluation in the regional transmission planning 
process.\280\ LS Power asks the Commission to set forth the requisite 
project information required in such a form, subject to any region or 
transmission provider obtaining Commission approval to modify such 
requirements. California ISO suggests that, notwithstanding its general 
opposition to the elimination of federal rights of first refusal, any 
requirements imposed on project developers to submit information in 
support of a proposal should include the submission of sufficient study 
results evidencing a prima facie case that the project is needed. 
Exelon contends that project proposals should be required to include 
technical analyses demonstrating that they meet the region's 
requirements and that a developer should not be provided with any 
priority rights without such supporting documentation. Transmission 
Agency of Northern California asks the Commission to clarify that the 
evaluation form should be developed in the regional transmission 
planning process and that a project developer would not be required to 
submit separate and distinct forms to each public utility transmission 
provider that participates in a given regional transmission planning 
process.
---------------------------------------------------------------------------

    \280\ E.g., California ISO; Edison Electric Institute; LS Power; 
and Transmission Agency of Northern California.
---------------------------------------------------------------------------

    301. LS Power supports the proposal for public utility transmission 
providers to identify a specified date by which to submit proposed 
transmission projects, generally arguing that a submission deadline 
would promote orderly and fair consideration of projects.\281\ Others 
oppose the proposal, generally arguing that existing transmission 
planning processes are iterative in nature.\282\ For example, New 
England States Committee on Electricity states that establishing such a 
deadline could have the unintended consequence of discouraging 
discussion of emerging needs and alternative ways to meet them. It 
suggests that the Commission leave such procedural matters to the 
regions for consideration. Some commenters express concern that the 
Commission's proposal invites gaming, creating an incentive to propose 
a host of projects so that individual entities may obtain their own 
time-based rights of first refusal to develop proposals.\283\ LS Power 
disagrees in reply, arguing that such concerns could be addressed by 
requiring transmission developers to post a reasonable deposit, which 
could be based in part on the total estimated cost to develop the 
annual plan and the number of transmission projects evaluated in the 
plan, to avoid new projects being filed in an effort to prevent others 
from developing them.
---------------------------------------------------------------------------

    \281\ E.g., LS Power.
    \282\ E.g., Edison Electric Institute; California ISO; ISO New 
England; NEPOOL; Northeast Utilities; New England States Committee 
on Electricity; and National Rural Electric Coops.
    \283\ E.g., Edison Electric Institute; Exelon; MISO Transmission 
Owners; California ISO; ISO New England; NEPOOL; Northeast 
Utilities; New England States Committee on Electricity; and National 
Rural Electric Coops.

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

[[Page 49894]]

c. Comments Regarding Project Evaluation and Selection
    302. Commenters also address the remaining four aspects of the 
Commission's proposed framework for eliminating federal rights of first 
refusal, relating to mechanisms to evaluate, select and recover the 
costs of projects proposed in the regional transmission planning 
process. Most commenters support the proposal that each public utility 
transmission provider participate in a regional transmission planning 
process that evaluates the proposals submitted through a transparent 
and not unduly discriminatory or preferential process.\284\ For 
example, Duke and National Grid state that existing regional 
transmission planning processes already evaluate proposed projects 
through an open process described in the relevant public utility 
transmission providers' OATTs.
---------------------------------------------------------------------------

    \284\ E.g., Federal Trade Commission; PUC of Nevada; 
Massachusetts Departments; New England States Committee on 
Electricity; California Commissions; Connecticut & Rhode Island 
Commissions; LS Power; FirstWind; National Grid; Western Independent 
Transmission Group; Transmission Agency of Northern California; 
Northern California Power Agency; Pattern Transmission; American 
Transmission; California State Water Project; Anbaric and 
PowerBridge; PPL Companies; Green Energy and 21st Century; Duke; and 
Old Dominion.
---------------------------------------------------------------------------

    303. Several commenters suggest that regional flexibility is needed 
when determining the procedures by which transmission projects are 
evaluated and selected.\285\ For example, Connecticut & Rhode Island 
Commissions and Massachusetts Departments state that ensuring equal 
rights and obligations of incumbent and nonincumbent transmission 
developers would raise a number of questions that will need to be 
addressed through the stakeholder process, including how projects and 
developers are selected, how non-transmission alternatives will be 
evaluated, how rights of way are negotiated, and how to address cost 
overruns. They state that the Final Rule should recognize the many 
issues that would arise following the proposed change and allow the 
stakeholder process flexibility to identify and develop solutions to 
these challenges. Western Independent Transmission Group suggests the 
use of an independent third-party observer may be necessary to oversee 
the evaluation and selection of competing transmission projects to give 
market participants and the Commission assurance that the process is 
fairly and efficiently managed.
---------------------------------------------------------------------------

    \285\ E.g., Connecticut & Rhode Island Commissions; National 
Grid; New England States Committee on Electricity; KCP&L Edison 
Electric Institute; and WIRES.
---------------------------------------------------------------------------

    304. A number of commenters characterize the Commission's proposal 
as implementing a sponsorship model that conflicts with the 
collaborative nature of current transmission planning processes.\286\ 
North Dakota & South Dakota Commissions state that the sponsorship 
paradigm will turn current transmission planning processes into an 
unmanageable free for all, undermining the effective evaluation of 
potential transmission solutions. Integrys and Southern Companies 
contends that sponsorship rights may do more harm than good and will 
defeat the objective of an orderly and systematic planning and 
construction process, increasing disputes, creating queuing problems, 
disrupting existing OATT processes, harming reliability, and resulting 
in a loss of flexibility. Baltimore Gas & Electric argues that those 
that want to claim sponsorship rights also do not want to provide the 
RTO with discretion to deny their claim and that such entities could 
tie up transmission construction as long as they want until they ensure 
they are the builders. National Rural Electric Coops suggest that the 
Commission convene a technical conference to address complex 
implementation issues.
---------------------------------------------------------------------------

    \286\ E.g., Baltimore Gas & Electric; Edison Electric Institute; 
Integrys; MISO Transmission Owners; North Dakota & South Dakota 
Commissions; PSEG Companies; PPL Companies; and Southern Companies.
---------------------------------------------------------------------------

    305. Southern Companies also question how transmission proposals 
submitted by nonincumbent transmission providers should be evaluated in 
the regional transmission planning process. Southern Companies state 
that the Proposed Rule could be viewed as permitting any qualified 
entity to sponsor projects at the regional level, where a ``black box'' 
evaluation process would be applied to determine the ``winners.'' 
Southern Companies suggest that nonincumbent transmission developers be 
treated similarly to the integration of merchant generation so that 
state law would not be undermined. That is, Southern Companies 
recommend that, if a nonincumbent transmission developer has a proposal 
that the incumbent utility believes to be cost-effective and reliable, 
that developer would have to join with Southern Companies to petition 
the relevant state regulatory authorities for approval for construction 
and rate recovery.
    306. Some commenters argue that the Commission should not require 
development of mechanisms that provide construction rights to 
nonincumbent transmission developers seeking to develop projects solely 
within an existing transmission owner's footprint or that use rights-
of-way held by existing transmission owners.\287\ For example, Edison 
Electric Institute asks the Commission to clarify that only an 
incumbent transmission owner should be allowed to propose local, single 
system facilities that are simply rolled up into a regional plan, as 
well as upgrades or modifications to facilities owned by an incumbent 
transmission provider, including reconductoring, tower change outs, 
additional facilities in existing substations, facilities in a right of 
way owned by the incumbent, and new substations cut into existing 
lines. It argues that allowing nonincumbent transmission developers to 
perform upgrades to an incumbent transmission owner's transmission 
facilities could delay upgrades necessary to maintain system 
reliability and increase the costs of constructing and maintaining such 
transmission facilities. PJM agrees, arguing that existing transmission 
owners are in the best position to use their own resources. Imperial 
Irrigation District expresses concern regarding the potential impact of 
the Proposed Rule on contractual rights in existing joint ownership and 
operation agreements governing existing facilities. LS Power cautions 
that, to the extent the Commission provides for the retention of 
federal rights of first refusal for existing facilities, the 
limitations of such an exclusion must be clearly described in the OATT.
---------------------------------------------------------------------------

    \287\ E.g., Anbaric and PowerBridge; California Municipal 
Utilities; Edison Electric Institute; Exelon; Imperial Irrigation 
District; LS Power; PJM; and Southern California Edison.
---------------------------------------------------------------------------

    307. A number of commenters suggest that the Commission modify the 
proposal for sponsors of proposed transmission projects to retain the 
right to build projects of a similar scope for a defined period of 
time.\288\ Bonneville Power states that this proposed reform creates 
the potential for increased litigation to determine whether an 
incumbent transmission owner's project is substantially similar to a 
previously proposed non-incumbent transmission developer's project. 
Xcel and others \289\ contend that selection among similar projects for 
inclusion in the regional transmission plan is inherently subjective 
and, therefore, determining whether a project is a modification of a 
previously proposed project or sufficiently different to be considered 
a

[[Page 49895]]

new project would be difficult. National Rural Electric Coops ask the 
Commission to clarify that the proposal does not prevent an incumbent 
transmission provider from making minor modifications to a competing 
transmission project to better meet the needs of the participants in 
the process.
---------------------------------------------------------------------------

    \288\ E.g., California Municipal Utilities; Exelon; LS Power; 
Northern Tier Transmission Group; and Transmission Agency of 
Northern California.
    \289\ E.g., Duke; PPL Companies; MidAmerican; and North Dakota 
and South Dakota Commissions.
---------------------------------------------------------------------------

    308. Some commenters argue that the Commission should implement 
competitive bidding processes for selecting project developers instead 
of relying on a sponsor-based mechanism for determining construction 
rights.\290\ For example, Transmission Access Policy Study Group 
contends that competitive bidding yields lower costs to consumers, 
includes mechanisms to limit cost overruns, and restricts the ability 
of winning bidders to transfer construction rights. It suggests that 
any competitive bidding process employed by the Commission favor 
projects that are jointly owned. California ISO states that its 
competitive solicitation framework for economic and public policy 
transmission projects meets the Commission's goals of ensuring 
development of cost-effective transmission facilities, providing 
ratepayer benefits, optimizing participation in the transmission 
planning process, and providing opportunities for nonincumbent 
transmission developers, although California ISO opposes the use of 
competitive solicitations for reliability projects. Edison Electric 
Institute and Ad Hoc Coalition of Southeastern Utilities contend that 
mandating competitive bidding would undermine existing transmission 
planning processes and allow nonincumbent developers to bid selectively 
only for advantageous projects. Pattern Transmission responds that such 
``cherry picking'' concerns can be addressed through properly 
structured competitive bidding processes.
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    \290\ E.g., Transmission Access Policy Study Group; Pattern 
Transmission; and Indianapolis Power & Light.
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    309. With regard to the period for which development rights could 
be retained, LS Power recommends that a transmission developer that 
sponsors a transmission project be permitted to retain the right to 
build or build and own the transmission project for a minimum of five 
years, while California Municipal Utilities suggest a period of two 
years. Others express concern with the impact of the Commission's 
proposal, generally arguing such a policy would encourage entities to 
submit multiple proposals to maximize potential development 
opportunities.\291\ For example, National Rural Electric Coops suggest 
this would create an approach to transmission planning in which 
immutable transmission proposals compete against each other in a form 
of baseball arbitration (in which the arbitrator must pick one side's 
offer without modification), even if minor changes to one or more of 
the proposals would allow them to better meet the needs of consumers in 
the region. LS Power and Transmission Agency of Northern California 
disagree, arguing that objective rules can be established to identify 
when a modified project is the functional equivalent of a sponsored 
project.
---------------------------------------------------------------------------

    \291\ E.g., Connecticut & Rhode Island Commissions; Indianapolis 
Power & Light; Indicated PJM Transmission Owners; Massachusetts 
Departments; National Rural Electric Coops; and Oklahoma Gas & 
Electric.
---------------------------------------------------------------------------

    310. Arizona Corporation Commission stresses that, in all cases, 
proposed transmission projects resubmitted for consideration must be 
freshly evaluated in each transmission planning cycle so that projects 
address current needs and requirements. Northern Tier Transmission 
Group recommends that a project that is not selected in the regional 
transmission plan must have similar performance characteristics and 
costs when resubmitted for consideration. California Municipal 
Utilities argue that a project sponsor should not receive a priority 
right during resubmission if the transmission project sponsor is only 
interested in selling that right.
    311. Some commenters seek clarification of the obligations that 
would be imposed on nonincumbent transmission developers as a result of 
selection of its project for construction.\292\ MISO Transmission 
Owners and New York Transmission Owners contend that, if the proposed 
reforms are implemented, the Commission should make clear that a 
nonincumbent transmission developer's right to participate in the 
transmission planning process must be accompanied by an obligation that 
it satisfy all the requirements expected of transmission developers in 
the regional transmission planning process. MISO Transmission Owners 
state that this clarification is particularly important because 
institutional investors may seek to invest in transmission facilities 
to earn the stable return on their investment that a rate-regulated 
business would provide but have no intention to become public utilities 
once the facility is placed into service and put under the functional 
control of an RTO. Minnesota PUC and Minnesota Office of Energy 
Security suggest that winning transmission projects, regardless of 
ownership type, should be subject to regulatory scrutiny to make sure 
that when completed the transmission project fulfills the needs 
initially ascribed to it and that the transmission project costs are 
consistent with the cost levels initially proposed.
---------------------------------------------------------------------------

    \292\ E.g., New York Transmission Owners; Edison Electric 
Institute; MISO Transmission Owners; Southern Companies; and 
Transmission Agency of Northern California.
---------------------------------------------------------------------------

    312. Finally, commenters also address whether the selection of a 
transmission facility proposed by a nonincumbent transmission developer 
for inclusion in the regional transmission plan should be eligible for 
regional cost allocation.\293\ Massachusetts Departments and 
Connecticut & Rhode Island Commissions agree with the basic principle, 
but argue that recovery should be determined by project criteria and 
not on the basis of the type of developer proposing the project. SPP 
and Old Dominion support the proposal, provided that the nonincumbent 
transmission developer is subject to the same responsibilities as 
incumbent transmission owners pursuant to the transmission planning 
requirements. MISO Transmission Owners raise the possibility that a 
nonincumbent project selected in the regional transmission planning 
process may be rejected by a state agency in favor of an incumbent 
transmission owner and question whether under this scenario an 
incumbent transmission owner would be required to build the project but 
would not be eligible for regional cost recovery. Ad Hoc Coalition of 
Southeastern Utilities assert that the proposal may conflict with 
state-based mandates, explaining that the majority of transmission 
costs in the Southeast are incurred to serve native load, and are 
included in rates established pursuant to state or local regulation.
---------------------------------------------------------------------------

    \293\ E.g., Ad Hoc Coalition of Southeastern Utilities; 
FirstEnergy Service Company; MISO Transmission Owners; New York ISO; 
Old Dominion; and SPP.
---------------------------------------------------------------------------

d. Commission Determination
    313. The Commission directs public utility transmission providers, 
subject to the modifications to the Proposed Rule discussed below and 
subject to the framework discussed and adopted below, 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

[[Page 49896]]

regional transmission plan for purposes of cost allocation.
    314. As explained in the preceding sections, the elimination of 
federal rights of first refusal from Commission-jurisdictional tariffs 
and agreements is necessary and appropriate to ensure that rates for 
jurisdictional services are just and reasonable. However, based on the 
comments received in response to the Proposed Rule, the Commission 
modifies the specific requirements placed on public utility 
transmission providers to implement the proposal and provides 
clarification regarding those requirements to facilitate 
compliance.\294\
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    \294\ The requirements adopted here apply only to public utility 
transmission providers that have provisions in their tariffs or 
other Commission-jurisdictional agreements granting a federal right 
of first refusal that is inconsistent with the requirements of this 
Final Rule. If no such provisions are contained in a public utility 
transmission provider's tariff or other Commission-jurisdictional 
agreement, it should state so in its compliance filing.
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    315. To place our actions in context, the Commission reiterates the 
existing requirements of Order No. 890 as implemented by public utility 
transmission providers. As noted by commenters, Order No. 890 already 
requires public utility transmission providers to have in place 
processes for evaluating the merits of proposed transmission solutions 
offered by potential developers.\295\ To ensure comparable treatment of 
all resources, the Commission has required public utility transmission 
providers to include in their OATTs language that identifies how they 
will evaluate and select among competing solutions and resources.\296\ 
This includes the identification of the criteria by which the public 
utility transmission provider will evaluate the relative economics and 
effectiveness of performance for each alternative offered for 
consideration.\297\ Given that the regions already have processes in 
place to evaluate competing transmission projects in their transmission 
planning process, the fundamental question raised in the Proposed Rule 
is whether additional requirements are needed to ensure that these 
processes are not adversely affected by federal rights of first 
refusal. The Commission concludes that such requirements are necessary 
and, accordingly, adopts the framework set forth in the Proposed Rule 
with modification.
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    \295\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 494; 
Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 215-16.
    \296\ See, e.g., New York Independent System Operator, Inc., 129 
FERC ] 61,044 at P 35.
    \297\ Id.
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    316. Opponents of the Commission's proposed elimination of federal 
rights of first refusal argue that this framework represents a 
fundamental shift in the way that transmission is planned in existing 
regional processes. These commenters contend that characterizing 
existing transmission owners as developers of sponsored transmission 
facilities that are to be evaluated on a comparable basis to proposals 
submitted by nonincumbent transmission developers transforms, in their 
view, the collaborative and iterative transmission planning process 
into a sponsorship-driven competition for new investment opportunities. 
As we explain elsewhere, the reforms adopted in this Final Rule build 
upon the requirements of Order No. 890 with respect to transmission 
planning. Public utility transmission providers already have put in 
place mechanisms to provide for comparative evaluation of competing 
solutions. We recognize that the mechanisms for evaluating proposals 
under this Final Rule will have greater implications because we are 
also requiring a just and reasonable and not unduly discriminatory 
process to grant to a transmission developer the ability to use the 
regional cost allocation method associated with each transmission 
facility selected in the regional transmission plan for purposes of 
cost allocation. However, we disagree that the reforms in the Proposed 
Rule, as modified herein, will make the planning process unmanageable, 
as suggested by some commenters.
    317. Some of the concerns expressed by commenters appear to be 
driven by the phrasing used in the Proposed Rule to present the 
framework for removing federal rights of first refusal. There, the 
Commission stated that both incumbent and nonincumbent transmission 
developers should share similar benefits and obligations, including the 
right, consistent with state or local laws or regulations, to construct 
and own a transmission facility that it sponsors in a regional 
transmission planning process and that is selected in the regional 
transmission plan.\298\ The Commission's focus in the Proposed Rule on 
sponsorship of proposed transmission facilities, whether by incumbent 
transmission providers or nonincumbent transmission developers, appears 
to have led many commenters to conclude that every transmission 
facility being planned by an incumbent transmission provider is, in 
effect, sponsored by that entity and, therefore, could no longer be 
subject to a federal right of first refusal. The Commission clarifies 
that this was not the intent of the Proposed Rule, nor is it the intent 
of the requirements adopted in this Final Rule.
---------------------------------------------------------------------------

    \298\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 93.
---------------------------------------------------------------------------

    318. The Commission's focus here is 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.\299\ As 
Edison Electric Institute notes, in those regions relying on ``bottom 
up'' local transmission planning, a transmission facility that is in a 
public utility transmission provider's local transmission plan might be 
``rolled-up'' and listed in a regional transmission plan to facilitate 
analysis at the regional level. However, the transmission facility from 
the local transmission plan might not have been proposed in the 
regional transmission planning process and might not have been selected 
in the regional transmission plan for purposes of cost allocation by 
going through an analysis in the regional transmission planning 
process. The Commission does not, in this Final Rule, require removal 
from Commission-jurisdictional tariffs and agreements of a federal 
right of first refusal as applicable to a local transmission facility, 
as that term is defined herein.\300\
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    \299\ In order for a transmission facility to be eligible for 
the regional cost allocation methods, the region must select the 
transmission facility in the regional transmission plan for purposes 
of cost allocation. For those facilities not seeking cost 
allocation, the region may nonetheless have those transmission 
facilities in its regional transmission plan for information or 
other purposes, and then having such a facility in the plan would 
not trigger regional cost allocation.
    \300\ See definition supra section II.D of this Final Rule.
---------------------------------------------------------------------------

    319. In addition, the Proposed Rule emphasized that our 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 or not an upgrade has been selected in the regional 
transmission plan for purposes of cost allocation.\301\ In other words, 
an incumbent transmission provider would be permitted to maintain a 
federal right of first refusal for upgrades to its own transmission 
facilities. In addition, the Commission affirms that proposal here, and 
in response to commenters adds that our reforms are not intended to 
alter an incumbent transmission provider's use and control of its 
existing rights-of-way. That is, this Final Rule does not remove or 
limit any right an incumbent may have to build, own and

[[Page 49897]]

recover costs for upgrades to the facilities owned by an incumbent, nor 
does this Final Rule grant or deny transmission developers the ability 
to use rights-of-way held by other entities, even if transmission 
facilities associated with such upgrades or uses of existing rights-of-
way are selected in the regional transmission plan for purposes of cost 
allocation. The retention, modification, or transfer of rights-of-way 
remain subject to relevant law or regulation granting the rights-of-
way.
---------------------------------------------------------------------------

    \301\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 97.
---------------------------------------------------------------------------

    320. Through the reforms to regional planning required in this 
Final Rule, the Commission is seeking to ensure that a robust process 
is in place to identify and consider regional solutions to regional 
needs, whether initially identified through ``top down'' or ``bottom 
up'' transmission planning processes. Combined with the cost allocation 
and other reforms adopted in this Final Rule, implementation of this 
framework to remove federal rights of first refusal will address 
disincentives that may be impeding participation by nonincumbent 
transmission developers in the regional transmission planning process. 
The extent to which any existing regional transmission planning process 
must be changed to implement the framework set forth below will depend 
on the mechanisms used by the region to evaluate competing transmission 
projects and developers.
    321. For example, this Final Rule permits a region to use or retain 
an existing mechanism that relies on a competitive solicitation to 
identify preferred solutions to regional transmission needs, and such 
an existing process may require little or no modification to comply 
with the framework adopted in this Final Rule.\302\ In regions relying 
primarily on ``top down'' mechanisms pursuant to which regional 
planners independently identify regional needs and more efficient and 
cost-effective solutions, existing procedures that allow for 
stakeholders to offer potential solutions for consideration could 
provide a foundation for implementing the framework below. In other 
regions emphasizing the development of local transmission plans prior 
to analysis at the regional level of alternative solutions, additional 
procedures may be required to distinguish between those transmission 
facilities that are proposed to be selected in the regional 
transmission plan for purposes of cost allocation and those that are 
merely ``rolled up'' for other purposes.
---------------------------------------------------------------------------

    \302\ For example, the Commission has found that competitive 
solicitation processes can provide greater potential opportunities 
for independent transmission developers to build new transmission 
facilities. See, e.g., California Indep. Sys. Operator, 133 FERC ] 
61,224 (2010). However, the Commission declines to adopt commenter 
suggestions to mandate a competitive bidding process for selecting 
project developers. While the Commission agrees that a competitive 
process can provide benefits to consumers, we continue to allow 
public utility transmission providers within each region to 
determine for themselves, in consultations with stakeholders, what 
mechanisms are most appropriate to evaluate and select potential 
transmission solutions to regional needs.
---------------------------------------------------------------------------

    322. The Commission concludes that the framework adopted below 
provides sufficient flexibility for public utility transmission 
providers in each region to determine, in the first instance, how best 
to address the removal of federal rights of first refusal from 
Commission-jurisdictional tariffs and agreements. Because we are 
allowing for regional flexibility and encouraging stakeholders to 
participate fully in the implementation of this framework by public 
utility transmission providers, we decline to decide in this Final Rule 
to convene a technical conference to further explore issues related to 
federal rights of first refusal, as suggested by some commenters. With 
the foregoing background in mind, the Commission turns to the specific 
requirements of this framework below.
i. Qualification Criteria To Submit a Transmission Project for 
Selection in the Regional Transmission Plan for Purposes of Cost 
Allocation
    323. First, the Commission requires each public utility 
transmission provider to revise its OATT to demonstrate that the 
regional transmission planning process in which it participates has 
established 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, whether 
that entity is an incumbent transmission provider or a nonincumbent 
transmission developer. These criteria must not be unduly 
discriminatory or preferential. The qualification 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.
    324. The Commission agrees with commenters that qualification 
criteria are necessary, and that adoption of one-size-fits-all 
requirements would not be appropriate. It is important that each 
transmission planning region have the flexibility to formulate 
qualification criteria that best fit its transmission planning 
processes and addresses the particular needs of the region. Such 
criteria could address a range of issues raised by commenters, such as 
commitments to be responsible for operation and maintenance of a 
transmission facility.\303\ The Commission stresses, however, that 
appropriate qualification criteria should be fair and not unreasonably 
stringent when applied to either the incumbent transmission provider or 
nonincumbent transmission developers. The qualification criteria should 
allow for the possibility that an existing public utility transmission 
provider already satisfies the criteria and should allow any 
transmission developer the opportunity to remedy any deficiency. Within 
these general parameters, we leave it to each region to develop 
qualification criteria that are workable for the region, including 
procedures for timely notifying transmission developers of whether they 
satisfy the region's qualification criteria and opportunities to 
mitigate any deficiencies.\304\
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    \303\ The Commission notes, however, that nothing in the 
qualification requirement of this Final Rule precludes a 
transmission developer from entering into voluntary arrangements 
with third parties, including any interested incumbent transmission 
provider, to operate and maintain a transmission facility. 
Similarly, nothing this Final Rule creates an obligation for an 
incumbent transmission provider to operate and maintain a 
transmission facility developed by another transmission developer. 
Additionally, nothing in the qualifications requirement of this 
Final Rule is intended to change any existing RTO or ISO procedure 
or practice regarding the operation of one or more existing 
transmission facilities.
    \304\ To be clear, the qualification criteria required herein 
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.
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ii. Submission of Proposals for Selection in the Regional Transmission 
Plan for Purposes of Cost Allocation
    325. Second, the Commission requires that each public utility 
transmission provider revise its OATT to identify: (a) The information 
that must be submitted by a prospective transmission developer in 
support of a transmission project it proposes in the regional 
transmission planning process; and (b) the date by which such 
information must be submitted to be considered in a given transmission 
planning cycle. The Commission declines to adopt the proposal to 
require a specific form to be developed for the purpose of submitting 
this information, given that the data to be submitted may not be easily 
reduced

[[Page 49898]]

to entries on a form. To ensure consistency in the region, however, the 
Commission requires each public utility transmission provider that has 
its own OATT to have in that OATT the same information requirements as 
other public utility transmission providers in the same transmission 
planning region, as requested by Transmission Agency of Northern 
California.
    326. These information requirements must identify in sufficient 
detail the information necessary to allow a proposed transmission 
project to be evaluated in the regional transmission planning process 
on a basis comparable to other transmission projects that are proposed 
in the regional transmission planning process. They may require, for 
example, relevant engineering studies and cost analyses and may request 
other reports or information from the transmission developer that are 
needed to facilitate evaluation of the transmission project in the 
regional transmission planning process. Beyond these minimum 
requirements, the Commission provides each region with discretion to 
identify the information to be required, so long as such requirements 
are fair and not so cumbersome as to effectively prohibit transmission 
developers from proposing transmission projects, yet not so relaxed 
that they allow for relatively unsupported proposals. Whether the 
region wishes to require prima facie showings of need for a project, as 
suggested by the California ISO, should be addressed in the first 
instance by public utility transmission providers in consultation with 
stakeholders within the region. The Commission will review the 
resulting information requirements on compliance and provide further 
guidance at that time, if necessary.
    327. The Commission disagrees that requiring the identification of 
a date by which information must be submitted for consideration in a 
given transmission planning cycle undermines the iterative nature of 
transmission planning or amounts to creation of a time-based federal 
right of first refusal. Without some reasonable limitation on the 
submission of new information, public utility transmission providers 
would never be able to complete the analysis needed to complete their 
region's transmission plan. However, each region may determine for 
itself what deadline is appropriate, including potentially the use of 
rolling or flexible dates to reflect the iterative nature of their 
transmission planning processes. Given our decision to eliminate the 
proposed ongoing right to develop previously-sponsored transmission 
projects, the Commission believes it is not necessary to require here 
additional procedural protections such as the posting of deposits, as 
suggested by LS Power. To the extent stakeholders in a particular 
region believe such procedures have merit, they may consider them 
during the development of OATT proposals that comply with the 
requirement of this Final Rule.
iii. Evaluation of Proposals for Selection in the Regional Transmission 
Plan for Purposes of Cost Allocation
    328. Third, the Commission requires 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. This process must comply with the Order 
No. 890 transmission planning principles, ensuring transparency, and 
the opportunity for stakeholder coordination. 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. In complying with this requirement, the Commission 
encourages public utility transmission providers to build on existing 
regional transmission planning processes that, consistent with Order 
Nos. 890 and 890-A, already set forth the criteria by which the public 
utility transmission provider evaluates the relative economics and 
effectiveness of performance for alternative solutions offered during 
the transmission planning process.
    329. In light of comments received in response to the Proposed 
Rule, we also 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. We appreciate that there are many sources of delay 
that could affect the timing of transmission development, and do not 
intend to require constant reevaluation of delays that do not 
materially affect the ability of an incumbent transmission provider to 
meet its reliability needs or service obligations. Our 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. Under 
such circumstances, an incumbent transmission provider must have the 
ability to propose solutions that it would implement within its retail 
distribution service territory or footprint that will enable it to meet 
its reliability needs or service obligations. If such other solution is 
a transmission facility, public utility transmission providers in the 
regional transmission planning process should evaluate the proposed 
solution for possible selection in the regional transmission planning 
process for purposes of cost allocation. As we have explained elsewhere 
in this Final Rule,\305\ nothing herein restricts an incumbent 
transmission provider from developing a local transmission solution 
that is not eligible for regional cost allocation to meet its 
reliability needs or service obligations in its own retail distribution 
service territory or footprint.
---------------------------------------------------------------------------

    \305\ See supra P 256.
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    330. The Commission appreciates that the selection of any 
transmission facility in the regional transmission plan for purposes of 
cost allocation requires the careful weighing of data and analysis 
specific to each transmission facility and, in some instances, may be 
difficult or contentious. While the Commission appreciates the 
challenges presented by such an evaluation, the requirement to engage 
in a comparative analysis of proposed solutions to regional needs has 
been in place since Order No. 890. The Commission encourages public 
utility transmission providers to consider ways to minimize disputes, 
such as through additional transparency mechanisms, as they identify 
enhancements to regional transmission planning processes necessary to 
comply with this Final Rule.\306\ The Commission declines, however, to 
mandate the use of independent third-party observers, as suggested by 
Western Independent Transmission Group. To the extent public utility 
transmission

[[Page 49899]]

providers in consultation with other stakeholders in a region wish, 
they may propose to use an independent third-party observer and we will 
review any such proposal on compliance.
---------------------------------------------------------------------------

    \306\ Additionally, as described in section III.A, the 
requirements of the dispute resolution principle order of Order No. 
890 apply to the regional transmission planning process as reformed 
by this Final Rule.
---------------------------------------------------------------------------

    331. By requiring the evaluation of proposed transmission solutions 
in the regional transmission planning process, the Commission is not 
dictating that any particular proposals be accepted or that selected 
transmission facilities be constructed. Similar to the planning 
requirements of Order No. 890, the Commission requires the 
establishment of processes to evaluate potential solutions to regional 
transmission needs, with the input of interested parties and 
stakeholders. Whether or not public utility transmission providers 
within a region select a transmission facility in the regional 
transmission plan for purposes of cost allocation will depend in part 
on their combined view of whether the transmission facility is an 
efficient or cost-effective solution to their needs.\307\ Moreover, the 
Commission anticipates that the processes for evaluating whether to 
select a proposed transmission facility in the regional transmission 
plan for purposes of cost allocation will vary from region to region, 
just as other aspects of the regional transmission planning processes 
may vary.
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    \307\ As noted above, for one solution to be chosen over another 
in the regional transmission planning process, there should be an 
evaluation of the relative efficiency and cost-effectiveness of each 
solution. If a nonincumbent transmission developer is unable to 
demonstrate that its proposal is the most efficient or cost-
effective, given all aspects of its proposal, then it is unlikely to 
be selected as the preferred transmission solution within the 
regional transmission planning process for purposes of cost 
allocation.
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iv. Cost Allocation for Projects Selected in the Regional Transmission 
Plan for Purposes of Cost Allocation
    332. The Commission also requires 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. More specifically, each public 
utility transmission provider must participate in a regional 
transmission planning process that provides that the nonincumbent 
developer has an opportunity comparable to that of an incumbent 
transmission developer to allocate the cost of such transmission 
facility through a regional cost allocation method or methods. As 
explained further in section IV.C, the cost of a transmission facility 
that is not selected in a regional transmission plan for purposes of 
cost allocation, whether proposed by an incumbent or by a nonincumbent 
transmission provider, may not be recovered through a transmission 
planning region's cost allocation method or methods.
    333. In the Proposed Rule, the Commission acknowledged that a 
proposed transmission project can be modified in the regional 
transmission planning process as needs and potential solutions are 
analyzed and, therefore, sought comment on whether to require a 
mechanism to identify the most similar project to one initially 
proposed to determine which developer should have the right to 
construct and own the facility. Although the Commission raised this 
issue in the context of processes of construction rights, similar 
issues are raised regarding the selection of a transmission facility in 
the regional transmission plan for purposes of cost allocation.
    334. In light of the comments received in response to this aspect 
of the Proposed Rule, we are concerned that the proposed requirement to 
identify the most similar project to one initially proposed could 
conflict with the way potential solutions are evaluated and selected in 
some regions. For example, a requirement to identify proposals that are 
``most similar'' to transmission projects in the regional transmission 
plan may be meaningless in a region that relies on market proposals or 
competitive solicitations to identify solutions to the region's needs. 
In other regions that rely on voluntary construction decisions for 
transmission facilities in a regional transmission plan, the linking of 
rights to construct to a determination of similarity may be 
meaningless. As discussed in the next section, in response to concerns 
such as these, we have decided not to adopt the proposal that would 
give a sponsor the federal right to construct and own a transmission 
facility it sponsored consistent with state or local laws or 
regulations. Given this change, we do not adopt the proposal to require 
a mechanism to identify the most similar project to one initially 
proposed to determine which developer should have the right to 
construct and own the facility.
    335. Instead, we adopt and clarify the requirement that a 
nonincumbent transmission developer of a transmission facility selected 
in the regional transmission plan for purposes of cost allocation have 
the same opportunity as an incumbent transmission developer to allocate 
the cost of such transmission facilities through a regional cost 
allocation method or methods. We require that each public utility 
transmission provider must participate in a regional transmission 
planning process that makes each transmission facility selected in the 
regional transmission plan for purposes of regional cost allocation 
eligible for such cost allocation. In other words, eligibility for 
regional cost allocation is tied to the transmission facility's 
selection in the regional transmission plan for purposes of cost 
allocation and not to a specific sponsor.
    336. We also require that public utility transmission providers in 
a region establish, in consultation with stakeholders, procedures to 
ensure that all projects are eligible to be considered for selection in 
the regional transmission plan for purposes of cost allocation. This 
mechanism could be, for example, a non-discriminatory competitive 
bidding process. The mechanism a regional planning process implements 
could also allow the sponsor of a transmission project selected in the 
regional transmission plan for purposes of cost allocation to use the 
regional cost allocation method associated with the transmission 
project. In that case, however, the regional transmission planning 
process would also need to have a fair and not unduly discriminatory 
mechanism to grant to an incumbent transmission provider or 
nonincumbent transmission developer the right to use the regional cost 
allocation method for unsponsored transmission facilities selected in 
the regional plan for purposes of cost allocation. There may also be 
other mechanisms, or combinations of mechanisms, that may comply with 
our requirements.
    337. The Commission declines commenter requests to further define 
the particular obligations and responsibilities that may flow from 
selection of a nonincumbent transmission developer's proposal in the 
regional transmission plan for purposes of cost allocation. Nothing in 
this Final Rule is intended to change or limit any obligations that 
would apply to a nonincumbent transmission developer under state or 
local laws or under RTO or ISO agreements.
v. Rights To Construct and Ongoing Sponsorship
    338. The Proposed Rule also sought comment on whether to include 
two additional features in a framework to implement the elimination of 
federal rights of first refusal: Whether to require public utility 
transmission providers to revise their OATTs to contain a regional 
transmission planning process that

[[Page 49900]]

provides a right to construct and own a transmission facility; and, 
whether 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.\308\ The Commission declines to 
adopt these aspects of the Proposed Rule.
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    \308\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 95.
---------------------------------------------------------------------------

    339. In the preceding sections, the Commission adopted a framework 
in which, upon selection of a transmission facility in a regional 
transmission plan for purposes of cost allocation, the developer of 
that transmission facility (whether incumbent or nonincumbent) will 
have the ability to rely on the relevant cost allocation method or 
methods within the region should it desire to move forward with its 
transmission project. Nothing in this Final Rule preempts or limits any 
obligations or requirements that a nonincumbent transmission developer 
may be subject to under state or local laws or regulations or under RTO 
or ISO agreements.
    340. With regard to ongoing sponsorship rights, the Commission 
concludes on balance that granting transmission developers an ongoing 
right to build sponsored transmission projects could adversely impact 
the transmission planning process, potentially leading to transmission 
developers submitting a multitude of possible transmission projects 
simply to acquire future development rights. The Commission appreciates 
that not granting such a right causes some risk for transmission 
developers in disclosing their transmission projects for consideration 
in the regional transmission planning process. That risk is outweighed, 
however, by the potentially negative impacts such a rule could have on 
regional transmission planning.
4. Reliability Compliance Obligations of Transmission Developers
a. Comments Regarding Reliability Obligations
    341. PSEG Companies and Indianapolis Power & Light contend that it 
is unclear how compliance with NERC reliability standards would be 
managed and whether and to what extent a third-party developer would be 
responsible for NERC compliance, coordination of outages, and whether 
it would need to become a member or transmission owner in an RTO. PSEG 
Companies also assert that third party developers are not regulated by 
state commissions and are not subject to state law obligations with 
respect to reliability and safety or state law oversight of their 
operations. Salt River Project argues that mandatory compliance with 
NERC reliability standards places added pressure on transmission owners 
and operators to be involved in every stage of planning, construction, 
and obligation. It asserts that the Proposed Rule was silent as to 
whether the proposed rules might work with respect to nonincumbent 
developers that are subsidized for the project but who then may not be 
interested or qualified to operate or own the facility, let alone 
comply with reliability standards. Indianapolis Power & Light also 
expresses concern that questions will remain regarding whether and to 
what extent a nonincumbent transmission developer is required to comply 
with NERC reliability standards. Other commenters respond that 
incumbent transmission owners and nonincumbent transmission developers 
are subject to and have to meet the same reliability standards.\309\
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    \309\ E.g., City of Santa Clara; Federal Trade Commission; 
NextEra; Northern California Power Agency; Pattern Transmission; and 
Western Independent Transmission Group.
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b. Commission Determination
    342. As discussed in section III.B.3 above, the Commission 
concludes that potentially increasing the number of asset owners 
through the elimination of a federal right of first refusal in 
Commission-jurisdictional tariffs and agreements does not, by itself, 
make it more difficult for system operators to maintain reliability. 
The Commission acknowledges, however, that a proposed transmission 
facility's impact on reliability is an important factor that is 
considered during evaluation of a proposed transmission facility for 
potential selection. We note 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, as every other registered entity is 
required. As part of that process, all entities, incumbent and 
nonincumbents alike, that are users, owners or operators of the 
electric bulk power system must register with NERC for performance of 
applicable reliability functions.
    343. However, if there are still concerns regarding the lack of 
clarity as to when compliance with NERC registration and reliability 
standards would be triggered, we conclude that the appropriate forum to 
raise these questions and request clarification is the NERC process.
    344. The Commission is sensitive to the concerns of some commenters 
that contend that existing transmission providers run the risk of 
violating NERC reliability standards in the event that a nonincumbent 
transmission developer abandons a transmission facility meant to 
address a violation. To address such concerns, the Commission clarifies 
that, if a violation of a NERC reliability standard 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. Rather, the transmission provider must identify 
the specific NERC reliability standard(s) that will be violated and 
submit a NERC mitigation plan to address the violation. Provided the 
public utility transmission provider follows the NERC approved 
mitigation plan, the Commission will not subject that public utility 
transmission provider to enforcement action for the specific NERC 
reliability standard violation(s) caused by a nonincumbent transmission 
developer's decision to abandon a transmission facility.

C. Interregional Transmission Coordination 310
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    \310\ We 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. See supra section III.A.2.
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    345. This section of the Final Rule adopts several reforms to 
improve coordination among public utility transmission planners with 
respect to the coordination of interregional transmission facilities. 
Specifically, the Commission requires each public utility transmission 
provider, through its regional transmission planning process, to 
enhance existing regional transmission planning processes in the 
following ways.\311\ First, the Commission requires the development and 
implementation of procedures that provide for the sharing of 
information regarding the respective needs of neighboring transmission 
planning regions, as well as the identification and joint evaluation by 
the neighboring transmission planning regions of

[[Page 49901]]

potential interregional transmission facilities that address those 
needs. Second, to ensure that developers of interregional transmission 
facilities have an opportunity for their transmission projects to be 
evaluated, the Commission requires the development and implementation 
of procedures for neighboring public utility transmission providers to 
identify and jointly evaluate transmission facilities that are proposed 
to be located in both regions. Third, to facilitate the joint 
evaluation of interregional transmission facilities, the Commission 
requires the exchange of planning data and information between 
neighboring transmission planning regions at least annually. Finally, 
to ensure transparency in the implementation of the foregoing 
requirements, the Commission requires public utility transmission 
providers, either individually or through their transmission planning 
region, to maintain a Web site or e-mail list for the communication of 
information related to interregional transmission coordination.
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    \311\ In the Proposed Rule, the Commission sometimes referred to 
the requirements of this section as ``interregional transmission 
planning''; however, we believe that ``interregional transmission 
coordination'' better describes what we are requiring in this Final 
Rule and, therefore, we will refer herein to ``interregional 
transmission coordination.''
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    346. Through these reforms, the Commission aims to facilitate the 
identification and evaluation of interregional transmission facilities 
that may resolve the individual needs of neighboring transmission 
planning regions more efficiently and cost-effectively. To accomplish 
these reforms, public utility transmission providers in each pair of 
transmission planning regions are directed to work through their 
regional transmission planning processes to develop the same language 
to be included in each public utility transmission provider's OATT that 
describes the procedures that a particular pair of transmission 
planning regions will use to satisfy the foregoing requirements. 
Alternatively, if the public utility transmission providers so choose, 
these procedures may be reflected in an interregional transmission 
planning agreement among the public utility transmission providers 
within neighboring transmission planning regions that is filed with the 
Commission.\312\
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    \312\ We discuss the filing requirements for the same language 
to be included in each public utility transmission provider's OATT 
that describes the procedures that a particular pair of transmission 
planning regions will use to satisfy the interregional transmission 
coordination requirements as well as for any interregional 
transmission coordination agreements in the compliance section 
below. See discussion infra section III.C.3.e. of this Final Rule.
---------------------------------------------------------------------------

1. Need for Interregional Transmission Coordination Reform \313\
---------------------------------------------------------------------------

    \313\ Legal authority issues associated with the interregional 
transmission coordination reforms described herein are addressed in 
the discussion above concerning regional transmission planning. See 
discussion supra section III.A.2. of this Final Rule.
---------------------------------------------------------------------------

a. Commission Proposal
    347. In Order No. 890, the Commission found that, when transmission 
providers engage in regional transmission planning, they may identify 
solutions to regional needs that are more efficient than those that 
would have been identified if needs and potential solutions were 
evaluated only independently by each individual transmission 
provider.\314\ In Order No. 890-A, the Commission reiterated that 
effective regional transmission planning must include coordination 
among transmission planning regions. To that end, the Commission 
required public utility transmission providers within each transmission 
planning region to coordinate as necessary to share data, information, 
and assumptions to maintain reliability and allow customers to consider 
resource options that span a region.\315\
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    \314\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 524.
    \315\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 226.
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    348. The Commission noted in the Proposed Rule that, within the 
Order No. 890 and 890-A framework, transmission providers in certain 
parts of the country have organized subregional transmission planning 
groups for the purpose of collectively developing transmission plans 
for facilities on their combined transmission systems. These 
subregional transmission plans are then analyzed at a regional level to 
ensure that, if implemented, they will be simultaneously feasible and 
meet reliability requirements. The Commission also acknowledged that 
some neighboring transmission planning regions have undertaken joint 
transmission planning pursuant to bilateral agreements.\316\
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    \316\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 103.
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    349. However, the October 2009 Notice observed that there are few 
processes in place to analyze whether alternative interregional 
solutions more efficiently or effectively would meet the needs 
identified in individual regional transmission plans. As part of the 
October 2009 Notice, the Commission posed several questions related to 
this issue, including whether existing transmission planning processes 
are adequate to identify and evaluate potential solutions to needs 
affecting the systems of multiple transmission providers. The 
Commission also sought comment as to what processes should govern the 
identification and selection of projects that affect multiple systems.
    350. In light of the comments received on this issue, the 
Commission in the Proposed Rule expressed concern that the lack of 
coordinated transmission planning processes across the seams of 
neighboring transmission planning regions could be needlessly 
increasing costs for customers of transmission providers, which may 
result in rates that are unjust and unreasonable and unduly 
discriminatory or preferential. The Commission noted that, in the few 
years since the issuance of Order No. 890, interest in multiregional 
transmission facilities has grown significantly.\317\ Therefore, the 
Commission proposed reforms intended to improve coordination between 
neighboring transmission planning regions with respect to the 
evaluation of transmission facilities that are proposed to be located 
in both regions, as well as other possible interregional transmission 
facilities, to determine if such facilities address the needs of the 
transmission planning regions more efficiently or cost-
effectively.\318\
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    \317\ The Commission cited two such recent multiregional 
projects. Id. n.46 (citing Pioneer Transmission, LLC, 126 FERC ] 
61,281 (2009); Green Power Express LP, 127 FERC ] 61,031 (2009)).
    \318\ Id. P 112-113.
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b. Comments
    351. Many commenters agree that there is a need to increase 
coordination in interregional transmission planning,\319\ and 
identified a range of deficiencies in and opportunities for enhancement 
of existing interregional transmission coordination efforts. Several 
commenters state that a more defined and coordinated interregional 
transmission planning process is

[[Page 49902]]

necessary. For example, AEP, joined by Integrys, contends that utility 
and regional transmission planning efforts have a limited geographic 
perspective and do not consider the benefits associated with 
interregional transmission projects in neighboring regions. Boundless 
Energy and Sea Breeze state that in the absence of RTOs and ISOs, and 
particularly in WECC, interregional transmission planning is 
ineffective, overly costly, and focuses on individual transmission 
projects with no relationship to the grid as a whole network or a smart 
grid.
---------------------------------------------------------------------------

    \319\ E.g., AEP; Allegheny Energy Companies; AWEA; CapX2020 
Utilities; Clean Line; Duke; East Texas Cooperatives; Edison 
Electric Institute; Energy Future Coalition; Environmental Defense 
Fund; Exelon; Federal Trade Commission; First Energy Service 
Company; Integrys; ISO New England; ITC Companies; Kansas City Power 
& Light and KCP&L Greater Missouri; LS Power; Massachusetts 
Departments; MidAmerican; MISO; MISO Transmission Owners; Minnesota 
PUC and Minnesota Office of Energy Security; National Grid; Natural 
Resources Defense Council; NEPOOL; New York ISO; NextEra; Northeast 
Utilities; Old Dominion; Organization of MISO States; Pattern 
Transmission; Pennsylvania PUC; PHI Companies; Pioneer Transmission; 
Powerex; PSEG Companies; PUC of Nevada; San Diego Gas & Electric; 
Sonoran Institute; Sunflower and Mid-Kansas; Transmission Access 
Policy Study Group; Vermont Electric; Westar; Wilderness Society and 
Western Resource Advocates; WIRES; and Wisconsin Electric Power 
Company.
---------------------------------------------------------------------------

    352. Other commenters argue that there is no coordinated process 
between regions with respect to evaluating interregional transmission 
projects.\320\ AEP and MidAmerican specify that the lack of a 
coordinated process between transmission planning regions creates 
hurdles for projects (especially proposed extra high voltage 
facilities) that are unreasonably higher than those faced by 
intraregional transmission projects. MidAmerican contends that 
different regions have different planning protocols and rules for 
project evaluation and justification, and focus too narrowly on 
planning criteria that are limited to reliability, generator 
interconnection, and economic congestion relief to demonstrate the need 
for a project. It states that many transmission planning regions do not 
have joint planning protocols or other tariff authority under which an 
interregional project could be approved based on the total benefits 
that it provides to the planning regions; and that there is a lack of 
coordinated planning to identify the most economically efficient 
solutions. Transmission Dependent Utility Systems state that the 
ultimate objective of the Final Rule should be the development of a 
regional transmission plan that jointly optimizes solutions for 
transmission across the regions to allow access to economically-priced 
energy by all transmission providers and customers to best serve their 
native loads. 26 Public Interest Organizations state that without 
interregional coordination of planning assumptions and procedures, it 
may not be possible to develop regional transmission plans that the 
Commission can rely on to determine whether rates are just and 
reasonable.
---------------------------------------------------------------------------

    \320\ E.g., East Texas Cooperatives; AEP; Kansas City Power & 
Light and KCP&L Greater Missouri; Anbaric and PowerBridge; Edison 
Electric Institute; MISO Transmission Owners; TDU Systems; AWEA; and 
PSEG Companies.
---------------------------------------------------------------------------

    353. Some other commenters state that improved interregional 
transmission coordination would result in a more orderly and timely 
transmission planning process.\321\ Pioneer Transmission indicates that 
improved interregional transmission planning would require planning 
regions to adopt broader planning goals and objectives, plan 
transmission and generation in a coordinated and cohesive fashion, and 
recognize that the benefits of interregional transmission projects will 
multiply and that their beneficiaries often expand over time.
---------------------------------------------------------------------------

    \321\ E.g., First Wind; Solar Energy Industries; and Large-scale 
Solar.
---------------------------------------------------------------------------

    354. Several commenters also discuss the positive impacts that the 
proposed interregional transmission planning requirements would have on 
renewable resources. For example, some state that these requirements 
would facilitate access to renewable energy and help meet state, 
federal and other renewable energy goals.\322\ Pattern Transmission 
indicates that unless a formal interregional planning process is 
required, approval of transmission projects needed to allow load to 
access renewable resources will be difficult, particularly for 
remotely-located resources. Wind Coalition states that without 
interregional planning, location-constrained resources located in one 
region that could be cost-effectively accessed to serve the needs of an 
adjacent, or even more distant region, will not be available or may be 
accessed through a more expensive and less efficient transmission 
solution than would be possible with interregional transmission 
planning.
---------------------------------------------------------------------------

    \322\ E.g., Edison Electric Institute; AWEA; Clean Line; 
American Transmission; and Solar Energy Industries and Large-scale 
Solar.
---------------------------------------------------------------------------

    355. Some commenters argue that seams issues have prevented 
efficient use of existing transmission infrastructure and adequate 
consideration of the needs of load-serving entities at the seams.\323\ 
Several commenters cite difficulties they have had in the MISO and PJM, 
Entergy and SPP, PJM and New York ISO, and Pacific Northwest 
regions.\324\ For example, East Texas Cooperatives state a lack of 
coordination between SPP and Entergy has hindered its ability to obtain 
network service for a new generating plant. Specifically, East Texas 
Cooperatives state that in 2009 they submitted a request to SPP for 335 
MW of network service sourcing and sinking in SPP to access the 
Harrison County generating plant. When studying the request, SPP 
determined that it may cause impacts on Entergy's system. After 
multiple iterations of the SPP Aggregate Study Process and two Affected 
System Analysis were conducted, the Entergy system identified $30.7 
million of upgrades necessary to facilitate the request, the cost of 
which were to be directly assigned to East Texas Cooperatives. East 
Texas Cooperatives identified several potential issues in the SPP and 
Entergy studies that appeared to stem, at least in part, from a lack of 
queue coordination between Entergy and SPP. East Texas Cooperatives 
state that after significant effort on their part and additional study 
costs being incurred, which may not have been necessary with better 
coordination between Entergy and SPP, the cost of the necessary 
upgrades on the Entergy system was dramatically reduced. However, East 
Texas Cooperatives state that errors in SPP's planning studies and a 
lack of coordination between SPP and Entergy in addressing East Texas 
Cooperatives' network service request, resulted in a long delay in 
securing the necessary financing for the Harrison County project.
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    \323\ E.g., AEP; Anbaric and PowerBridge; Connecticut & Rhode 
Island Commissions; East Texas Cooperatives; Edison Electric 
Institute; Energy Consulting Group; MISO Transmission Owners; 
Northeast Utilities; and Omaha Public Power District.
    \324\ E.g., Pennsylvania PUC; MidAmerican; Exelon; East Texas 
Cooperatives; PSEG Companies; and Powerex.
---------------------------------------------------------------------------

    356. Similarly, ITC Companies state that it has been difficult to 
move forward on its Green Power Express project because there is no 
applicable planning process for projects that extend beyond the 
boundaries of a single RTO. Exelon states that its experience on the 
seam between MISO and PJM supports the contention that mandatory 
interregional planning is needed at this time. For instance, Exelon 
cites issues in studying and building transmission projects identified 
in the MISO's Regional Generation Outlet Study as necessary to deliver 
35 GW of wind energy to load centers in the MISO. Exelon states that 
several of the projects are located in PJM, but will not be studied 
further by the MISO because MISO states that it has no authority to 
order its members or PJM members to build transmission on PJM's system. 
In addition, Exelon states that current coordination protocols between 
the MISO and PJM are failing to prevent increased congestion in PJM, 
resulting in deteriorating operations at the seam such as increased 
transmission loading relief (TLR) events on the Commonwealth Edison 
system. PJM, however, disputes Exelon's assertions regarding both the 
cause and the total number of TLR events on the Commonwealth Edison 
system.
    357. PSEG Companies recommend that where there is evidence of

[[Page 49903]]

significant seams issues that affect operations, the Commission should 
require that the affected planning regions: (1) coordinate the planning 
of their systems, including sharing information needed to forecast, 
measure, and monitor impacts; and (2) form an agreement to address how 
the costs associated with cross-border impacts will be allocated that 
incorporates the ``beneficiary pays'' approach. Pennsylvania PUC states 
that the Commission's proposed interregional transmission planning 
requirements may help to improve interregional operational efficiency 
between RTOs.
    358. Organization of MISO States and Pattern Transmission discuss 
the effect of improved interregional coordination between RTO and non-
RTO regions. Organization of MISO States notes that the proposed 
requirements would enhance the incorporation of non-RTO regions into 
interregional transmission planning processes. According to Pattern 
Transmission, interregional transmission planning is particularly 
important in non-RTO and non-ISO regions, where the lack of a 
structured regional transmission planning process effectively restricts 
transmission development by nonincumbent developers to merchant 
transmission developers.
    359. Transmission Dependent Utility Systems urge the Commission to 
adopt the proposed interregional transmission planning reforms without 
delay as they are necessary to promote cost-effective interregional 
transmission planning and to remedy the unduly discriminatory exclusion 
of transmission customers that are load-serving entities from these 
activities. They assert that transmission providers have little 
incentive to develop transmission that would allow competing suppliers 
to serve customers and that in many regions, interregional transmission 
planning efforts are either nonexistent or are often implemented 
through bilateral agreements that provide no opportunity for active 
participation by transmission customers that are load-serving entities 
or other stakeholders.
    360. Several commenters stress that the Commission's actions in 
this proceeding must not interfere with the ARRA-funded transmission 
planning initiatives.\325\ Allegheny Energy Companies believe in the 
potential success of the ARRA-funded process. They state that the ARRA-
funded interconnectionwide transmission planning initiatives may 
develop into a potential model for an open, interconnectionwide 
transmission planning process and in effect could help resolve some of 
the planning issues currently being encountered. Western Area Power 
Administration urges the Commission to consider the positive 
developments associated with the implementation of these initiatives 
while developing any Final Rule.
---------------------------------------------------------------------------

    \325\ E.g., Indianapolis Power & Light; NARUC; PHI Companies; 
Pennsylvania PUC; PSC of Wisconsin; SPP; and Transmission Access 
Policy Study Group.
---------------------------------------------------------------------------

    361. Some commenters argue that interregional transmission planning 
reforms are needed notwithstanding the ARRA-funded interconnectionwide 
transmission planning initiatives.\326\ SPP states that the ARRA-funded 
process will not ensure that the most cost-effective solutions are 
implemented across planning regions or the entire interconnection. 
Transmission Dependent Utility Systems also contend that the ARRA-
funded process does not address short-range needs for interregional 
projects and may have too wide of a geographic scope to conduct the 
bottom-up planning necessary to ensure that the needs of load-serving 
entities are met. AEP encourages the Commission to provide as much 
direction as possible to the planning authorities to ensure that the 
ARRA initiatives accomplish more than the cumulative assembly of the 
isolated plans of each region and planning entity.
---------------------------------------------------------------------------

    \326\ E.g., SPP; Minnesota PUC and Minnesota Office of Energy 
Security; AEP; and Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    362. Conversely, other commenters suggest that the Commission 
postpone imposing new requirements until after the ARRA-funded 
interconnection-wide transmission planning process is complete.\327\ 
For example, Southwest Area Transmission Sub-Regional Planning Group 
encourages the Commission to support existing planning activities, 
postponing the proposal for additional requirements until after the 
ARRA-funded interconnectionwide transmission planning initiatives are 
complete. ColumbiaGrid and ISO New England argue that their 
transmission planning processes already comply with the Commission's 
proposed requirements. The New England Transmission Owners support the 
Commission's interregional transmission planning objectives, but urge 
the Commission to give the ISO New England's existing interregional 
transmission planning process time to mature before imposing any new or 
additional requirements. PHI Companies argue that the Commission should 
require that existing interregional planning processes that meet the 
Commission's articulated principles be followed whenever the objectives 
of one region have the potential to impose burdens or costs on another 
region.
---------------------------------------------------------------------------

    \327\ E.g., Southwest Area Transmission Sub-Regional Planning 
Group; APPA; and Xcel.
---------------------------------------------------------------------------

    363. Other commenters oppose the Commission's proposed 
interregional transmission planning requirements, arguing they are 
unnecessary \328\ or premature.\329\ In particular, several commenters 
state that existing transmission planning processes in their regions 
(West, Southeast, Midwest) have led to significant progress and that 
there is no need for mandating that regions create interregional 
transmission planning agreements.\330\ For example, Southern Companies 
state that there already is an institution in place to provide 
interregional coordination in the Eastern Interconnection, namely the 
Eastern Interconnection Planning Collaborative. Salt River Project 
similarly states that it participates in robust and effective planning 
activities in the West, and provides an inventory of projects, 
including interregional lines that are being built as a result of 
coordination between regional and subregional planning groups. Southern 
Companies note that the Commission's proposed interregional 
transmission planning requirements are unnecessary as the deficiencies 
alleged by the Commission in the Proposed Rule are not applicable in 
the Southeast. Organization of MISO States expresses its view that the 
Commission should give the interconnectionwide Eastern Interconnection 
States Planning Council planning process some time to work before 
requiring the filing of any bi-regional interregional transmission 
planning agreements.
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    \328\ E.g., California ISO; ColumbiaGrid; Indianapolis Power & 
Light; National Rural Electric Coops; Southern Companies; and 
Washington Utilities and Transportation Commission.
    \329\ E.g., Georgia Transmission Corporation; Salt River 
Project; and Southwest Area Transmission Sub-Regional Planning 
Group.
    \330\ E.g., Salt River Project; Southwest Area Transmission Sub-
Regional Planning Group; Xcel; California Commissions; San Diego Gas 
& Electric; NEPOOL; Northeast Utilities; New England Transmission 
Owners; Southern Companies; Washington Utilities and Transportation 
Commission; and Indianapolis Power & Light.
---------------------------------------------------------------------------

    364. Salt River Project and Southwest Area Transmission contend 
that the proposed requirements are premature because the Commission did 
not provide specific examples of deficiencies and lack of coordination 
in the transmission planning process that support the need for the 
proposed requirements. They recommend that the Commission undertake a 
comprehensive

[[Page 49904]]

and thorough inventory of existing planning processes and then use the 
demonstrable outcomes of these processes to identify any real barriers 
that would merit new rules or regulations. National Rural Electric 
Coops, Indianapolis Power and Light, and Transmission Agency of 
Northern California contend, in whole or part, that the Commission 
should pursue only additional reforms that address specific problems 
identified in the record from this proceeding, that mandatory 
coordination should occur on an as-needed basis where such efforts are 
likely to lead to substantial transmission development, and that any 
further reforms be targeted to specific problems.
    365. Some commenters suggest that the Commission should allow Order 
No. 890 processes to develop further before imposing new interregional 
coordination requirements.\331\ Xcel acknowledges the need for 
interregional planning and cost allocation mechanisms to support public 
policy mandates, but recommends that the Commission allow current 
voluntary interregional planning and cost allocation discussions to 
continue, rather than mandate the development of interregional 
agreements within a specified time frame.
---------------------------------------------------------------------------

    \331\ E.g., Washington Utilities and Transportation Commission; 
Georgia Transmission Corporation; and Xcel.
---------------------------------------------------------------------------

    366. Similarly, several commenters contend that interregional 
coordination should be voluntary. Ad Hoc Coalition of Southeastern 
Utilities and Bonneville Power contend that the Commission should 
permit parties to pursue voluntary interregional transmission planning 
agreements. Ad Hoc Coalition of Southeastern Utilities states that it 
supports voluntary efforts of regional transmission processes to 
address facilities located in multiple regions. Similarly, North 
Carolina Agencies state that coordination among regions, as well as 
within a broadly defined region, should be voluntary. Bonneville Power 
states that the Commission has not demonstrated that the voluntary 
approach does not work in the Pacific Northwest or that it is not just 
and reasonable or that it is unduly discriminatory or preferential. It 
recommends that if the Commission mandates interregional transmission 
planning agreements, it should permit parties the discretion to pursue 
voluntary agreements for interregional planning in general, as well as 
for specific projects. Further, California ISO points to successful 
voluntary coordination efforts in the West by WECC and California 
Transmission Planning Group. California PUC, in its reply comments, 
supports California ISO's and Bonneville Power's views.
    367. Other reply commenters disagree with these arguments. 26 
Public Interest Organizations respond that the Commission is obligated 
under the FPA to ensure that changing system needs (such as state 
renewable portfolio standards and new federal environmental rules) and 
the consequences for systems outside of the RTO's footprint (such as 
loop flow) are justly and reasonably addressed, which requires 
interregional coordination. WIRES replies that interregional planning 
must be made mandatory and subject to stronger Commission oversight and 
participation. WIRES states that experience demonstrates that, left to 
the voluntary cooperation of the parties, the transmission network will 
not be integrated as effectively as it could be, reliability and 
resource diversity will suffer, and seams and congestion issues will be 
unresolved.
c. Commission Determination
    368. The Commission concludes that implementation of further 
reforms in the area of interregional transmission coordination 
activities are necessary at this time. As the Commission stated in the 
Proposed Rule, in the absence of coordination between transmission 
planning regions, public utility transmission providers may be unable 
to identify more efficient or cost-effective solutions to the 
individual needs identified in their respective local and regional 
transmission planning processes, potentially including interregional 
transmission facilities. Clear and transparent procedures that result 
in the sharing of information regarding common needs and potential 
solutions across the seams of neighboring transmission planning regions 
will facilitate the identification of interregional transmission 
facilities that more efficiently or cost-effectively could meet the 
needs identified in individual regional transmission plans.
    369. Specifically, we agree with commenters, such as AEP, that the 
transmission planning 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 in 
neighboring transmission planning regions. Our decision also is 
influenced by those commenters that cite seams issues or difficulties 
they have encountered in coordinating the development of transmission 
facilities across the regions, including between RTOs and ISOs, as well 
as between an RTO or ISO and non-RTO or ISO region and among non-RTO 
regions. We are persuaded by those commenters who argue that additional 
interregional transmission coordination requirements would facilitate 
consideration of transmission needs driven by Public Policy 
Requirements by enabling the evaluation of interregional transmission 
facilities that may address those needs more efficiently or cost-
effectively. We agree with Transmission Dependent Utility Systems' 
comments that interregional transmission coordination promotes cost-
effective transmission development and facilitates transmission 
customer participation in interregional transmission coordination 
efforts.
    370. Given the clear need for reform of existing interregional 
transmission coordination practices, we are not persuaded by arguments 
contending that reform is not necessary or is premature. While we 
recognize that significant progress with respect to the development of 
open and transparent transmission planning processes has been made 
around the country, the existing transmission planning processes 
nevertheless do not adequately provide for the evaluation of proposed 
interregional transmission facilities or the identification of 
interregional transmission facilities that could address transmission 
needs more efficiently or cost-effectively than separate regional 
transmission facilities. Because such interregional transmission 
coordination helps to ensure that rates, terms, and conditions of 
jurisdictional service are just and reasonable and not unduly 
discriminatory or preferential by facilitating more efficient or cost-
effective transmission infrastructure development, we conclude that the 
interregional transmission coordination reforms adopted in this Final 
Rule are necessary and should not be delayed.
    371. Similarly, while we have considered the positive developments 
associated with the ARRA-funded transmission planning initiatives, we 
nevertheless agree with commenters who argue that the Commission should 
not postpone its proposed interregional transmission coordination 
reforms on account of these initiatives. While the ARRA-funded 
transmission planning initiatives represent a significant advancement 
in interconnectionwide transmission scenario analysis, they do not 
specifically provide for the ongoing coordination in the evaluation of 
interregional transmission facilities, which we conclude is necessary 
to ensure that rates, terms, and conditions of jurisdictional services 
are just and

[[Page 49905]]

reasonable and not unduly discriminatory or preferential. As requested 
by commenters, however, we have extended the compliance deadline for 
the interregional coordination requirements of this Final Rule, as 
discussed in section V.A below. We encourage public utility 
transmission providers to continue their participation in these efforts 
and to explore opportunities to use the valuable information these 
efforts provide in their regional transmission planning and 
interregional transmission coordination efforts. We reiterate our 
intent to build upon, and not interfere with, the ARRA-funded 
transmission planning initiatives in this Final Rule.
    372. With regard to commenters' contentions that their existing 
interregional transmission coordination efforts already comply with the 
Proposed Rule's provisions or need more time to mature, we acknowledge 
that some transmission planning regions already may engage in 
interregional transmission coordination efforts that satisfy some of 
the requirements discussed below or are developing such efforts. The 
Commission is acting in this Final Rule to establish a minimum set of 
requirements that apply to all public utility transmission providers. 
If a public utility transmission provider believes that it participates 
in a regional transmission planning process that fulfills the 
interregional transmission coordination requirements adopted in this 
Final Rule, it may describe in its compliance filing how such 
participation complies with the requirements of this Final Rule.
    373. We therefore disagree that the Commission should undertake 
additional investigation of the need for interregional coordination 
procedures or require them only on a case-by-case basis. The record in 
this proceeding is adequate to support our conclusion that the existing 
requirements of Order No. 890 are too narrowly focused geographically. 
Coordination of transmission planning activities by neighboring 
transmission planning regions will increase opportunities to identify 
interregional transmission facilities that address the needs of those 
regions more efficiently or cost-effectively. We thus see no need to 
adopt a case-by-case approach to our requirements. We conclude that the 
interregional coordination obligations implemented in this Final Rule 
are necessary to establish a minimum set of requirements that are 
applicable to all public utility transmission providers.
2. Interregional Transmission Coordination Requirements
a. Interregional Transmission Coordination Procedures
i. Commission Proposal
    374. In the Proposed Rule, the Commission proposed to require each 
public utility transmission provider through its regional transmission 
planning process to enter into agreements that include a detailed 
description of the process for coordination between public utility 
transmission providers in neighboring transmission planning regions 
with respect to transmission facilities that are proposed to be located 
in both regions, as well as interregional transmission facilities that 
are not proposed that could address transmission needs more efficiently 
than separate intraregional facilities.\332\ While acknowledging that 
every transmission planning agreement could be tailored to best fit the 
needs of the transmission planning regions entering into the agreement, 
the Commission proposed that each public utility transmission provider 
ensure that certain elements are included in each agreement.
---------------------------------------------------------------------------

    \332\ The Commission discusses in subsection 3e below comments 
in response to the proposal for interregional transmission 
coordination activities to be memorialized in an agreement executed 
by multiple public utility transmission providers.
---------------------------------------------------------------------------

    375. Specifically, the Commission proposed that an interregional 
transmission planning agreement must include the following elements: 
(1) A commitment to coordinate and share the results of respective 
regional transmission plans to identify possible interregional 
facilities that could address transmission needs more efficiently than 
separate intraregional facilities (Coordination); (2) an agreement to 
exchange at least annually planning data and information (Data 
Exchange); (3) a formal procedure to identify and jointly evaluate 
transmission facilities that are proposed to be located in both regions 
(Joint Evaluation); and (4) a commitment to maintain a Web site or e-
mail list for the communication of information related to the 
coordinated transmission planning process (Transparency).
    376. With respect to the third proposed element, the Commission 
proposed that the transmission developer of a transmission project that 
would be located in two neighboring transmission planning regions must 
first propose its transmission project in the transmission planning 
process of each of those transmission planning regions. The Commission 
further proposed that such a submission would trigger a procedure 
established by the interregional transmission planning agreement, under 
which the transmission planning regions would coordinate their reviews 
of and jointly evaluate the proposed transmission project. The 
Commission proposed that such coordination and joint evaluation must be 
conducted in the same general timeframe as, rather than subsequent to, 
each transmission planning region's individual consideration of the 
proposed transmission project. Finally, the Commission proposed that 
inclusion of the interregional transmission project in each of the 
relevant regional transmission plans would be a prerequisite to 
application of an interregional cost allocation method that satisfies 
the cost allocation principles set forth in the Proposed Rule.
ii. Comments
    377. American Transmission supports requiring regions to make a 
commitment to coordinate and share the results of respective regional 
transmission plans to identify possible interregional transmission 
facilities that could address transmission needs more efficiently than 
separate intraregional facilities. However, American Transmission also 
recommends that the Commission require public utility transmission 
providers to specifically describe the process by which their planning 
regions will identify such interregional transmission facilities. East 
Texas Cooperatives suggest that the Commission clarify that it requires 
more than simple coordination (i.e., the sharing of information and 
plans), but also the establishment of an interregional transmission 
planning process intended to address and resolve seams issues.
    378. Several commenters request that the Commission provide more 
detailed guidance on the interregional transmission planning 
agreements.\333\ MISO Transmission Owners similarly request that the 
Commission clarify its specific expectations for interregional 
coordination. SPP recommends that the Final Rule provide detailed 
guidance concerning the requirements for interregional transmission 
planning, including the goals and objectives of interregional 
transmission planning. Powerex states that the Commission should 
require each interregional transmission planning agreement to include a 
set of interregional planning goals that are concrete and outcome-

[[Page 49906]]

based and that directly address the reliability problems that reduce 
efficiency. ITC Companies state that interregional transmission 
planning agreements should include the key criteria to be considered in 
the interregional planning process, based on the planning principles, 
and the cost allocation method that would apply to approved 
interregional projects.\334\
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    \333\ E.g., 26 Public Interest Organizations; MISO Transmission 
Owners; SPP; and Sunflower and Mid-Kansas.
    \334\ The cost allocation method that would apply to selected 
interregional transmission facilities is addressed in the cost 
allocation section below. See discussion supra section IV.E. of this 
Final Rule.
---------------------------------------------------------------------------

    379. Old Dominion recommends that the Commission require public 
utility transmission providers and interregional planning entities, 
such as the Eastern Interconnection Planning Collaborative, to adopt 
transmission planning processes that: (1) Identify the needs of 
multiple transmission systems based on scenario planning using a long-
term planning horizon (e.g., 15 to 20 years); (2) conduct various 
scenario analyses to identify the projects that best address 
reliability, economic, or demand response concerns; and (3) allow 
developers to compete to provide the ``best'' solution.
    380. Some commenters support a more robust interregional 
transmission planning process than the interregional coordination 
requirements set forth in the Proposed Rule. For example, Energy Future 
Coalition states the interregional transmission planning process should 
include a rigorous and transparent analysis of a comprehensive set of 
considerations and alternatives and provide for ``right-sizing'' 
facilities to ensure the best possible use of existing corridors and 
minimize environmental impacts from new corridors.
    381. A few commenters recommend that the Commission require 
interregional transmission planning processes to comply with the Order 
No. 890 planning principles.\335\ Transmission Dependent Utility 
Systems contend that subjecting interregional transmission planning 
processes to the Order No. 890 planning principles would alleviate 
concerns about the limited size of some Order No. 890-compliant 
planning regions, which arose due to the lack of an opportunity for 
load-serving entities to participate in planning across seams, and 
would ensure that the most cost-effective solutions to constraints 
associated with seams are pursued. Old Dominion states that requiring 
interregional transmission planning processes to comply with the Order 
No. 890 planning principles would ensure that information will flow 
between the regional and interregional transmission planning processes, 
so that stakeholders will have the information necessary to offer 
meaningful input at the interregional level and to inform discussions 
at the regional levels.
---------------------------------------------------------------------------

    \335\ E.g., East Texas Cooperatives; ITC Companies; Old 
Dominion; Transmission Access Policy Study Group; and Transmission 
Dependent Utility Systems.
---------------------------------------------------------------------------

    382. Energy Consulting Group states that transmission owners should 
be required to develop the transmission upgrades and expansions 
identified in the wide-area planning process within a mandated time 
frame. NextEra states that the Commission should require the 
interregional transmission planning process to result in an 
interregional transmission plan that includes interregional 
transmission facilities identified through the planning process. 
Boundless Energy and Sea Breeze contend that the Commission should 
strengthen interregional transmission planning processes by requiring 
implementation of interregional transmission plans and an implementing 
authority. MidAmerican expresses concern that proposed element 1 does 
not describe how the Commission intends neighboring planning regions to 
move those interregional projects identified towards construction, and 
recommends that the Commission require the identified interregional 
facilities to be included in local and regional transmission plans. 
Similarly, National Grid recommends that the Commission require 
consideration of procedures for adopting into regional plans any 
transmission upgrade identified as part of an interregional 
coordination process.
    383. Southwest Area Transmission Sub-Regional Planning Group, 
however, states that the Commission should clarify that 
interconnectionwide, regional, and interregional planning groups are 
not decision-making entities with the authority to direct developers or 
load-serving entities to develop any project. National Grid asks the 
Commission not to require the formation of new interregional planning 
entities, especially where interregional planning efforts are already 
underway.
    384. NextEra also states that the Commission should require the 
interregional transmission planning process to result in an 
interregional transmission plan that includes longer-term objectives 
that have not yet resulted in proposals for specific facilities. 
Similarly, California Commissions state that plans should contain 
conceptual elements that have yet to materialize as specific 
transmission projects and contingent elements that may be needed under 
certain future scenarios so that a plan can evolve over time.
    385. Solar Energy Industries and Large-scale Solar and Anbaric and 
PowerBridge urge the Commission to impose stronger requirements for 
interregional coordination for public policy and renewable energy 
projects. MidAmerican asks that the Commission clarify that 
consideration of public policy requirements is not limited to local and 
regional transmission planning processes but should be extended to 
interregional transmission coordination as well.
    386. On the other hand, Energy Consulting Group contends that 
interregional transmission planning should provide an incentive for 
development of transmission facilities that provide access to economic 
generation resources that minimize power costs, not act as an 
instrument of public policy. Energy Consulting Group also states that 
it is not clear that the proposed transmission planning processes will 
have a mechanism to address transmission service requests, and that a 
process for addressing such requests should be added to wide-area 
planning.
    387. ITC Companies contend that interregional coordination should 
assure equal consideration for all drivers of transmission needs, 
including reliability, generator interconnection, and public policy 
requirements. National Grid requests that the Commission require 
interregional transmission planning efforts to consider transmission 
upgrades that could provide economic benefits to consumers in multiple 
regions and upgrades or modified operating practices that could result 
in more efficient use of the existing transmission system in addition 
to those transmission facilities needed to maintain reliability. 
Powerex states that the Final Rule should establish policies that 
encourage transmission customers to continue to purchase and invest in 
long-term transmission and that the Commission should ensure that it is 
sending proper signals for long-term investments in transmission by 
rejecting policies that erode the existing rights of firm transmission 
customers that have already made long-term investments in transmission 
service.
    388. Organization of MISO States urges the Commission to encourage 
transmission planning regions to coordinate on issues besides 
transmission planning and cost allocation, such as interconnection and 
operational issues.
    389. North Carolina Agencies state that coordination among regions, 
as well as within a broadly defined region, should complement, rather 
than

[[Page 49907]]

substitute for, local and narrower regional planning processes. NEPOOL 
and Northeast Utilities state that the Proposed Rule's provisions, 
which reflect a ``bottom up'' planning approach, should be reflected in 
any Final Rule. Other commenters also support a ``bottom up'' approach 
to interregional transmission planning.\336\
---------------------------------------------------------------------------

    \336\ E.g., Allegheny Energy Companies; East Texas Cooperatives; 
and ISO New England.
---------------------------------------------------------------------------

    390. Other commenters urge the Commission to ensure that the Final 
Rule does not infringe on state authority. California Commissions 
emphasize that rules pertaining to interregional transmission planning 
agreements and the resulting coordinated planning process must not 
diminish state control by shifting decision-making to the Commission 
and that states should be directly involved in the development of 
interregional transmission planning agreements and should have a strong 
role in their implementation. NARUC asserts that the interregional 
transmission planning process must continue to respect the role of 
state commissions in reviewing and guiding the planning process and the 
role of state authorities in ultimately siting any transmission lines.
    391. Several commenters request that the Commission oversee the 
development and implementation of interregional transmission planning 
agreements and/or monitor the progress of interregional planning 
efforts.\337\ For example, Organization of MISO States suggests that 
the Commission require an accountability and oversight element in 
interregional transmission planning agreements to ensure that such 
agreements are implemented as intended, perhaps utilizing the expertise 
of state commissions. American Transmission and MISO Transmission 
Owners state that public utility transmission providers and their 
stakeholders should be required to conduct periodic reviews of the 
effectiveness of their interregional transmission planning efforts and 
file informational reports with the Commission.
---------------------------------------------------------------------------

    \337\ E.g., Energy Future Coalition; Organization of MISO 
States; Transmission Dependent Utility Systems; and AWEA.
---------------------------------------------------------------------------

    392. Federal Trade Commission acknowledges that the Commission's 
proposed interregional transmission planning requirements would require 
market participants that may be competitors to collaborate with each 
other in transmission planning, construction, ownership, and operation, 
but states that participants in the interregional transmission planning 
process should not view the antitrust laws as an impediment to their 
participation.
iii. Commission Determination
    393. To remedy the potential for unjust and unreasonable rates for 
public utility transmission providers' customers, we adopt the 
interregional transmission coordination requirements discussed below. 
These interregional transmission coordination requirements obligate 
public utility transmission providers to identify and jointly evaluate 
interregional transmission facilities that may more efficiently or 
cost-effectively address the individual needs identified in their 
respective local and regional transmission planning processes.
    394. In the Proposed Rule, the Commission set forth its proposed 
interregional transmission coordination requirements in the form of 
four elements to be included in an interregional transmission planning 
agreement. After reviewing the comments concerning interregional 
transmission coordination received in this proceeding, we find that 
these four elements are so extensively interconnected that it would be 
inappropriate to require that they be addressed as distinct elements, 
as was proposed in the Proposed Rule. Instead, we believe that these 
four elements are better represented as characteristics of 
interregional transmission coordination. Specifically, two of the 
proposed elements--Coordination and Joint Evaluation--embody the 
purpose of interregional transmission coordination: to coordinate and 
share the results of 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 to jointly evaluate such facilities, as 
well as to jointly evaluate those transmission facilities that are 
proposed to be located in more than one transmission planning region. 
The other two elements--Data Exchange and Transparency--are more 
appropriately described as part of the procedures through which 
effective interregional transmission coordination is implemented.
    395. Thus, the framework in which we present these requirements 
differs from that of the Proposed Rule. This Final Rule lays out the 
objectives of interregional transmission coordination followed by a 
discussion of the mechanics of interregional transmission coordination 
instead of four required elements. Here we address the requirements for 
interregional transmission coordination, the entities between which 
interregional transmission coordination must occur, and the 
transmission facilities to which the interregional transmission 
coordination requirements apply. Hence the discussion of Coordination 
and Joint Evaluation is here. We address in other sections below the 
mechanics of implementation, including a discussion of the procedures 
for joint evaluation, requirements for data exchange, transparency, 
stakeholder participation, and the required revisions to the OATT.
    396. The Commission requires 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 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. Through adoption of this requirement, the 
Commission intends that neighboring transmission planning regions will 
enhance their existing regional transmission planning processes to 
provide for: (1) The sharing of information regarding the respective 
needs of each region, and potential solutions to those needs; and (2) 
the identification and joint evaluation of interregional transmission 
facilities that may be more efficient or cost-effective solutions to 
those regional needs.\338\ By requiring public utility transmission 
providers to undertake such interregional transmission coordination 
activities, the Commission and transmission customers will have greater 
certainty that the transmission facilities in each regional 
transmission plan are more efficient or cost-effective solutions to 
meeting transmission planning region's needs.
---------------------------------------------------------------------------

    \338\ The same language must be included in each public utility 
transmission provider's OATT that describes the processes that a 
particular pair of transmission planning regions will use to satisfy 
the interregional transmission coordination requirements of this 
Final Rule. The filing requirements concerning this same language 
are discussed in the compliance section below. See discussion infra 
section VI.A. of this Final Rule.
---------------------------------------------------------------------------

    397. In response to the Proposed Rule, several commenters seek 
clarification from the Commission as to whether, for example, the 
Commission intends the formation of a new interregional transmission 
planning process or that certain types of facilities or objectives 
should be the focus of interregional transmission coordination. With 
the exception of the requirements for

[[Page 49908]]

implementing interregional transmission coordination discussed herein, 
the Commission declines at this time to impose specific obligations as 
to how neighboring transmission planning regions must share information 
regarding their needs, and potential solutions to those needs, or 
identify and jointly evaluate interregional transmission alternatives 
to those regional needs, as well as proposed interregional transmission 
facilities. Thus, we also decline to require the use of specific 
planning horizons or the performance of particular scenario analyses. 
While we appreciate commenters' desire for additional clarity on this 
point, the Commission believes it is appropriate to leave to the 
transmission planning regions in the first instance adequate discretion 
to allow for the development and implementation of interregional 
transmission coordination procedures that suit the needs of the 
neighboring transmission planning regions. In light of the varying 
approaches to transmission planning that are currently used by 
transmission planning regions across the country, providing further 
guidance at this time could inadvertently impose restrictions that are 
not appropriate for a particular transmission planning region.
    398. However, we clarify in response to East Texas Cooperatives 
that the interregional transmission coordination requirements adopted 
do require that public utility transmission providers do more than 
simply commit to share their regional transmission plans and other 
transmission planning information. To comply with the requirements in 
this Final Rule, each public utility transmission provider, through its 
regional transmission planning process, must develop and implement 
additional procedures that provide for the sharing of information 
regarding the respective needs of each neighboring transmission 
planning region, and potential solutions to those needs, as well as the 
identification and joint evaluation of interregional transmission 
alternatives to those regional needs by the neighboring transmission 
planning regions. On compliance, public utility transmission providers 
must describe the methods by which they will identify and evaluate 
interregional transmission facilities. While the Commission does not 
require any particular type of studies to be conducted, this Final Rule 
requires public utility transmission providers in neighboring 
transmission planning regions to jointly identify and evaluate whether 
interregional transmission facilities are more efficient or cost-
effective than regional transmission facilities. Accordingly, the 
Commission requires that the compliance filing by public utility 
transmission providers in neighboring planning regions include a 
description of the type of transmission studies that will be conducted 
to evaluate conditions on their neighboring systems for the purpose of 
determining whether interregional transmission facilities are more 
efficient or cost-effective than regional facilities.
    399. We decline to adopt the recommendations of those commenters 
that suggest that the Commission adopt a more robust, formalized 
interregional transmission planning process than the interregional 
transmission coordination requirements in the Proposed Rule, such as an 
interregional transmission coordination process that complies with the 
Order No. 890 transmission planning principles or that produces an 
interregional transmission plan. We clarify here that the interregional 
transmission coordination requirements that we adopt do not require 
formation of interregional transmission planning entities or creation 
of a distinct interregional transmission planning process to produce an 
interregional transmission plan. Rather, our 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. To the extent that public utility transmission 
providers wish to participate in processes that lead to the development 
of interregional transmission plans, they may do so and, as relevant, 
rely on such processes to comply with the requirements of this Final 
Rule.
    400. While we acknowledge MidAmerican's concern that the Commission 
does not specify how interregional transmission facilities will be 
moved toward construction, we note that in the Proposed Rule, the 
Commission stated that, consistent with Order No. 890, the proposed 
regional transmission planning obligations do not address or dictate 
which investments identified in a transmission plan should be 
undertaken by public utility transmission providers.\339\ We affirm 
that statement, and further note that Order No. 890 already requires 
that public utility transmission providers make available information 
regarding the status of transmission upgrades identified in their 
regional transmission plans in addition to the underlying transmission 
plans and related transmission studies.\340\ The Commission made clear 
in Order No. 890-A that transmission providers must make available to 
other stakeholders information regarding the progress and construction 
of transmission upgrades and transmission facilities.\341\ To the 
extent neighboring transmission planning regions identify interregional 
transmission facilities of mutual benefit and have such transmission 
facilities in their individual regional transmission plans, these 
informational requirements will apply to the portions of the 
interregional transmission facilities within each of the individual 
region's transmission plans. We decline to require, as suggested by 
MidAmerican and National Grid, that every interregional transmission 
facility that is evaluated through the interregional transmission 
coordination procedures automatically be selected in a regional 
transmission plan for purposes of cost allocation. However, as 
discussed below, an interregional transmission facility must be 
selected in both of the relevant regional transmission plans for 
purposes of cost allocation in order to be eligible for interregional 
cost allocation pursuant to an interregional cost allocation method 
required under this Final Rule. Rather, we expect that information 
exchanged during the interregional coordination effort should inform 
discussions at the regional and local transmission planning level.
---------------------------------------------------------------------------

    \339\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at n.59 
(citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 438).
    \340\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 472.
    \341\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 202.
---------------------------------------------------------------------------

    401. Moreover, in response to commenters, this Final Rule neither 
requires nor precludes longer-term interregional transmission planning, 
including the identification of conceptual or contingent elements,\342\ 
the consideration of transmission needs driven by Public Policy 
Requirements,\343\ or the evaluation of economic considerations.\344\ 
Whether and how to address these issues 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. However, the

[[Page 49909]]

Commission agrees with North Carolina Agencies that interregional 
transmission coordination should complement local and regional 
transmission planning processes, and should not substitute for these 
processes. Consistent with the implementation requirements for 
interregional transmission coordination procedures discussed in section 
III.C.3.a. below, we clarify that interregional transmission 
coordination may follow a ``bottom up'' approach. In response to Energy 
Consulting Group, we neither require nor prohibit consideration by 
neighboring transmission planning regions of requests for transmission 
service or upgrades within the interregional transmission coordination 
procedures required in this Final Rule.
---------------------------------------------------------------------------

    \342\ See California Commission.
    \343\ See MidAmerican.
    \344\ See Energy Consulting Group.
---------------------------------------------------------------------------

    402. With respect to commenters' assertion that this Final Rule 
should not infringe on state authority, we emphasize here that the 
interregional transmission coordination requirements are not intended 
to infringe on state authority. We acknowledge the vital role that 
state agencies play in transmission planning and their authority to 
site transmission facilities. We strongly encourage state agencies to 
be involved in the development and implementation of the interregional 
transmission coordination procedures necessary to satisfy the 
interregional transmission coordination requirements adopted herein.
    403. In response to commenters' requests that we monitor the 
implementation of the interregional transmission coordination 
requirements adopted in this Final Rule and the progress of 
interregional transmission coordination efforts, although the 
Commission believes that Commission oversight of compliance with this 
Final Rule and assessment of the adequacy of its measures is 
appropriate, the Commission does not intend to monitor coordination 
efforts so closely as to intrude in the interregional transmission 
coordination activities. It is not necessary for the Commission to 
decide the exact level of its monitoring at this time.
    404. We also decline to require public utility transmission 
providers and their stakeholders to conduct periodic reviews of the 
effectiveness of their interregional transmission coordination efforts 
and file information reports with us, as suggested by American 
Transmission and MISO Transmission Owners. However, we do encourage 
such reviews. We also note that parties may utilize the dispute 
resolution provisions of the relevant public utility transmission 
provider's OATT or file a complaint with the Commission if they find 
that the interregional transmission coordination procedures described 
in a public utility transmission provider's OATT are not being 
implemented properly.
b. Geographic Scope of Interregional Transmission Coordination
i. Commission Proposal
    405. As noted above, the Commission proposed to require 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 address transmission planning issues. The 
Commission noted that this does not require a public utility 
transmission provider to coordinate with a neighboring transmission 
planning region in another interconnection. However, the Commission 
also encouraged public utility transmission providers to explore 
possible multilateral interregional transmission coordination processes 
among several, or even all, transmission planning regions within an 
interconnection, building on processes developed through the ARRA-
funded transmission planning initiatives.\345\ The Commission proposed 
to require interregional coordination between public utility 
transmission providers in neighboring transmission planning regions 
with respect to transmission facilities that are proposed to be located 
in both regions, as well as interregional transmission facilities that 
are not proposed but that could address transmission needs more 
efficiently than separate intraregional transmission facilities.\346\
---------------------------------------------------------------------------

    \345\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 114-15.
    \346\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 116.
---------------------------------------------------------------------------

ii. Comments
    406. The Commission received a number of comments addressing the 
geographic scope of the proposed interregional coordination 
requirements, as well as the specific entities within the appropriate 
geographic scope that would be required to coordinate. Several 
commenters suggest that the Commission clarify how it defines regions 
for purposes of regional transmission planning to provide clarity as to 
how its proposed interregional transmission planning requirements will 
be implemented.\347\ Transmission Dependent Utility Systems recommend 
that the Commission define regional boundaries if it appears that there 
is discrimination or inefficiencies in the planning process. Others 
urge the Commission not to change existing areas over which 
transmission planning is now coordinated among transmission planning 
regions.\348\ For example, Integrys suggests that the Final Rule should 
preserve the existing mandate that PJM and the MISO constitute a single 
common market in the application of interregional transmission planning 
rules, and thus should be considered, at least for certain purposes, a 
single region subject to the interregional transmission planning and 
cost allocation rules.
---------------------------------------------------------------------------

    \347\ E.g., Integrys; Transmission Dependent Utility Systems; 
and MISO Transmission Owners.
    \348\ E.g., Integrys and National Grid.
---------------------------------------------------------------------------

    407. New York Transmission Owners agree with the Commission's 
proposal to require that interregional transmission planning agreements 
between neighboring planning regions address transmission facilities 
that are proposed to be located in both regions. However, New York ISO 
states that this requirement should not preclude planning regions from 
considering other types of projects.
    408. Several commenters either agree with the Commission's 
encouragement to extend interregional planning voluntarily beyond 
coordination between neighboring transmission planning regions so as to 
cover larger areas or an interconnection, or ask the Commission to 
require planning over such larger areas. ITC Companies state that, 
because some projects may involve more than two transmission planning 
regions, interregional planning also may need to involve more than two 
transmission planning regions. WECC suggests that because it already 
serves as a facilitator for interconnectionwide transmission planning 
and coordination in the Western Interconnection, it could provide a 
forum for facilitating multilateral transmission planning agreements. 
Federal Trade Commission recommends that the Commission 
institutionalize interconnectionwide transmission planning to 
incorporate relevant congestion, reliability, and environmental 
considerations and to reflect the geographic scope of power flows.
    409. AWEA recommends that the Commission require public utility 
transmission providers to enter into multilateral, or even 
interconnectionwide, interregional transmission planning agreements. 
Similarly, Wind Coalition encourages the Commission to consider 
extending its proposed interregional transmission planning requirements 
beyond adjacent planning regions to provide a process

[[Page 49910]]

for accessing location-constrained resources located in more distant 
regions. Grasslands contends that the Commission should not limit its 
proposed interregional coordination requirements to neighboring 
transmission planning regions within the same interconnection. Without 
interregional transmission planning between the interconnections, 
Grasslands claims that transmission developers will not develop 
transmission facilities that will efficiently link the interconnections 
in the future.
    410. Organization of MISO States cautions that, even with 
implementation of the proposed interregional transmission planning 
requirements, it may be difficult to require any non-RTO or non-ISO 
public utility transmission provider to act in the best interests of a 
geographic footprint beyond its own. Thus, it states that efforts such 
as the Eastern Interconnection States Planning Council, which would 
view projects over a geographic region larger than the RTO footprint, 
may be valuable.
    411. Other commenters support the Commission's intent not to 
mandate interconnectionwide transmission planning,\349\ offering among 
other things that mandating interconnectionwide planning would increase 
the difficulty of resolving local issues by making coordinated planning 
among transmission planning regions more complex and risk frustrating 
the ARRA-funded interconnectionwide transmission planning initiatives.
---------------------------------------------------------------------------

    \349\ E.g., Indianapolis Power & Light; Transmission Access 
Policy Study Group; MISO Transmission Owners; New York ISO; and 
Organization of MISO States.
---------------------------------------------------------------------------

    412. American Transmission and MISO Transmission Owners state that 
with respect to planning activities in regions without an RTO or ISO, 
the Commission should provide guidance as to which entities would be 
required to coordinate with each other. Integrys states that the 
Commission might implement its proposed interregional transmission 
planning requirements in non-RTO regions by requiring transmission 
providers in such regions to form planning consortia that could operate 
within a region and/or between two or more regions. Indianapolis Power 
& Light suggests that the Commission clarify whether transmission 
providers would be required to coordinate with each individual entity 
or one planning region to coordinate with another planning region.
    413. New York ISO states that the Commission should clarify that 
public utility transmission providers that are unable to reach 
interregional transmission planning agreements with neighboring 
Canadian systems will not be deemed out of compliance with the Final 
Rule.
    414. MISO Transmission Owners state that the agreements should 
enable a region impacted by a proposed project located in a neighboring 
region to review the neighboring region's plans, and that the 
transmission planning regions subject to the agreement should agree on 
what level of impact is material, as well as how disputes between the 
parties will be resolved. Edison Electric Institute and Exelon likewise 
state that the Commission should require that interregional 
transmission planning agreements address transmission facilities 
located in a single region that could have significant adverse impacts 
on the reliability of neighboring regions. Moreover, Exelon states that 
interregional transmission planning agreements should require that if a 
proposed project would result in any reliability violations or 
increased congestion on a neighboring system, these impacts must be 
mitigated before the project is approved.
iii. Commission Determination
    415. We require 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 adopted in 
this Final Rule. This requirement is necessary to improve coordination 
of neighboring transmission planning regions' activities, facilitating 
the identification and joint evaluation of interregional transmission 
solutions that could meet local and regional transmission needs more 
efficiently or cost-effectively than separate regional transmission 
solutions alone.
    416. The Commission declines to expand the interregional 
transmission coordination requirements adopted herein to require joint 
evaluation of the effects of a new transmission facility proposed to be 
located solely in a single transmission planning region. Although this 
Final Rule requires each regional transmission planning process to 
identify the consequences of a proposed new transmission facility in 
another transmission planning region as we explain below in the 
discussion of Cost Allocation Principle 4,\350\ we do not require that 
be done interregionally. To do so could have the effect of mandating 
interconnectionwide transmission planning, given that transmission 
facilities located within one transmission planning region often have 
effects on multiple neighboring systems, which could trigger a chain of 
multilateral evaluation processes. However, we believe that the 
exchange of planning data and information between neighboring 
transmission planning regions consistent with the interregional 
transmission coordination requirements of the Final Rule will assist 
transmission planners in understanding and managing the effects of a 
transmission facility located in one region upon another neighboring 
region. Further, although we decline to impose a joint evaluation by 
more than one region of a facility located solely in one transmission 
planning region, nothing in this Final Rule precludes public utility 
transmission providers from developing and proposing interregional 
processes for that purpose.\351\
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    \350\ See discussion infra section IV.E.5. of this Final Rule.
    \351\ Moreover, the absence of such a requirement in this Final 
Rule does not affect any obligations 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.
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    417. While the Commission declines to require multilateral or 
interconnectionwide coordination in this Final Rule, we continue to 
encourage public utility transmission providers to explore the 
possibility of multilateral interregional transmission coordination 
among several, or even all, transmission planning regions within an 
interconnection, building on the processes developed through the ARRA-
funded transmission planning initiatives. The Commission agrees that 
imposing multilateral or interconnectionwide coordination requirements 
at this time could frustrate the progress being made in the ARRA-funded 
transmission planning initiatives. To the extent that stakeholders in 
those planning initiatives wish to continue these activities at the 
conclusion of the ARRA-funded transmission planning initiatives, we 
encourage them to explore how existing regional transmission planning 
processes and interregional transmission coordination procedures 
implemented under Order No. 890 and this Final Rule could be enhanced 
to provide for such transmission planning activities.

[[Page 49911]]

    418. We decline to adopt Grasslands' recommendation that the 
Commission require interregional transmission coordination between 
transmission planning regions located in different interconnections. 
While we recognize that interregional transmission coordination between 
transmission planning regions in different interconnections could 
provide transmission planning benefits, such as increased power flows 
between interconnections, it may provide greater benefits for some 
pairs of neighboring transmission planning regions than for others due 
to geographical and operational limitations. Therefore, while we 
encourage public utility transmission providers to consider 
coordinating with neighboring transmission planning regions in 
different interconnections where it would be helpful, we do not find it 
appropriate to require such coordination in this Final Rule.
    419. In response to American Transmission and MISO Transmission 
Owners' request for guidance regarding the entities that they are 
required to coordinate with in neighboring regions without an RTO or 
ISO, we reiterate that we require 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. Thus, interregional transmission coordination would 
occur between the public utility transmission providers in two 
neighboring transmission planning regions.
    420. As discussed above in the regional transmission planning 
section,\352\ the Commission declines to revisit how each transmission 
planning region defines itself, as requested by Integrys and 
Transmission Dependent Utility Systems. We also decline to adopt 
Integrys' suggestion that the Commission could implement its 
interregional transmission coordination requirements in non-RTO regions 
by requiring public utility transmission providers in such regions to 
form planning consortia. Public utility transmission providers are free 
to do so; however, we do not want to foreclose other approaches to 
meeting the interregional transmission coordination requirements in 
this Final Rule.
---------------------------------------------------------------------------

    \352\ See supra section III.A.3 of this Final Rule.
---------------------------------------------------------------------------

    421. We clarify for New York ISO that a public utility transmission 
provider will not be deemed out of compliance with this Final Rule if 
it attempts to and is unable to develop interregional transmission 
coordination procedures with neighboring transmission systems in 
another country.
3. Implementation of the Interregional Transmission Coordination 
Requirements
a. Procedure for Joint Evaluation
i. Comments
    422. Several commenters express support for the Commission's 
proposal to require the development of a formal procedure to identify 
and jointly evaluate transmission facilities that are proposed to be 
located in neighboring transmission planning regions.\353\ Some 
commenters seek clarification of this requirement. For example, Duke 
suggests that the Commission clarify whether it intends that only one 
joint interregional study will be performed for a proposed 
interregional project, regardless of the number of regions that are 
crossed, as multiple studies would result in an inefficient use of 
resources. ISO/RTO Council and PJM ask whether the Commission intends 
``joint evaluation'' to mean coordination of stakeholder meetings and 
processes and/or the creation of a new set of planning criteria and a 
new planning cycle. In addition, PJM requests clarification as to 
whether the Commission intends ``joint evaluation'' to be conducted 
consistent with an interregional agreement such as the PJM/MISO Joint 
Operating Agreement.
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    \353\ E.g., American Transmission; New York Transmission Owners; 
Northeast Utilities; and Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    423. Several commenters urge the Commission to provide flexibility 
in developing and implementing planning agreements.\354\ They state 
that although the Commission proposed to require that interregional 
transmission planning agreements include the four elements of 
interregional coordination, the Commission also encouraged every 
interregional transmission planning agreement to be tailored to best 
fit the needs of the regions entering into the agreement. ISO New 
England urges the Commission to allow flexibility for regions to define 
in their interregional transmission planning agreements what it means 
to ``jointly evaluate'' interregional projects.
---------------------------------------------------------------------------

    \354\ E.g., PUC of Nevada; New York ISO; and Dayton Power and 
Light.
---------------------------------------------------------------------------

    424. In setting out the details of interregional coordination, PUC 
of Nevada urges the Commission to consider the ongoing efforts in the 
Western Interconnection to address interregional coordination. 
WestConnect Planning Parties state that any requirement to execute an 
interregional transmission planning agreement should respect the 
various organizational structures of existing regional and 
interregional planning processes, as well as allow signature by all 
formal participants in the interregional planning process instead of 
requiring ``formation of a legal entity authorized to act on behalf of 
those participants.''
    425. Other commenters offer specific suggestions as to the design 
and implementation of interregional coordination procedures. Minnesota 
PUC and Minnesota Office of Energy Security argue that, for the studies 
of an entire project to be meaningful and informative, all transmission 
planning entities studying a project should be required to coordinate 
their information and studies. Pioneer Transmission recommends that the 
Commission require planning regions to evaluate interregional projects 
through a single, coordinated process. It believes that if projects are 
studied under separate procedures by each planning region, 
interregional coordination would be unnecessarily delayed and more 
expensive than if the project was studied under a single set of 
procedures. However, Connecticut & Rhode Island Commissions contend 
that the Commission should require that proposed interregional projects 
be independently processed through each applicable regional planning 
process before they are eligible for joint evaluation through 
interregional coordination procedures.
    426. Old Dominion similarly recommends that coordinated analysis of 
interregional transmission facilities be accomplished through 
preliminary evaluation within existing regional transmission planning 
processes, followed by an evaluation of the project on an interregional 
basis. If the identified transmission facility is determined to meet 
interregional needs, the relevant transmission planning regions would 
incorporate the project into their regional transmission planning 
processes and further assess its effects on regional needs. Old 
Dominion recommends that the Commission require this ``feedback loop'' 
so that local and regional transmission plans can be reconsidered once 
an interregional transmission plan has been developed. Similarly, New 
England States Committee on Electricity supports the Commission's 
proposed interregional coordination requirements provided that 
interregional projects will be identified and developed through the 
current approach that begins with and respects the regional 
transmission

[[Page 49912]]

planning process and resulting regional transmission plan.
    427. Several commenters suggest that the Commission should develop 
a pro forma interregional transmission planning agreement. NextEra 
suggests that such an agreement include the steps by which the regions 
and their stakeholders will identify the transmission facilities 
necessary to meet their needs. Otherwise, NextEra contends that the 
negotiation of such agreements is likely to be cumbersome. ITC 
Companies agrees that development of a pro forma interregional planning 
agreement would provide clarity regarding the Commission's minimum 
requirements and, if designed properly, could avoid replication of 
flaws in existing transmission planning processes that occurred in the 
PJM and MISO Joint Operating Agreement. In its reply comments, PJM 
agrees with ITC Companies that a more standardized planning process 
that includes a pro forma interregional planning agreement could 
improve coordination with respect to interregional facilities, and 
cautions that the Commission cannot simply recite regional differences 
as the basis for not establishing broader criteria. However, PJM 
contends that ITC Companies' argument regarding the Joint Operating 
Agreement is likely premised on the fact that their project was not 
selected in the RTOs' respective regional transmission plans. In its 
reply, Southern California Edison argues that adopting a pro forma 
agreement is not workable because planning coordination differs 
significantly at each RTO/ISO and among vertically integrated 
utilities.
    428. Pennsylvania PUC suggests that the joint operating agreement 
between PJM and MISO, which includes a section on coordinated regional 
transmission planning requirements, could serve as a model for 
neighboring transmission regions negotiating bilateral coordination 
agreements. Pennsylvania PUC warns, however, that the joint operating 
agreement between PJM and MISO may require improvement in both content 
and operation with regard to interregional transmission planning and 
construction.
    429. PJM requests that, before requiring greater interregional 
coordination, the Commission clarify whether it will continue to allow 
regional differences in transmission planning processes or it intends 
to require greater standardization among regional planning processes to 
achieve interregional coordination. Old Dominion agrees, recommending 
that the Commission provide guidance addressing the extent to which 
regional differences can be modified to enhance interregional 
transmission planning--potentially by requiring an interim compliance 
measure where regions report to the Commission on their progress, 
identify differences in regional transmission planning and/or cost 
allocation, and request guidance where needed. Southern Companies 
states on reply that, while they have no objection to the Commission 
encouraging additional coordination, the Commission should not attempt 
to mandate (directly or indirectly) uniformity or standardization. 
Other commenters urge flexibility to accommodate regional 
differences.\355\
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    \355\ E.g., California Commissions; Dayton Power and Light; and 
NARUC.
---------------------------------------------------------------------------

    430. Several commenters emphasize the need for more consistent data 
formats, modeling, planning assumptions, planning standards and 
protocols, and evaluation procedures and metrics (among other elements 
of and tools used in the transmission planning process) between 
transmission planning regions or for use in interregional transmission 
planning to ensure that the proposed reforms are effective.\356\ East 
Texas Cooperatives cite examples of inconsistent metrics and 
assumptions that they contend have hindered effective interregional 
planning between SPP and Entergy, including the use of: (1) Different 
metrics to calculate available flowgate capacity at the seams; (2) 
different planning horizons; and (3) different types of proposed 
transmission upgrades in the long-term models for granting transmission 
service. Exelon asks the Commission to require the use of the same 
modeling assumptions and planning criteria, which should reflect actual 
expected operating conditions, when studying the impacts of a proposed 
interregional transmission facility on the reliability and congestion 
of neighboring systems. WIRES argues for the establishment of common 
interregional planning protocols by the Commission that can be employed 
by planners and stakeholders to guide development of interregional 
agreements on data, assumptions, and procedures that will be the 
foundation of genuine interregional planning processes. ITC Companies 
also recommends that the Commission require common assumptions and 
goals for long-term planning. Minnesota PUC and Minnesota Office of 
Energy Security recommend that project sponsors be required to provide 
usable data to all transmission planning entities that must study their 
projects.
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    \356\ E.g., WIRES; Wisconsin Electric Power Company; Pioneer 
Transmission; Organization of MISO States; Pennsylvania PUC; 26 
Public Interest Organizations; East Texas Cooperatives; and ITC 
Companies.
---------------------------------------------------------------------------

    431. Several commenters express concern that interregional planning 
processes could occur at different times and argue that a timeline 
should be established such that all planning regions consider 
interregional projects using the same timeline.\357\ MidAmerican argues 
that interregional planning should be undertaken on a common time 
horizon, such as 20 years or longer. Organization of MISO States 
recommends that the Commission consider requiring the establishment of 
deadlines for submitting an interregional project for joint evaluation 
to avoid any negative impacts on each individual transmission planning 
region's planning process. ISO New England, however, argues against 
requiring interregional projects to be evaluated simultaneously by both 
regions or in joint sessions of both regions' stakeholders, asking 
instead that sequential evaluation by each region be allowed. Pioneer 
Transmission opposes sequential evaluation and recommends that the 
Commission require that interregional transmission planning agreements 
include specific milestones to ensure that proposed interregional 
projects are evaluated in a timely manner. Pioneer Transmission 
cautions, however, that interregional projects already before a 
transmission planning region should not be required to start over, 
which could possibly delay the overall evaluation process. MISO 
Transmission Owners agree that the proposed requirement should not 
interfere with existing transmission planning cycles.
---------------------------------------------------------------------------

    \357\ E.g., Indianapolis Power & Light; California ISO; 
Organization of MISO States; and Solar Energy Industries and Large-
scale Solar.
---------------------------------------------------------------------------

    432. American Transmission and the MISO Transmission Owners further 
recommend that interregional coordination procedures must allow for 
``out-of-cycle'' reviews of interregional projects to address 
reliability issues. However, Wisconsin Electric Power Company suggests 
that the Commission require that adjacent planning regions align the 
timelines of their regional transmission planning processes to 
facilitate interregional coordination.
    433. Several commenters support the Commission's proposed 
requirement that a proposed interregional transmission project must be 
included in each relevant regional transmission plan to be subject to 
the interregional cost allocation method.\358\ Duke supports the 
proposed requirement

[[Page 49913]]

subject to the acknowledgement that inclusion in a plan does not mean 
that a given project will be constructed. Connecticut & Rhode Island 
Commissions contend that a region should not be required to accept an 
allocation of a transmission facility's costs unless the region 
approved the facility in its planning process and has identified 
concrete benefits that would accrue to the region. Organization of MISO 
States asks the Commission to clarify what would happen if, after 
neighboring regions' joint evaluation of a proposed interregional 
project, the project were found to benefit one region, but not the 
other. New England States Committee on Electricity supports the 
Commission's approach to interregional coordination as long as 
interregional transmission projects sponsored by one region will not be 
imposed involuntarily on another region. However, Anbaric and 
PowerBridge suggest that, once selected to go ahead, an interregional 
transmission project should bypass the planning region's normal 
procedures and be assigned to an interregional team to expedite and 
oversee the project, to ensure timely development of the facilities.
---------------------------------------------------------------------------

    \358\ E.g., New York ISO; New York Transmission Owners; and 
Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    434. First Wind suggests that a region from which renewable energy 
is to be exported may not experience reliability, economic, or public 
policy benefits as a result of an interregional transmission project 
and, thus, the exporting region may not include the project in its 
regional transmission plan. To ensure that renewable resources are able 
to access markets in which they can command the best price, First Wind 
suggests that the regional state committee representing the importing 
region be able to identify that an interregional transmission project 
is necessary to achieve public policy objectives and consequently have 
it included in the exporting region's regional transmission plan.
ii. Commission Determination
    435. The Commission 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. The establishment of a procedure by which a public utility 
transmission provider will identify and jointly evaluate is necessary 
for facilitating the identification of interregional solutions that may 
resolve each region's needs more efficiently or cost-effectively. As a 
result, the Commission and transmission customers will have greater 
certainty that the transmission facilities in each regional 
transmission plan are the more efficient and cost-effective solutions 
to meet the region's needs.
    436. The Commission also requires 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 the 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 process, will jointly evaluate the 
proposed transmission project. This joint evaluation must be conducted 
in the same general timeframe as, rather than subsequent to, each 
transmission planning region's individual consideration of the proposed 
transmission project. Finally, for an interregional transmission 
facility to receive cost allocation under the interregional cost 
allocation method or methods developed pursuant to this Final Rule, the 
transmission facility must be selected in both of the relevant regional 
transmission planning processes for purposes of cost allocation.
    437. Some commenters such as ISO/RTO Council express concern that 
joint evaluation of proposed interregional transmission facilities 
could involve the creation of a new set of planning criteria, while 
others such as Exelon stress the need for greater consistency in 
planning criteria and modeling assumptions used by neighboring regions. 
As a general matter, we note 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. We therefore 
direct, as part of compliance with the interregional transmission 
coordination requirements, that each public utility transmission 
provider, through its transmission planning region, develop procedures 
by which such differences can be identified and resolved for purposes 
of jointly evaluating the proposed interregional transmission facility. 
We leave to each pair of neighboring regions, however, discretion in 
the way this requirement is designed and implemented and do not require 
that any particular planning horizons or criteria be used. In response 
to Minnesota PUC and Minnesota Office of Energy Security, we discuss in 
the opportunities for discrimination against non-incumbent transmission 
developers section the information that a transmission developer must 
provide to the transmission planning region in support of its 
transmission project proposal.\359\
---------------------------------------------------------------------------

    \359\ See discussion supra section III.B.3.d.ii.
---------------------------------------------------------------------------

    438. Some commenters argue that the Commission should establish the 
timeframe within which regions must jointly evaluate interregional 
transmission projects. The Commission declines to specify a timeline 
for the interregional transmission coordination procedures or a 
deadline by which all interregional transmission projects must be 
submitted. Instead, the Commission expects public utility transmission 
providers in neighboring transmission planning regions to cooperate and 
develop timelines that allow for coordination and joint evaluation of 
interregional transmission projects in the same general time frame as 
each region's consideration of the transmission project. Furthermore, 
we disagree with those commenters that argue that there should be 
sequential evaluation of transmission projects, as opposed to 
evaluation on the regional and interregional levels in the same general 
time frame. However, we clarify for ISO New England that we will not 
require that interregional transmission projects be evaluated 
simultaneously by both regions or in joint sessions of both regions' 
stakeholders.
    439. Rather, we require that both regions conduct joint evaluation 
of an interregional transmission project in the same general timeframe. 
By same general time frame, the Commission expects public utility 
transmission providers to develop a timeline that provides a meaningful 
opportunity to review and evaluate through the interregional 
transmission coordination procedures information developed through the 
regional transmission planning process and, similarly, provides a 
meaningful opportunity to review and use in the regional transmission 
planning process information developed in the interregional 
transmission coordination procedures. Rather than provide further 
detailed guidance on this matter in this Final Rule that may unduly 
constrain the planning time line of each region for purposes of 
coordination with one or several neighboring regions, we prefer in the 
first instance to permit regions to develop appropriate timing 
arrangements with neighbors, which we will review on compliance.
    440. American Transmission and the MISO Transmission Owners

[[Page 49914]]

recommend that interregional transmission coordination procedures must 
allow for ``out-of-cycle'' reviews of interregional transmission 
projects to address reliability issues. The Commission believes that a 
requirement for ongoing constant reviews without regard to a defined 
planning cycle would be too burdensome. This Final Rule does not 
require such an ``out-of-cycle'' review, nor does it prohibit a region 
or a pair of regions from doing so, for example if necessary to address 
a pressing reliability issue. Additionally, while the creation of a new 
planning cycle may be unnecessary, the Commission is requiring that 
coordination and joint evaluation must be conducted in the same general 
time frame as, rather than subsequent to, each transmission planning 
region's individual consideration of the proposed transmission project.
    441. Furthermore, we decline to adopt suggestions to require 
adjacent transmission planning regions to align the timelines of their 
regional transmission planning processes. The Commission is providing 
flexibility, subject to certain requirements, in the design and 
implementation of procedures to govern the joint evaluation of 
interregional transmission facilities by neighboring transmission 
planning regions. To the extent public utility transmission providers 
in neighboring transmission planning regions identify changes to their 
regional transmission planning processes that are necessitated by 
implementation of interregional transmission coordination procedures, 
those transmission providers should implement those changes as part of 
their compliance filings submitted in response to this Final Rule.
    442. In response to New England States Committee on Electricity's 
comment that interregional transmission coordination should begin with 
and respect the regional transmission planning process and resulting 
regional transmission plan, we note that we require in this Final Rule 
that the developer of a transmission project that would be located in 
more than one transmission planning region first must propose its 
transmission project in the regional transmission planning process of 
each of those transmission planning regions. We expect each 
transmission planning region's review of that transmission project to 
be informed by and closely coordinated with the interregional 
transmission coordination procedures. Furthermore, the Commission did 
not propose in the Proposed Rule, and will not require in this Final 
Rule, that interregional transmission coordination procedures provide 
for the costs of an interregional transmission project sponsored by one 
transmission planning region to be involuntarily imposed on another 
transmission planning region.
    443. Finally, the Commission agrees with Duke that having an 
interregional transmission facility in a regional transmission plan 
does not mean that it will be constructed. As in Order No. 890, the 
goal of this Final Rule is to establish procedures by which neighboring 
transmission planning regions will coordinate to jointly evaluate 
proposed transmission facilities, not to dictate which investment must 
be made or transmission projects must be built.\360\ In response to 
Connecticut & Rhode Island Commissions, the Commission clarifies that 
public utility transmission providers in a transmission planning region 
will not be required to accept allocation of the costs of an 
interregional transmission project unless the region has selected such 
transmission facility in the regional transmission plan for purposes of 
cost allocation. That is, based on the information gained during the 
joint evaluation of an interregional transmission project, each 
transmission planning region will determine, for itself, whether to 
select those transmission facilities within its footprint in the 
regional transmission plan for purposes of cost allocation. Whether a 
transmission planning region would decide to select an interregional 
transmission facility in its regional transmission plan likely would be 
driven by the relative costs and benefits of the transmission project 
to that region. The Commission believes this effectively provides the 
``feedback loop'' sought by Old Dominion.
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    \360\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 438.
---------------------------------------------------------------------------

    444. The Commission declines to adopt the suggestion by Anbaric and 
PowerBridge that an interregional transmission project resulting from 
the interregional transmission coordination procedures be allowed to 
bypass the relevant regions' transmission planning processes and be 
automatically assigned to an interregional team. However, we do not 
preclude the public utility transmission providers in a pair of 
transmission planning regions from creating a separate process for 
developing interregional transmission facilities that have been in each 
relevant transmission planning region's plan. Instead, we provide 
transmission planning regions with flexibility to determine how to 
address an interregional transmission project. We reiterate that, to be 
eligible for interregional cost allocation, the interregional 
transmission facility must be selected in the regional transmission 
plan for purposes of cost allocation in each of the transmission 
planning regions in which the transmission facility is proposed to be 
located.
    445. Beyond the clarifications provided above, we decline to 
address the remaining requests to further delineate how neighboring 
transmission regions must jointly evaluate proposed interregional 
transmission facilities because such action could inadvertently impose 
requirements that are not appropriate for particular regions. Given the 
flexibility we have provided to public utility transmission providers 
in implementing the interregional transmission coordination 
requirements, the Commission determines it is unnecessary to adopt 
interim compliance requirements or other processes such as those 
suggested by Old Dominion.
    446. We decline to adopt First Wind's suggestion that a 
transmission planning region should be required to include a 
transmission project intended to export renewable energy resources in 
its regional transmission plan if the regional state committee 
representing the importing region identifies the transmission project 
as necessary to achieve a public policy objective. As discussed above, 
whether an interregional transmission facility is to be selected in the 
regional transmission plan for purposes of cost allocation is a 
decision left to each transmission planning region. However, we will 
not preclude public utility transmission providers in neighboring 
transmission planning regions from voluntarily developing procedures 
such as those proposed by First Wind should they agree to do so as part 
of their interregional transmission coordination efforts.
    447. In response to commenters' recommendations that the Commission 
provide for regional flexibility in developing and implementing 
interregional transmission coordination, we reiterate the Commission's 
encouragement in the Proposed Rule that interregional transmission 
coordination procedures be tailored to best fit the needs of the public 
utility transmission providers in the regions involved while also 
meeting certain minimum requirements.\361\
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    \361\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 117.
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    448. Furthermore, as urged by PUC of Nevada, we are cognizant of 
existing

[[Page 49915]]

interregional transmission coordination efforts and, by providing 
regional flexibility, intend to accommodate their various 
organizational structures, as suggested by WestConnect Planning 
Parties. Consistent with this approach, any public utility transmission 
provider that believes its existing interregional transmission 
coordination procedures, including those found in any interregional 
transmission planning agreement, already comply with the requirements 
of this Final Rule may indicate in its compliance filing how its 
existing procedures meet each requirement. If the existing procedures 
do not meet all of the requirements, the public utility transmission 
provider may propose revisions to its existing interregional 
transmission coordination procedures so that the procedures comply with 
this Final Rule.
    449. Because we want to allow for regional flexibility, we decline 
to adopt commenters' suggestions that the Commission develop pro forma 
interregional transmission coordination procedures or impose additional 
requirements as to what interregional transmission coordination should 
entail. As noted by Southern California Edison, planning coordination 
differs significantly at each RTO and ISO and among vertically 
integrated utilities, and we thus determine that pro forma 
interregional transmission coordination procedures are not appropriate 
at this time because it may not accommodate the differences among 
existing transmission planning regions. Moreover, the requirements that 
we adopt as interregional transmission coordination requirements in 
this Final Rule should be adequate guidance for public utility 
transmission providers.
    450. We also note the Pennsylvania PUC's suggestion that the joint 
operating agreement between PJM and MISO, which includes a section on 
coordinated regional transmission planning requirements, could serve as 
a model for neighboring transmission planning regions negotiating 
bilateral coordination agreements. While we generally agree that 
various existing transmission planning agreements between regions may 
serve as models, we note that existing agreements reflect the needs of 
the regions that negotiated them. Thus, the Commission declines to 
require public utility transmission providers to adopt or model their 
coordination procedures on any particular agreement to coordinate 
transmission planning between two regions.
b. Data Exchange
i. Comments
    451. American Transmission supports the Proposed Rule's requirement 
that interregional transmission planning agreements include an 
agreement to exchange planning data and information at least annually. 
American Transmission states that this requirement would help ensure 
that neighboring regions are aware of planning considerations as well 
as any transmission issues in neighboring regions. It also recommends 
that the Commission establish a time frame for a neighboring 
transmission planning region to respond to a transmission provider's 
request for planning information and data. SPP recommends that the 
Commission require interregional transmission planning agreements to 
include the specific procedures for sharing such information rather 
than only an agreement to do so.
    452. Several commenters state that this exchange should be required 
to occur more often than annually.\362\ NextEra states that the 
Commission should require the exchange of planning data and information 
at least as frequently as warranted by any material developments that 
either affect any neighboring region or interregional facility or may 
influence any interregional transmission plan. Organization of MISO 
States recommends that the Commission modify this element to require 
exchange of planning data and information at least semi-annually 
because transmission planning analysis can change over the course of a 
planning cycle due in part to changing modeling results and stakeholder 
input. Minnesota PUC and Minnesota Office of Energy Security recommend 
that the Commission require planning data and information exchanges 
between transmission planning regions to occur semi-annually to account 
for those project proposals that are requested to be reviewed out-of-
cycle.
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    \362\ E.g., Minnesota PUC and Minnesota Office of Energy 
Security; NextEra; and Organization of MISO States.
---------------------------------------------------------------------------

    453. Transmission Dependent Utility Systems and Pennsylvania PUC 
express concern that this proposed element does not consider 
differences in the planning processes of each region. For example, 
Transmission Dependent Utility Systems state that the proposed planning 
data and information exchange requirement may be inadequate to address 
interregional transmission infrastructure concerns, and that 
transmission providers and stakeholders should be permitted to 
determine the type and frequency of meetings and planning information 
exchanges. Likewise, Pennsylvania PUC states that this requirement 
should accommodate different transmission planning regions' planning 
cycles.
ii. Commission Determination
    454. The Commission requires each public utility transmission 
provider, through its regional transmission planning process, to adopt 
interregional transmission coordination procedures that provide for the 
exchange of planning data and information at least annually. The 
sharing of data at least once a year will ensure that neighboring 
transmission planning regions are aware of each others' transmission 
plans and the assumptions and analysis that support such plans. In 
response to arguments that the Commission should require neighboring 
transmission planning regions to exchange data more frequently, we note 
that this Final Rule provides that this information must be exchanged 
at least annually, thereby allowing each public utility transmission 
provider through its transmission planning region, the flexibility to 
decide to exchange information more frequently. If a pair of 
transmission planning regions anticipates that more frequent exchanges 
of planning data and information would improve interregional 
transmission coordination, then we encourage them to provide for such 
exchanges in their interregional transmission coordination procedures.
    455. We agree with SPP that interregional transmission coordination 
procedures must include the specific obligations for sharing planning 
data and information rather than only an agreement to do so. A clear 
description of the procedures that will be used to exchange planning 
data and information will help the Commission, transmission customers, 
and other stakeholders to better determine if each public utility 
transmission provider is fulfilling its obligations consistent with 
this Final Rule. However, we will not dictate the specific procedures 
or the level of detail for the procedures pursuant to which planning 
data and information must be exchanged. Consistent with the comments of 
Transmission Dependent Utility Systems and Pennsylvania PUC, we allow 
each public utility transmission provider, through its transmission 
planning region, to develop procedures to exchange planning data and 
information, which we anticipate will reflect the type and frequency of 
meetings that are appropriate for each pair of regions and

[[Page 49916]]

will accommodate each pair of region's planning cycles.
c. Transparency
i. Comments
    456. Pennsylvania PUC supports the proposed requirement that 
interregional transmission planning agreements include a commitment to 
maintain a Web site or e-mail list for the communication of information 
related to the coordinated planning process. Duke requests the 
Commission clarify that information relating to the interregional 
transmission planning process can be maintained on an existing 
transmission provider's Web site or regional transmission planning Web 
site.
    457. In addition, MISO Transmission Owners suggest that all 
transmission providers offering transmission service or interconnection 
service under a tariff (including a non-jurisdictional tariff) should 
be required to make publicly available their business practice manuals 
or other documentation specifically detailing the assumptions and 
criteria used in comparably evaluating all proposed transmission and 
generation projects, including the identification and treatment of 
third-party impacts.
ii. Commission Determination
    458. The Commission requires public utility transmission providers, 
either individually or through their transmission planning region, to 
maintain a Web site or e-mail list for the communication of information 
related to interregional transmission coordination procedures. The 
Commission clarifies that information related to interregional 
transmission coordination may be maintained on an existing public 
utility transmission provider's Web site or a regional transmission 
planning Web site. However, the information should be posted in such a 
way that stakeholders are able to distinguish between information 
related to interregional transmission coordination and information 
related to regional transmission planning.
d. Stakeholder Participation
i. Commission Proposal
    459. In the Proposed Rule, the Commission did not specifically 
address the issue of stakeholder participation with regard to the 
coordination of transmission planning activities undertaken by 
neighboring transmission regions.
ii. Comments
    460. Some commenters discuss the need for utilities and 
stakeholders to participate in the process of developing interregional 
planning agreements. Transmission Access Policy Study Group states that 
interregional transmission planning agreements must be inclusive, open, 
and collaborative. Both Transmission Access Policy Study Group and East 
Texas Cooperatives state that transmission dependent utilities should 
have the opportunity to participate in their development and 
implementation. Transmission Access Policy Study Group states that, 
without such a requirement, the Commission would not be fulfilling its 
responsibility under FPA section 217(b)(4) to facilitate planning to 
meet the needs of all load-serving entities. Wisconsin Electric Power 
Company requests that the Commission explicitly ensure that 
stakeholders have the opportunity to participate in the development of 
these agreements.
    461. Some commenters contend that the interregional transmission 
planning requirements described in the Proposed Rule could be 
significantly improved with respect to stakeholder participation. New 
York PSC states that the Commission should articulate that meaningful 
participation in the planning process is necessary, including the 
opportunity to provide input concerning how studies are conducted and 
solutions are identified. Transmission Dependent Utility Systems 
contend that it is just as important for transmission customers to be 
able to participate in interregional transmission planning as it is for 
them to be able to participate in regional transmission planning.
    462. Integrys states that because stakeholder involvement and input 
is necessary to ensure proper planning and evaluation of projects, the 
Commission should adopt a stakeholder participation requirement in any 
Final Rule. Xcel states that the interregional coordination necessary 
to support the development of larger-scale, interregional transmission 
projects (particularly those that are needed to integrate renewable 
energy resources) must engage stakeholders, and especially state 
regulatory agencies, in the development of processes that address the 
specific needs and requirements of the participating regions. Without 
the involvement of state agencies, which ultimately decide which 
transmission facility will be built, Xcel contends that interregional 
transmission planning processes will not result in the construction of 
needed transmission.
    463. Energy Future Coalition states that interregional transmission 
planning must be both participatory and analytically robust by engaging 
all interested parties, including utilities, states, renewable 
generation developers, environmental interests, and consumer interests.
    464. Some commenters express concern that, even if the proposed 
interregional transmission planning requirements provide for 
stakeholder participation, such participation can require significant 
resources from stakeholders. NARUC and Massachusetts Departments claim 
that limited human resources and budgets make it difficult for state 
commissions and other stakeholders to participate in additional 
transmission planning processes. Massachusetts Departments suggest that 
any Final Rule should take these challenges into account and consider 
mechanisms to address them. Similarly, California Commissions comment 
that states must have access to adequate resources to support state 
involvement in interregional coordination processes and that the 
Commission could consider requiring stakeholder support beyond that 
provided through the ARRA-funded interconnectionwide transmission 
planning initiatives.
iii. Commission Determination
    465. We agree with those commenters that argue stakeholder 
participation is an important component in interregional transmission 
coordination to ensure the goals of improving coordination between 
neighboring transmission planning regions and identifying interregional 
transmission facilities that can address transmission needs more 
efficiently or cost-effectively than separate intraregional 
transmission facilities. However, this Final Rule does not require the 
interregional transmission coordination procedure to meet the 
requirements of the planning principles required for local planning 
(under Order No. 890) and regional planning (under this Final 
Rule).\363\ Because we require in this Final Rule that an interregional 
transmission facility must be selected in each relevant regional 
transmission plan for purposes of cost allocation to be eligible for 
interregional cost allocation, stakeholders will have the opportunity 
to participate fully in the consideration of interregional transmission 
facilities during the regional transmission

[[Page 49917]]

planning process.\364\ Furthermore, we believe that stakeholder 
participation in the various regional transmission planning processes 
will enhance the effectiveness of interregional transmission 
coordination. To facilitate stakeholder involvement, this Final Rule 
requires the 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.\365\
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    \363\ Of course, nothing precludes public utility transmission 
providers in neighboring transmission planning regions from choosing 
to meet those requirements.
    \364\ See discussion supra P 0.
    \365\ This information must be made available subject to 
appropriate confidentiality protections and CEII requirements.
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    466. We also agree with commenters that discuss the importance of 
transmission customer and stakeholder participation in the development 
of the interregional transmission coordination procedures necessary to 
comply with the requirements in this Final Rule. Therefore, we require 
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.
    467. The Commission appreciates the concerns of NARUC and others 
regarding the effect budgetary limitations could have on effective 
stakeholder participation in interregional transmission coordination 
activities. As discussed above in the regional transmission planning 
section \366\ and consistent with Order No. 890, to the extent that 
public utility transmission providers choose to include a funding 
mechanism to facilitate the participation of state consumer advocates 
or other stakeholders in the regional transmission planning process, 
nothing in this Final Rule precludes them from doing so.
---------------------------------------------------------------------------

    \366\ See discussion supra section III.A.3.
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e. Tariff Provisions and Agreements for Interregional Transmission 
Coordination
i. Commission Proposal
    468. In the Proposed Rule, the Commission proposed to require that 
coordination between neighboring transmission planning regions be 
reflected in an interregional transmission planning agreement to be 
filed with the Commission.\367\
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    \367\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 114.
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ii. Comments
    469. Several commenters express support for the Commission's 
proposal to require neighboring regions to enter into interregional 
transmission planning agreements.\368\ They also emphasize, however, 
that planning regions should be able to structure planning agreements 
so that each region is a full, equal partner and no region can force 
projects or costs onto other regions in a manner that is inconsistent 
with the agreement. Edison Electric Institute further emphasizes that 
these planning agreements cannot replace strong interregional 
coordination to address interregional impacts.
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    \368\ E.g., National Grid; New York Transmission Owners; and 
Edison Electric Institute.
---------------------------------------------------------------------------

    470. Other commenters argue that the Commission should accept the 
submission of existing interregional agreements, with necessary 
modifications, to comply with the Final Rule.\369\ American 
Transmission and MISO Transmission Owners state that when reviewing 
existing interregional agreements to determine their compliance with 
the Final Rule, if the Commission determines that modifications to 
these agreements are necessary, the public utility transmission 
providers and their stakeholders should be given the opportunity to 
address and submit revisions.
---------------------------------------------------------------------------

    \369\ E.g., FirstEnergy Service Company; American Transmission; 
and MISO Transmission Owners.
---------------------------------------------------------------------------

    471. Some commenters suggest that interregional coordination 
procedures should be incorporated into public utility transmission 
providers' OATTs. Ad Hoc Coalition of Southeastern Utilities suggests 
that as an alternative to the interregional agreement, the Commission 
should consider adopting an additional planning principle that permits 
public utility transmission providers to explain how they address the 
types of matters that the Proposed Rule would require to be included in 
such interregional agreements. ColumbiaGrid further contends that 
transmission providers in the Western Interconnection should be 
required to include in their OATTs only the regional planning group and 
WECC processes and information regarding their existing relationship, 
and that they should not be required to divert resources to developing 
formal agreements to be filed with the Commission. Bonneville Power 
suggests that the Commission require transmission providers to include 
coordination requirements as part of the transmission planning 
processes outlined in their OATTs, but without specific details about 
how individual projects would be planned and developed. It states that 
this would allow transmission providers to enter into voluntary 
agreements and to focus on developing higher priority projects. 
Transmission Dependent Utility Systems state that each public utility 
transmission provider's interregional transmission planning process 
should be included in the OATT, subject to effective Commission and 
stakeholder scrutiny on an ongoing basis.
    472. California ISO also contends the proposed requirements are 
problematic for the ISO in that it would not be able to develop an 
interregional transmission planning agreement applicable to all of its 
neighboring balancing authority areas because many of its neighboring 
balancing authorities have different legal charters and are subject to 
different laws, regulations, and requirements.
    473. Several commenters raised concerns about the proposed 
interregional transmission planning agreements with respect to non-
jurisdictional transmission providers. Western Area Power 
Administration requests that the Final Rule acknowledge that 
interregional transmission planning-related agreements would need to 
account for the status and statutory requirements of non-public utility 
transmission providers before they may be executed. Large Public Power 
Council states its members will commit to voluntarily participate in 
interregional transmission planning processes, but that its members 
have limited authority to enter into agreements that include, among 
other things, an obligation to pay construction costs or a requirement 
to defer to regional or interregional planning authorities. Omaha 
Public Power District states that it plans to participate voluntarily 
in an interregional transmission planning process, but notes that its 
agreements to do so would not be subject to the Commission's 
jurisdiction or enforcement. Nebraska Public Power District expresses 
the same concerns regarding the lack of clarity in the commitments that 
it would be required to make as a result of the proposed interregional 
transmission planning agreements. Nebraska Public Power District also 
commits to participate in interregional transmission planning 
processes; however, it contends that it cannot make such commitment 
outside of its current RTO membership and the related protection 
against violating state law and that its authority to enter into 
binding agreements is limited consistent with state sovereignty.\370\
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    \370\ Comments addressing specific statutory provisions that may 
limit non-jurisdictional participation in this regard are addressed 
in the discussion of the Commission's legal authority to undertake 
reforms regarding regional transmission planning. See discussion 
infra section III.A.2 of this Final Rule.

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[[Page 49918]]

    474. Several commenters argue that the Commission should require 
non-jurisdictional entities to comply with the proposed interregional 
transmission planning requirements. Westar states that power flows on a 
non-jurisdictional entity's system can affect facilities in a 
jurisdictional entity's system, and vice-versa. Similarly, MISO 
Transmission Owners state that requiring non-jurisdictional entities to 
participate would ensure effective interregional transmission planning 
and coordination and address seams issues. NextEra states that to 
facilitate broad-based participation by all relevant entities, the 
Commission should invoke its authority under FPA section 211A to 
require unregulated transmitting utilities to participate in the 
interregional transmission planning process.
iii. Commission Determination
    475. In light of the comments received, the Commission declines to 
require that coordination between the public utility transmission 
providers in pairs of neighboring transmission planning regions be 
reflected in a formal interregional transmission planning agreement 
filed with the Commission, as was proposed in the Proposed Rule. 
Instead, as recommended in part by Ad Hoc Coalition of Southeastern 
Utilities, ColumbiaGrid, Bonneville Power, and Transmission Dependent 
Utility Systems, we require 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.\371\ Alternatively, if the public utility transmission 
providers so choose, these procedures may be reflected in an 
interregional transmission coordination agreement filed on compliance 
for approval by the Commission.\372\
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    \371\ Consistent with the approach taken in Order Nos. 890 and 
890-A, public utility transmission providers may use Web-posted 
business practice manuals to describe planning-related processes. 
See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 1653; Order No. 
890-A, FERC Stats. & Regs. ] 31,261 at P 990.
    \372\ However, even if a public utility transmission provider 
voluntarily enters into such an agreement, its OATT must still 
provide enough description for stakeholders to follow how 
interregional transmission coordination will be conducted, with 
links included to the actual agreement where the details can be 
found. See United States Dep't of Energy--Bonneville Power Admin., 
124 FERC ] 61,054, at P 65 (2008) (requiring Avista, Puget and 
Bonneville Power ``to provid[e] additional detail in their 
Attachment Ks on the WECC's [Transmission Expansion Planning Policy 
Committee's] process or providing direct links (i.e., URLs) to the 
appropriate documents on the WECC Web site where the processes to 
coordinate information and planning efforts [between several 
regional planning groups] are discussed'').
---------------------------------------------------------------------------

    476. We find that implementing the interregional transmission 
coordination requirements in this Final Rule through their 
incorporation in each public utility transmission provider's OATT, 
instead of requiring an interregional transmission planning agreement, 
will fulfill our objective to improve interregional transmission 
coordination and provide adequate transparency with regard to the 
obligations imposed on public utility transmission providers. Further, 
commenters persuade us that this approach would facilitate the 
participation of non-public utility transmission providers in an 
interregional transmission coordination efforts.
    477. In response to commenters' arguments that the Commission 
should accept the submission of existing interregional agreements on 
compliance, we agree provided the compliance filing explains how the 
existing agreement satisfies the requirements of this Final Rule. The 
Commission will address the adequacy of such an existing agreement on 
compliance.
    478. We decline to adopt Bonneville Power's recommendation that 
these procedures omit specific details about how individual 
transmission projects would be planned and developed, because we 
require each set of interregional transmission coordination procedures 
to include a formal procedure to identify and jointly evaluate 
transmission facilities that are proposed to be located in both 
transmission planning regions.
    479. We do not find convincing California ISO's argument that it 
will be problematic for it to develop interregional transmission 
coordination procedures with all of its neighboring balancing authority 
areas due to the differences among them. Just as reliable transmission 
operation of interconnected transmission systems requires coordination 
among neighboring utilities and regions--some of which is required by 
mandatory reliability standards, transmission planning of 
interconnected transmission systems requires some degree of 
coordination among neighboring utilities and regions. We conclude that 
this Final Rule provides for sufficient regional flexibility to allow 
the California ISO to develop in cooperation with its neighboring 
balancing authority areas interregional transmission coordination 
procedures that accommodate their differences.
    480. We agree with commenters that interregional transmission 
coordination should be structured in such a way that no public utility 
transmission provider in a transmission planning region should be 
permitted to force transmission projects or costs onto another region 
contrary to the agreed upon interregional transmission coordination 
procedures incorporated into the relevant public utility transmission 
providers' OATTs pursuant to this Final Rule.
    481. Because we are implementing the interregional transmission 
coordination requirements adopted in this Final Rule through 
incorporation of the same language into each public utility 
transmission provider's OATT rather than through formal agreements, we 
find comments presenting concerns that non-public utility transmission 
providers are unable to be party to interregional transmission planning 
agreements to be moot. Furthermore, we do not believe that it is 
necessary to address here those commenters that ask us to require non-
public utility transmission providers to participate in interregional 
transmission coordination efforts. We believe such concerns are 
premature, as we are encouraged by the non-public utility transmission 
providers who expressed their intent to participate in interregional 
transmission coordination efforts in their comments in response to the 
Proposed Rule. Additional discussion of non-public utility transmission 
provider participation in the reforms adopted in this Final Rule, 
including the interregional transmission coordination requirements, is 
in the reciprocity section below.\373\
---------------------------------------------------------------------------

    \373\ See discussion infra section V.B.
---------------------------------------------------------------------------

IV. Proposed Reforms: Cost Allocation

    482. The Commission requires, as part of this Final Rule, that each 
public utility transmission provider have in its OATT a method, or set 
of methods, for allocating the costs of new transmission facilities 
selected in the regional transmission plan (``regional cost 
allocation''); and that each public utility transmission provider 
within a transmission planning region develop a method or set of 
methods for allocating the costs of new interregional transmission 
facilities that two (or more) neighboring transmission planning regions 
determine resolve the individual needs of each region more efficiently

[[Page 49919]]

and cost-effectively (``interregional cost allocation''). The OATTs of 
all public utility transmission providers in a region must include the 
same cost allocation method or methods adopted by the region. Each of 
the regional cost allocation and interregional cost allocation methods 
must adhere to the respective general cost allocation principles as set 
forth below.\374\ Subject to these general cost allocation principles, 
public utility transmission providers in consultation with stakeholders 
have the opportunity to develop the appropriate cost allocation methods 
for their new regional and interregional transmission facilities. In 
the event that no agreement among public utility transmission providers 
in a region or pair of regions can be reached, the Commission will 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.
---------------------------------------------------------------------------

    \374\ For purposes of this Final Rule, a regional transmission 
facility is a transmission facility located entirely in one region. 
The Proposed Rule sometimes called such a facility a regional 
facility and sometimes an intraregional facility. 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.
---------------------------------------------------------------------------

    483. The requirements established below are designed to work in 
tandem with the transmission planning requirements established above 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 planning who would bear the costs 
of transmission facilities, if constructed.

A. Need for Reform Concerning Cost Allocation

1. Commission Proposal
    484. In the Proposed Rule, the Commission noted that its 
responsibility under sections 205 and 206 of the FPA to ensure that 
transmission rates are just and reasonable and not unduly 
discriminatory or preferential is not new, nor is the Commission's 
recognition of the cost causation principle. However, the Commission 
explained that the circumstances in which it must fulfill its statutory 
responsibilities change with developments in the industry, such as 
changes with respect to the demands placed on the grid. For example, 
the expansion of regional power markets has led to a growing need for 
new transmission facilities that cross several utility, RTO, ISO or 
other regions. Similarly, the increasing adoption of state resource 
policies, such as renewable portfolio standards, has contributed to the 
rapid growth of renewable energy resources that are frequently remote 
from load centers.
    485. The Commission stated that challenges associated with 
allocating the cost of transmission appear to have become more acute as 
the need for transmission infrastructure has grown. The Commission 
noted that constructing new transmission facilities requires a 
significant amount of capital and, therefore, a threshold consideration 
for any company considering investing in transmission is whether it 
will have a reasonable opportunity to recover its costs. The Commission 
explained, however, that there are few rate structures in place today 
that provide both for analysis of the beneficiaries of a transmission 
facility that is proposed to be located within a transmission planning 
region that is outside of an RTO or ISO, or in more than one 
transmission planning region, and for corresponding allocation and 
recovery of the facility's costs. The Commission stated that lack of 
such rate structures creates significant risk for transmission 
developers that they will have no identified group of customers from 
which to recover the cost of their investment. With regard to cost 
allocation within RTO or ISO regions, the Commission noted that cost 
allocation issues are often contentious and prone to litigation because 
it is difficult to reach an allocation of costs that is perceived as 
fair, particularly for RTOs and ISOs that encompass several states.
    486. The Commission further noted that the risk of the free rider 
problems associated with new transmission investment is particularly 
high for projects that affect multiple utilities' transmission systems 
and therefore may have multiple beneficiaries. With respect to such 
projects, any individual beneficiary has an incentive to defer 
investment in the hopes that other beneficiaries will value the project 
enough to fund its development. The Commission explained that, on one 
hand, a cost allocation method that relies exclusively on a participant 
funding approach,\375\ without respect to other beneficiaries of a 
transmission facility, increases this incentive and, in turn, the 
likelihood that needed transmission facilities will not be constructed 
in a timely manner. On the other hand, if costs would be allocated to 
entities that will receive no benefit from a transmission facility, 
then those entities are more likely to oppose selection of the facility 
in a regional transmission plan for purposes of cost allocation or to 
otherwise impose obstacles that delay or prevent the facility's 
construction.
---------------------------------------------------------------------------

    \375\ Under 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. The Proposed Rule cited 
several examples of regions relying principally or exclusively on 
the participant funding approach to cost allocation. Proposed Rule, 
FERC Stats. & Regs. ] 32,660 at P 128.
---------------------------------------------------------------------------

    487. In light of these challenges and recent developments affecting 
the industry, the Commission stated concern that existing cost 
allocation methods may not appropriately account for benefits 
associated with new transmission facilities and, thus, may result in 
rates that are not just and reasonable or are unduly discriminatory or 
preferential.\376\ The Commission proposed the cost allocation 
requirements discussed in further detail below to address this concern.
---------------------------------------------------------------------------

    \376\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 148-54.
---------------------------------------------------------------------------

2. Comments on Need for Reform
    488. A number of commenters generally support the cost allocation 
requirements proposed by the Commission.\377\ For example, ITC 
Companies state that the Commission has correctly concluded that reform 
with respect to transmission cost allocation methods is necessary. AWEA 
argues that issues related to cost allocation impede transmission 
development required to address increased demand, meet national energy 
and environmental goals, and create an intelligent, secure, and 
reliable transmission network. Clean Line argues that implementation of 
a cost allocation method is critical to the development of new 
infrastructure. Multiparty Commenters argue that a fair allocation of 
the costs of new transmission can be facilitated by acknowledging that 
the cost of transmission is a small portion of the delivered cost of 
electricity, generally ten percent or less, whereas the costs of a 
single project may be significant for the builders of that project. 
Solar Energy Industries urge the Commission to use its authority to 
alleviate impediments to building new transmission lines for renewable 
energy and other system needs to promote a robust competitive market 
that will benefit consumers and the environment.
---------------------------------------------------------------------------

    \377\ E.g., Transmission Access Policy Study Group; AWEA; 
Northeast Utilities; ITC Companies; Energy Future Coalition Group; 
MidAmerican; MISO; NextEra; E.ON Climate Renewables North America; 
Exelon; Iberdrola Renewables; WIRES; Western Grid Group; and 
Pennsylvania PUC.

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[[Page 49920]]

    489. Many commenters also support aligning transmission planning 
and cost allocation more closely.\378\ Transmission Dependent Utility 
Systems state that it is virtually impossible to separate transmission 
planning from transmission cost allocation. Exelon argues that fair, 
efficient, and legal cost allocation should follow the manner in which 
its system is planned. Integrys agrees with linking cost allocation 
rules with transmission planning, but cautions that the transmission 
planning process is not a substitute for the cost allocation process.
---------------------------------------------------------------------------

    \378\ E.g., Atlantic Grid; ITC Companies; Sunflower and Mid-
Kansas; MISO; Pennsylvania PUC; PHI Companies; Colorado Independent 
Energy Association; Energy Future Coalition Group; PSC of Wisconsin; 
CapX2020; and Wind Coalition.
---------------------------------------------------------------------------

    490. A number of commenters supporting closer alignment between 
planning and cost allocation state that existing ISO and RTO 
transmission planning and cost allocation processes already may satisfy 
the proposal to align transmission planning and cost allocation more 
closely.\379\ AEP and SPP believe that their existing transmission 
planning and cost allocation processes satisfy many of the Commission's 
proposed requirements. Similarly, MISO Transmission Owners state that 
cost allocation in MISO is already closely tied to the transmission 
planning process. Organization of MISO States points to MISO filings 
that address cost allocation issues.
---------------------------------------------------------------------------

    \379\ E.g., SPP; AEP; MISO Transmission Owners; Organization of 
MISO States; California PUC; and Pacific Gas & Electric.
---------------------------------------------------------------------------

    491. WIRES asks the Commission to ensure that the planning process 
not be unduly influenced by those that seek to redirect potential cost 
allocation liability. Illinois Commerce Commission believes it is 
unduly discriminatory for a state to be required to bear costs for 
transmission expansion projects under a cost sharing arrangement but 
have no decisional authority for projects outside their state. Where a 
regional state committee exists, Illinois Commerce Commission 
recommends that a process be carved out by which the regional state 
committee's board of directors has the opportunity to review and decide 
on the reasonableness of each of the RTO's proposed transmission 
expansion projects for which regional cost allocation would apply.
    492. A number of commenters express concern with the Commission's 
proposal to impose generic regional and interregional cost allocation 
requirements.\380\ Some commenters argue specifically that there is no 
need for the Commission's proposed cost allocation reforms.\381\ For 
example, Northern Tier Transmission Group argues that the Proposed Rule 
does not present a factual basis for expanding the scope of the cost 
allocation requirement to every project contained in a regional 
transmission plan. It requests that the Commission confirm that the 
Proposed Rule is not intended to apply to existing transmission 
projects covered by existing tariff-based and contract-based cost 
allocation procedures. If the Proposed Rule is intended to apply to all 
new transmission projects in a region's transmission plan, Northern 
Tier Transmission Group urges that the Proposed Rule be rejected. It 
also is concerned that shifting the burden of cost allocation for every 
project onto the regional transmission planning process will create an 
unnecessary burden on a region's collective transmission providers. 
Westar states that the transmission planning selection process is 
critical to ensure that only transmission projects that meet the 
various regional requirements are constructed and their costs recovered 
as part of tariff rates.
---------------------------------------------------------------------------

    \380\ E.g., Arizona Public Service Company; Bonneville Power; 
California Transmission Planning Group; Tucson Electric; Western 
Area Power Administration; California Commissions; California ISO; 
Eastern Massachusetts Consumer-Owned System; New York PSC; Coalition 
for Fair Transmission Policy; Connecticut & Rhode Island 
Commissions; Large Public Power Council; National Grid; and Southern 
California Edison.
    \381\ E.g., Ad Hoc Coalition; Southern Companies; Salt River 
Project; and Nebraska Public Power District.
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    493. North Carolina Agencies contend that the Commission has not 
established that current cost allocation methods are unjust and 
unreasonable. Nebraska Public Power District argues that the Proposed 
Rule does not contain any record evidence demonstrating the need for 
generic rate reform and states that transmission investment has 
substantially increased in recent years. Salt River Project argues that 
the primary barriers to renewable resource development are delays and 
denial of siting and other permits, not transmission funding. 
California Municipal Utilities suggest that fewer remote resources are 
needed because more local renewable resources are being developed and, 
therefore, the need for cost allocation reforms must be re-examined. 
Indianapolis Power and Light believes that existing tariff requirements 
and ongoing proceedings will achieve the Commission's stated objective 
without the uncertainty of a parallel rulemaking process.
    494. MEAG Power responds to Multiparty Commenters' assertion 
regarding the cost of transmission expansion by arguing that 
investments of the size actually needed to build out the transmission 
system, if allocated to load, would raise its native load customers' 
transmission costs dramatically. Sacramento Municipal Utility District 
states that, even if Multiparty Commenters' assertion were true, it is 
irrelevant to the establishment of a just and reasonable transmission 
rate whether it comprises a small or large portion of the cost of 
delivered power.\382\ Large Public Power Council raises arguments 
similar to those raised by both MEAG Power and Sacramento Municipal 
Utility District.
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    \382\ Sacramento Municipal Utility District (citing Farmers 
Union Central Exchange v. FERC, 734 F.2d 1486, 1508 (DC Cir. 1984)).
---------------------------------------------------------------------------

3. Commission Determination
    495. The Commission concludes that it is necessary and appropriate 
to adopt the cost allocation requirements described in further detail 
below for public utility transmission providers. The Commission finds 
that, without these minimum requirements in place, cost allocation 
methods used by public utility transmission providers may fail to 
account for the benefits associated with new transmission facilities 
and, thus, result in rates that are not just and reasonable or are 
unduly discriminatory or preferential.
    496. In Order No. 890, the Commission found that there is a close 
relationship between transmission planning, which identifies needed 
transmission facilities, and the allocation of costs of the 
transmission facilities in the plan.\383\ The Commission explained that 
knowing how the costs of transmission facilities would be allocated is 
critical to the development of new infrastructure because transmission 
providers and customers cannot be expected to support the construction 
of new transmission unless they understand who will pay the associated 
costs.\384\ In light of that relationship, the Commission directed 
public utility transmission providers to identify the cost allocation 
method or methods that would apply to transmission facilities that do 
not fit under previously existing rate structures.\385\ After several 
rounds of compliance filings, the Commission accepted various public 
utility transmission providers' proposals as in compliance with Order 
No. 890. Particularly in transmission planning regions outside of the 
RTO and ISO

[[Page 49921]]

footprints, several of the cost allocation methods that the Commission 
accepted relied exclusively on a participant funding approach to cost 
allocation.\386\ The Commission did not address cost allocation for 
interregional transmission facilities in Order No. 890.
---------------------------------------------------------------------------

    \383\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 557.
    \384\ Id.
    \385\ Id. P 558.
    \386\ See, e.g., El Paso Electric Co., 124 FERC ] 61,051 (2008); 
Xcel Energy Services, Inc.--Public Service Co. of Colorado, 124 FERC 
] 61,052 (2008); South Carolina Electric & Gas Co., 127 FERC ] 
61,275 (2009). Entergy Services, Inc., 127 FERC ] 61,272 (2009). See 
also Avista Corp., 128 FERC ] 61,065 (2009); Idaho Power Co., 128 
FERC ] 61,064 (2009).
---------------------------------------------------------------------------

    497. We conclude that, in light of changes within the industry and 
the implementation of other reforms in this Final Rule, the existing 
requirements of Order No. 890 are no longer adequate to ensure rates, 
terms and conditions of jurisdictional service are just and reasonable 
and not unduly discriminatory or preferential. While the existing cost 
allocation methods may have sufficed in the past, as we note above, the 
circumstances in which the Commission must fulfill its statutory 
responsibilities change with developments in the electric industry, 
such as changes with respect to the demands placed on the transmission 
grid. The comments in this proceeding make clear that the pace of 
change has accelerated in recent years, such as the expansion of 
regional power markets, which has led to a growing need for 
transmission facilities that cross several utility, RTO, ISO or other 
regions. The industry's continuing transition also has enabled greater 
utilization of resources (e.g., reserve sharing) resulting in, among 
other effects, broader diffusion of the benefits associated with 
transmission facilities. Additionally, the increasing adoption of state 
resource policies, such as renewable portfolio standard measures, has 
contributed to rapid growth of renewable energy resources that are 
frequently remote from load centers, and thus a growing need for 
transmission facilities to access remote resources, often traversing 
several utility and/or ISO/RTO regions.
    498. The challenges associated with allocating the cost of 
transmission appear to have become more acute as the need for 
transmission infrastructure has grown. Within RTO or ISO regions, 
particularly those that encompass several states, the allocation of 
transmission costs is often contentious and prone to litigation because 
it is difficult to reach an allocation of costs that is perceived by 
all stakeholders as reflecting a fair distribution of benefits. In 
other regions, few rate structures are currently in place that reflect 
an analysis of the beneficiaries of a transmission facility and for the 
corresponding cost allocation of the transmission facility's cost. 
Similarly, there are few rate structures in place today that provide 
for the allocation of costs of interregional transmission facilities.
    499. We agree with many commenters 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. Under the regional transmission 
planning and interregional transmission coordination requirements 
adopted in this Final Rule,\387\ public utility transmission providers, 
in consultation with stakeholders, will identify, evaluate, and 
determine the set of transmission facilities that will meet the 
combined needs of the region or neighboring pairs of regions, 
respectively. This necessarily includes a determination by the region 
that the benefits associated with that set of transmission facilities 
outweigh the costs. Failing to address the allocation of costs for 
these transmission facilities in a way that aligns with the evaluation 
of benefits through the transmission planning process could lead to 
needed transmission facilities not being built, adversely impacting 
ratepayers.
---------------------------------------------------------------------------

    \387\ See discussion supra sections III.A and III.C.
---------------------------------------------------------------------------

    500. In general and as discussed elsewhere in this Final Rule, the 
Commission requires a public utility transmission provider to 
participate in a regional transmission planning process and to 
coordinate transmission planning with public utility transmission 
providers in neighboring transmission planning regions in a manner that 
aligns transmission planning and cost allocation processes. 
Additionally, the OATTs of all public utility transmission providers in 
a region must include the same cost allocation method or methods 
adopted by the region. As some commenters point out, transmission 
facilities that are in a transmission plan to achieve a specific 
purpose or purposes, such as to avoid an impending violation of a 
Reliability Standard, address economic considerations, or enable 
compliance with Public Policy Requirements. Because such purposes 
involve the identification of expected beneficiaries, either explicitly 
or implicitly, establishing a closer link between transmission planning 
and cost allocation will ensure that rates for Commission-
jurisdictional service appropriately account for benefits associated 
with new transmission facilities.
    501. We recognize that identifying which types of benefits are 
relevant for cost allocation purposes, which beneficiaries are 
receiving those benefits, and the relative benefits that accrue to 
various beneficiaries can be difficult and controversial. We believe 
that a transparent transmission planning process is the appropriate 
forum to address these issues. By linking transmission planning and 
cost allocation through the transmission planning process, we seek to 
increase the likelihood that transmission facilities in regional 
transmission plans are actually constructed.
    502. Turning to specific comments on this topic, we are not 
persuaded to adopt Illinois Commerce Commission's proposal for separate 
review and decision by a committee of state regulators on the 
reasonableness of proposed transmission expansion projects for which 
regional cost allocation would apply. As explained above,\388\ this 
Final Rule builds on Order No. 890's requirement that a public utility 
transmission provider have open and transparent transmission planning 
processes in which we encourage states or state committees to be 
involved. Additionally, as required by this Final Rule, through the 
transmission planning process, the public utility transmission 
providers and other parties, including state regulators, will have 
opportunities to participate in the identification of transmission 
needs. We decline, however, to mandate veto rights for state 
committees, but do not preclude public utility transmission providers 
from proposing such mechanisms on compliance if they choose to do 
so.\389\
---------------------------------------------------------------------------

    \388\ See discussion supra section III.A.
    \389\ For example, Entergy's OATT allows Entergy's committee of 
state regulators to add a project to Entergy's transmission plan 
upon unanimous vote of the committee members. See Entergy Arkansas, 
Inc., 133 FERC ] 61,211 (2010).
---------------------------------------------------------------------------

    503. In response to Northern Tier Transmission Group's concern that 
applying the new cost allocation requirements to existing transmission 
projects covered by existing tariff-based and contract-based cost 
allocation procedures will shift costs and create unnecessary burdens, 
we clarify that the cost allocation requirements of this Final Rule 
apply only to new transmission facilities \390\ selected in regional 
transmission plans for purposes of cost allocation.
---------------------------------------------------------------------------

    \390\ See discussion supra P 0.

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[[Page 49922]]

B. Legal Authority for Cost Allocation Reforms

1. Commission Proposal
    504. The Commission explained in the Proposed Rule that, to ensure 
that transmission rates are just and reasonable, the costs of 
jurisdictional transmission facilities must be allocated in a way that 
satisfies the ``cost causation'' principle. It noted that the DC 
Circuit defined the cost causation principle stating that ``it has been 
traditionally required that all approved rates reflect to some degree 
the costs actually caused by the customer who must pay them.'' \391\ 
Moreover, the Commission noted that while the cost causation principle 
requires that the costs allocated to a beneficiary be at least roughly 
commensurate with the benefits that are expected to accrue to it,\392\ 
the DC Circuit has explained that cost causation ``does not require 
exacting precision in a ratemaking agency's allocation decisions.'' 
\393\
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    \391\ K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (DC Cir. 
1992) (K N Energy).
    \392\ Illinois Commerce Commission, 576 F.3d 470 at 476-77 (``We 
do not suggest that the Commission has to calculate benefits to the 
last penny, or for that matter to the last million or ten million or 
perhaps hundred million dollars.'').
    \393\ MISO Transmission Owners, 373 F.3d 1361 at 1371.
---------------------------------------------------------------------------

    505. The Commission explained that, while costs generally have been 
allocated through voluntary agreements, the cost causation principle is 
not limited to such arrangements. If it were, the Commission could not 
address free rider problems associated with new transmission investment 
and could not ensure that transmission rates are just and reasonable 
and not unduly discriminatory. The Commission stated that it may 
determine that an entity is a beneficiary of a transmission facility 
even if it has not entered a voluntary arrangement with the public 
utility transmission provider that is seeking to recover the costs of 
that transmission facility.
    506. The Commission noted that it has expressed a willingness to 
make such a determination, as when presented with concerns about 
parallel path flow.\394\ In such cases, a public utility transmission 
provider may propose a transmission service rate that would account for 
unauthorized use of its system.\395\ The Commission noted that it has 
cautioned against the hasty submittal of such unilateral filings and 
prefers resolution of parallel path flow issues on a consensual, 
regional basis.\396\ If necessary, however, it would permit recovery of 
costs from a beneficiary in the absence of a voluntary arrangement.
---------------------------------------------------------------------------

    \394\ The Commission has described the phenomenon of parallel 
path flow as follows: ``In general, utilities transact with one 
another based on a contract path concept. For pricing purposes, 
parties assume that power flows are confined to a specified sequence 
of interconnected utilities that are located on a designated 
contract path. However, in reality power flows are rarely confined 
to a designated contract path. Rather, power flows over multiple 
parallel paths that may be owned by several utilities that are not 
on the contract path. The actual power flow is controlled by the 
laws of physics which cause power being transmitted from one utility 
to another to travel along multiple parallel paths and divide itself 
along the lines of least resistance. This parallel path flow is 
sometimes called `loop flow.' '' Indiana Michigan Power Co. and Ohio 
Power Co., 64 FERC ] 61,184, at 62,545 (1993).
    \395\ See, e.g., Amer. Elec. Power Svc. Corp., 49 FERC ] 61,377, 
at 62,381 (1989) (AEP).
    \396\ Id.; see also Southern California Edison Co., 70 FERC ] 
61,087, at 61,241-42 (1995).
---------------------------------------------------------------------------

    507. The Commission also stated that it has affirmatively required 
costs of transmission facilities to be allocated to beneficiaries in 
the absence of a voluntary arrangement in a series of orders involving 
MISO and PJM. Specifically, the Commission explained that it directed 
MISO and PJM to develop cost allocation methods for new facilities in 
one of their footprints that benefit entities in the other's 
footprint.\397\ It subsequently conditionally accepted a proposal by 
MISO and PJM on the grounds that it ``more accurately identifies the 
beneficiaries and allocates the associated costs.'' \398\
---------------------------------------------------------------------------

    \397\ Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC 
] 61,168, at P 60 (2004) (citing Midwest Indep. Transmission Sys. 
Operator, Inc., 106 FERC ] 61,251, at P 56-57 (2004)). The 
Commission noted that MISO and PJM had committed in a Joint 
Operating Agreement to develop such a method for allocating the 
costs of certain facilities through their joint regional planning 
committee. Id. The Commission did not base the above-noted directive 
on the existence of the Joint Operating Agreement, which MISO and 
PJM developed to comply with a previous Commission directive. See 
Alliance Cos., 100 FERC ] 61,137, at P 48, 53 (2002).
    \398\ Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC 
] 61,194, at P 10 (2005). See also Midwest Indep. Transmission Sys. 
Operator, Inc., 122 FERC ] 61,084 (2008); Midwest Indep. 
Transmission Sys. Operator, Inc., 129 FERC ] 61,102 (2009).
---------------------------------------------------------------------------

    508. The Commission noted that courts have accepted the application 
of the cost causation principle in this way. For example, the DC 
Circuit addressed this issue in connection with a MISO proposal to 
recover administrative costs through a charge that would apply to 
transmission loads subject to MISO's OATT rates.\399\ The court found 
that the Commission's system-wide benefits analysis met the 
requirements of the cost causation principle, that is, to compare ``the 
costs assessed against a party to the burdens imposed or benefits drawn 
by that party.'' \400\
---------------------------------------------------------------------------

    \399\ MISO Transmission Owners, 373 F.3d 1361. The DC Circuit 
stated that the subject costs ``are primarily MISO's startup 
expenses--particularly those pertaining to the MISO Security 
Center--and certain expenses pertaining to the creation and 
administration of MISO's open access tariff.'' Id. at 1369.
    \400\ Id. at 1367.
---------------------------------------------------------------------------

2. Comments on Legal Authority
    509. Several entities comment in support of the Commission's legal 
authority to allocate costs of new transmission facilities based on a 
beneficiary pays approach.\401\ AEP asserts that the Commission's 
proposed cost allocation principles comport with the legal requirements 
on cost allocation articulated by the U.S. Court of Appeals for the 
Seventh Circuit in Illinois Commerce Commission v. FERC.\402\ Further, 
AEP states that while the courts have found that the allocation of 
transmission expansion costs in rates must follow the ``cost 
causation'' principle, the courts have explained that all beneficiaries 
``cause'' costs for the purpose of applying this principle. Thus, from 
AEP's perspective, the Commission's proposal to require allocation of 
costs to beneficiaries is fully consistent with the legal precedent. 
Iberdrola Renewables and American Transmission agree. American 
Transmission cautions, however, that care be taken in how precisely the 
costs of a transmission project are linked to beneficiaries, given that 
the benefits and beneficiaries of a particular project may change over 
time, particularly in the case of a large project that provides 
regional and interregional benefits. Allegheny Energy Companies state 
that although the Illinois Commerce Commission decision found that the 
Commission did not provide sufficient evidence to justify adoption of 
the postage-stamp cost allocation method in PJM, it did not reject the 
method outright, instead requiring the Commission only to provide 
further justification assuring that this method results in a just and 
reasonable rate that satisfies the principle that rates required to be 
paid by a customer must have some relationship to the costs caused or 
benefits received by that customer.
---------------------------------------------------------------------------

    \401\ E.g., Iberdrola Renewables; 26 Public Interest 
Organizations; Exelon; ITC Companies; LS Power; and Multiparty 
Commenters.
    \402\ 576 F.3d 470 (7th Cir. 2009) (Illinois Commerce 
Commission).
---------------------------------------------------------------------------

    510. LS Power asserts that there is nothing in the FPA that 
precludes the Commission from allocating costs incurred by one 
transmission provider in a region to entities nominally taking service 
under the tariffs of other transmission providers, or to those other 
transmission providers themselves for

[[Page 49923]]

the benefits they receive with respect to their own uses of the 
regional transmission grid. On the contrary, it explains that 
allocating costs only to customers located within the corporate 
boundaries of the utility that owns the transmission facilities will 
over-allocate costs to such customers and allow other beneficiaries to 
become free riders. LS Power concludes that the Commission has 
exclusive jurisdiction over interstate transmission services, and 
therefore, the authority and the responsibility to define interstate 
transmission services--here regional transmission services--and to 
identify the beneficiaries of those services that are responsible for 
costs incurred by regional transmission providers.
    511. Illinois Commerce Commission agrees with the Commission's 
decision that, when applying the cost causation principle, the 
Commission may allocate costs of a transmission facility to a 
beneficiary identified through an appropriate process, such as a 
Commission-approved transmission planning process, even if that 
beneficiary has not entered into a voluntary arrangement with a public 
utility that is seeking to recover the costs of that facility. However, 
it asserts that the process must take into account the restrictions on 
allocation to beneficiaries set forth in Illinois Commerce Commission, 
in which cost causers are primary, and beneficiaries may be taken into 
account only to the extent that, without the developer's expectation of 
receiving revenues from such a party, the project ``might not have been 
built, or might have been delayed.'' Illinois Commerce Commission 
asserts that an unduly discriminatory socialization of costs based on 
speculation that uncertain future costs will offset the discrimination 
does not support a finding of just and reasonable rates.\403\
---------------------------------------------------------------------------

    \403\ In reply, PPL Companies assert that Illinois Commerce 
Commission overstates Illinois Commerce Commission, arguing that the 
court did not interpret the cost causation principle to require that 
costs be allocated on a narrow definition of ``cause'' that ignores 
benefits received by customers.
---------------------------------------------------------------------------

    512. A number of commenters agree that a free rider problem exists 
in transmission development and that the Commission should bring 
certainty to cost allocation rules to address this concern.\404\ 
NextEra states that any project that provides benefits to entities, 
other than the sponsoring entity, creates an incentive for an 
individual beneficiary to defer investment in hopes that others will 
fund the project's development, and this has led to stalemate and 
delay. Federal Trade Commission agrees that the lack of rate structures 
to allocate the costs of needed transmission, and the free rider 
problem that arises when project beneficiaries seek to shift 
transmission construction costs onto others, add uncertainty and 
conflict to the debate over what transmission to build and how to pay 
for it. Sunflower and Mid-Kansas state that the free rider problem can 
be an issue regionally, but is likely to prove more intractable for 
interregional cost allocation. Boundless Energy and Sea Breeze state 
that cost allocation has to deal with the free rider issue when 
multiple utilities are involved because then an independent entity with 
a proposal that provides system benefits across a larger region may 
find that beneficiaries will not contract for their portion of the 
benefits.
---------------------------------------------------------------------------

    \404\ E.g., Gaelectric North America; Atlantic Grid; Multiparty 
Commenters; Primary Power; Pennsylvania PUC; NextEra; Federal Trade 
Commission; Sunflower and Mid-Kansas; Boundless Energy and Sea 
Breeze; and LS Power.
---------------------------------------------------------------------------

    513. Several commenters argue that it is unlawful for transmission 
developers to recover costs from entities to which they do not provide 
service.\405\ Some commenters contend that the Commission ignores that 
privity of contract existed between the entities involved in the cases 
that it cites to support its proposal \406\ and that the Commission's 
authority under the FPA is premised on a utility having a contractual 
relationship or a tariff to provide service to its customers.\407\ 
Nebraska Public Power District asserts that the Mobile-Sierra cases 
support this view.\408\
---------------------------------------------------------------------------

    \405\ E.g., Ad Hoc Coalition of Southeastern Utilities; Nebraska 
Public Power District; Salt River Project; and Sacramento Municipal 
Utility District.
    \406\ E.g., Ad Hoc Coalition of Southeastern Utilities (citing 
Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 144); Salt River 
Project (citing Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 
164).
    \407\ E.g., Ad Hoc Coalition of Southeastern Utilities; Salt 
River; and Nebraska Public Power District.
    \408\ Nebraska Public Power District (citing United Gas Pipeline 
Co. v. Mobile Gas Corp., 350 U.S. 332 (1955); FPC v. Sierra Pac. 
Power Co., 350 U.S. 348 (1956)).
---------------------------------------------------------------------------

    514. Sacramento Municipal Utility District asserts that there is a 
distinction between allocating costs among a public utility 
transmission provider's customers without their voluntary agreement 
(such as the roll-in of the costs of the transmission provider's bulk 
transmission system) and allocating them to entities that are not the 
transmission provider's customers. It argues that AEP and similar cases 
\409\ do not establish a right to assess costs of facilities to non-
customers and that it is a perversion of the statutory scheme to 
suggest that an entity could build a transmission facility and then 
claim that because power generated or scheduled by non-customers flowed 
over the facility, it was entitled to be compensated by them. Southern 
Companies note that no complaint was filed in response to AEP, and the 
case therefore does not support the idea that allocation of costs to 
non-customers is lawful. Northern Tier Transmission Group maintains 
that even if the Commission has authority to permit allocation of costs 
to an entity that does not take service from the transmission provider 
that collects the costs, it has not complied with the common law 
requirements necessary to delegate that authority to transmission 
providers.
---------------------------------------------------------------------------

    \409\ In addition to AEP, Sacramento Municipal Utility District 
cites Sierra Pacific Power Co., 85 FERC ] 61,314 at 62,235 (1998); 
Sierra Pacific Power Co., 86 FERC ] 61,198 at 61,698 (1999); Vermont 
Elec. Power Co., 44 FERC ] 61,098, at 61,275 (1988).
---------------------------------------------------------------------------

    515. Sacramento Municipal Utility District asserts that the cases 
that the Commission cites dealing with the allocation of costs between 
RTOs when new facilities in one of their footprints benefits entities 
in the other's footprint do not apply here.\410\ It argues that in 
those cases, cross-border facility costs were allocated to each RTO as 
a whole, after which project costs were recovered by the RTO through 
its own intra-RTO cost allocation. Sacramento Municipal Utility 
District states that customers in these cases were not being billed for 
service taken from entities with which those customers had no contract 
or applicable tariff, but rather were being billed by their own 
transmission providers.
---------------------------------------------------------------------------

    \410\ Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC 
] 61,084; Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC 
] 61,168; Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC 
] 61,194.
---------------------------------------------------------------------------

    516. Sacramento Municipal Utility District takes issue with the 
Commission's reliance on MISO Transmission Owners for the proposition 
that the cost causation principle allows allocation of at least some 
types of costs to beneficiaries that are not customers of the public 
utility that is seeking cost recovery. It states that in that case, 
MISO was the public utility seeking cost recovery, and the costs in 
question were not levied directly on the entities in question. Instead, 
the MISO transmission owners--existing customers under the MISO 
tariff--had challenged whether the cost allocation reflected in their 
rates was reasonable. Sacramento Municipal Utility District contends 
that all the court decided was that the Commission had reasonably 
allocated

[[Page 49924]]

MISO's operating costs to the transmission owners based on their use of 
MISO-controlled transmission facilities to deliver power to entities 
that were not subject to the MISO tariff and on the benefits that MISO 
Transmission Owners derived from that delivery.\411\
---------------------------------------------------------------------------

    \411\ See also Southern Companies and ColumbiaGrid.
---------------------------------------------------------------------------

    517. Sacramento Municipal Utility District asserts that the 
Commission's position on joint rates supports its position that a 
contractual customer relationship is a precondition for the allocation 
of transmission costs. It states that the Commission's position is 
that, absent evidence that two systems were in fact acting as one, the 
Commission cannot mandate the use of a single joint rate. Sacramento 
Municipal Utility District argues that if the Commission cannot mandate 
joint rates when this condition is not met even where a customer takes 
service from both utilities, it cannot mandate that an entity pay rates 
charged by a utility with which it has no contractual or tariff-based 
customer relationship.\412\
---------------------------------------------------------------------------

    \412\ Sacramento Municipal Utility District cites to Ft. Pierce 
Utilities Comm'n v. FERC, 730 F.2d 778 (DC Cir. 1984) (Fort Pierce); 
Richmond Power & Light v. FERC, 574 F.2d 610 (DC Cir. 1978) 
(``purchasers are always free to subscribe to the services of 
willing utilities at the separate rates''); Alabama Power Co. v. 
FERC, 993 F.2d 1557, 1565 (DC Cir. 1993) (affirming order directing 
joint rate between holding company members who the Commission found 
were acting as one); see also Illinois Power Co., 95 FERC ] 61,183, 
at 61,644 (2002) (approving single joint rate across Alliant and 
MISO systems but recognizing that, in the absence of an agreement 
between these utilities, there would not be a single rate).
---------------------------------------------------------------------------

    518. ColumbiaGrid argues that the Commission cannot use its 
authority to force customers to pay for additional benefits that go 
beyond their existing service. It states that a court has held that 
under section 5 of the Natural Gas Act, the Commission may reject 
unjust and unreasonable rates and prescribe a new just and reasonable 
rate, but it may not require distributors to accept or to pay for 
additional service.\413\ ColumbiaGrid maintains that this shows that 
costs cannot be recovered from entities that are not customers 
receiving jurisdictional service. ColumbiaGrid argues that Illinois 
Commerce Commission does not support the allocation of costs in the 
absence of an approved rate or a contractual relationship between 
transmission owners and presumed beneficiaries, and it maintains that 
the Commission's reliance on this case to extend the cost causation 
principle to cover any entity that may be said to benefit from a 
project is misplaced.
---------------------------------------------------------------------------

    \413\ ColumbiaGrid cites to Exxon Mobil Corp. v. FERC, 430 F.3d 
1166 (DC Cir. 2005) (Exxon Mobil Corp.).
---------------------------------------------------------------------------

    519. Southern Companies argue that while the Proposed Rule 
acknowledges the fundamental role of cost causation, it proceeds to 
nullify the ``but for'' element that is intrinsic to any determination 
of cost causation. Southern Companies argue that the primary 
beneficiary of a transmission improvement is the customer that made the 
request that ``causes'' the improvement in question. They argue that 
the Proposed Rule seems to attack cost causation by concluding that a 
participant funding approach is not permissible.
    520. Several commenters maintain that in their experience, free 
rider problems do not exist and that such concerns may be 
speculative.\414\ Ad Hoc Coalition of Southeastern Utilities states 
that cost socialization is not needed to protect against the inequities 
of free ridership. It interprets the Commission's reference to the free 
rider problem as referring to the relatively cost-free transmission 
that may be provided to entities that take advantage of oversized 
investments made by others.
---------------------------------------------------------------------------

    \414\ E.g., Southern Companies; California Municipal Utilities; 
Transmission Agency of Northern California; and Columbia Grid.
---------------------------------------------------------------------------

    521. Southern Companies suggest that if any such problems exist, 
they are a product of local or regional factors that do not require a 
national solution. E.ON argues that free rider problems do not exist in 
the context of reliability or public policy transmission projects, and 
participant funding of such projects does not exacerbate the free rider 
problem.
    522. Some commenters argue that, even if free rider problems exist, 
they can either be solved without resort to broad cost allocation or 
are beyond the Commission's authority.\415\ Alternatively, Illinois 
Commerce Commission states that while a free rider problem does exist, 
it is impossible to solve in practice, and the negative consequences of 
allocating costs too broadly will be greater than allocating costs more 
narrowly to cost causers and direct, quantifiable beneficiaries. 
Dominion similarly asserts that while broad cost allocation may 
eliminate free ridership, it may result in some entities paying 
disproportionate costs.
---------------------------------------------------------------------------

    \415\ E.g., Nebraska Public Power District and Sacramento 
Municipal Utility District.
---------------------------------------------------------------------------

    523. Alabama PSC states that it would be improper to require 
citizens of Alabama to pay for the costs of transmission facilities in 
other areas of the country where there is high congestion and which are 
not necessary to provide service in Alabama. It maintains that this 
violates the principle of cost causation and the requirement that 
facilities be ``used and useful'' before being incorporated into a 
consumer's rates. Indianapolis Power & Light argues that it is 
inconsistent with cost causation principles to subsidize a state's 
generation decisions (e.g., a state's renewable portfolio standard), 
and states should not be able to pass the cost of compliance with their 
requirements on to other jurisdictions. ELCON agrees and states that a 
claim of generalized system benefits, such as an amorphous reliability 
improvement, does not justify regionalized charges. Instead, ELCON 
asserts that there must be a tangible, nontrivial benefit supported by 
substantial evidence. ELCON also maintains that disallowing export 
charges or other forms of cost transfer to beneficiaries in other 
planning regions will result in unjust and discriminatory rates.
    524. Coalition for Fair Transmission Policy states that the 
Commission lacks authority to require consideration of broad public 
policy benefits that cannot be measured or projected within a 
transmission providers' planning horizon. It maintains that allowing 
the allocation of costs that are not required to maintain reliability, 
relieve congestion, or to meet mandated public policy requirements is 
beyond the Commission's core mission.
    525. Ad Hoc Coalition of Southeastern Utilities states that in the 
Southeast, only North Carolina has a renewable portfolio standards 
requirement, and there is no suggestion that a regional mechanism for 
funding transmission is needed to satisfy this requirement. It thus 
sees no reason to discontinue providing cost recovery for regional 
transmission projects from the entities that choose to use them.
    526. ColumbiaGrid argues that at least with respect to non-RTO 
regions (where there are no regional service tariff rates), directing 
public and non-public utilities to adopt a specific cost allocation 
method in advance could infringe upon a utility's right to propose 
rates under section 205 of the FPA.\416\ The California ISO maintains 
that the Commission does not have the authority to compel rate filings 
in the first instance, and it can require a filing only if it shows 
that the existing rate does not meet the requirements of section 
206.\417\

[[Page 49925]]

California ISO argues that the Commission cannot fulfill this 
requirement with regard to cost allocation for regional and 
interregional facilities because there are no existing contracts or 
rates for such services. The Commission may at most issue guidance on 
whether future filings will meet statutory requirements.
---------------------------------------------------------------------------

    \416\ ColumbiaGrid bases this claim on Atlantic City Electric 
Co. v. FERC, 295 F.3d 1 (DC Cir. 2002) (Atlantic City).
    \417\ Similarly, Northern Tier Transmission Group argues that 
the Commission must justify, under section 206, modifying the cost 
allocation process that it already accepted for its members.
---------------------------------------------------------------------------

    527. Southern Companies assert that where vertically integrated 
transmission providers plan their transmission systems from the bottom 
up under state supervision and recover most of their costs for 
transmission facilities through bundled rates, the Proposed Rule's 
mandates cannot be implemented without preempting or undermining state 
law. Southern Companies state that the Commission should revise its 
proposed reforms and explain how they can be implemented while 
respecting existing processes for bundled retail ratemaking. Southern 
Companies assert that they recover only approximately 15 percent of 
their transmission revenue requirements under a federal OATT, with the 
remaining 85 percent being recovered in state-regulated bundled rates. 
They state that the latter cost recovery is not an issue of federal 
comparability, and a nonincumbent would, at best, be allowed to recover 
only 15 percent of its transmission costs under a federal OATT, with 
the rest requiring state approval. Southern Companies maintain that as 
a practical matter, a nonincumbent cannot have ``comparable'' cost 
recovery without a long-term contract from Southern Companies that has 
appropriate state commission approval for purposes of retail rate 
recovery.
    528. Transmission Access Policy Study Group urges the Commission to 
address allocation of costs of transmission projects that go beyond 
existing boundaries of an RTO or individual transmission providers 
where the transmission grid is integrated. It recommends that the 
Commission recognize that it has the authority to order joint, non-
pancaked rates where transmission systems are integrated. Sacramento 
Municipal Utility District argues in response that the Commission 
cannot require joint rates unless two adjoining transmission systems 
are not just integrated, but effectively operate as a single system. 
Large Public Power Council agrees. Ad Hoc Coalition of Southeastern 
Utilities argues that the statutory right of utilities to set their 
rates may not be easily set aside, and that imposing a joint, non-
pancaked rate structure on utilities would do exactly that.
    529. Florida PSC is concerned that the Commission's proposal may 
circumvent its authority over rates for transmission infrastructure 
that serves retail load because the Proposed Rule appears to allow 
entities seeking to construct merchant transmission projects to recover 
project costs from Florida ratepayers through a Commission-approved 
cost allocation process. North Carolina Agencies argue that the Final 
Rule should recognize the indispensible role of state regulatory 
authorities and should apply only to unbundled transmission rates. 
Northwestern Corporation (Montana) states that entities seeking to 
recover costs without approval from state public utilities commissions 
face the risk of cost disallowance.
3. Commission Determination
    530. We conclude that we have the legal authority to adopt the cost 
allocation reforms required by this Final Rule. Numerous commenters 
challenge our authority to require allocation of transmission costs to 
beneficiaries that do not have a contractual or formalized customer 
relationship with the entity that is collecting the costs. These 
challenges are based primarily on the commenters' analysis of various 
Commission and court cases. Some commenters have made arguments that 
speak directly to provisions of the FPA, but none of these assertions 
reach convincing conclusions. For instance, Ad Hoc Coalition of 
Southeastern Utilities states that ``[u]tilities filing for rate 
changes under FPA section 205 ask the Commission to approve changes in 
rates charged to their customers'' and that ``the Commission's 
authority is, in all cases, based on the premise that a utility has a 
contractual relationship to provide service to its customers.'' \418\ 
However, section 205 does not specify any such limitation and no 
commenter has shown where it is expressed elsewhere in the FPA. 
Instead, commenters generally appear to agree with Ad Hoc Coalition of 
Southeastern Utilities that the ``FPA is structured on the assumption 
that rates subject to [Commission] approval are supported by a 
contractual agreement.'' \419\
---------------------------------------------------------------------------

    \418\ Ad Hoc Coalition of Southeastern Utilities Comments at 60-
61 (emphasis in original).
    \419\ Id. at 60 (emphasis supplied).
---------------------------------------------------------------------------

    531. The merit of this argument depends, of course, on how the FPA 
is in fact structured, and an examination of the relevant provisions of 
the statute shows that it is not structured in a way that would justify 
this argument. On the contrary, the Commission's jurisdiction is 
clearly 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. As discussed further below, 
this comports fully with the specific characteristics of transmission 
facilities and transmission services, and our actions today are 
necessary to fulfill our statutory duty of ensuring rates, terms and 
conditions of jurisdictional service are just and reasonable and not 
unduly discriminatory or preferential. We thus turn first to the 
language of the statute itself.
    532. Section 201(b)(1) of the FPA gives the Commission jurisdiction 
over ``the transmission of electric energy in interstate commerce.'' 
The Commission's jurisdiction therefore extends to the rates, terms and 
conditions of transmission service, rather than merely transactions for 
such transmission service specified in individual agreements. Moreover, 
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. As a result, the Commission 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.
    533. 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. Any such rates or charges must, of course, be 
accepted for filing with the Commission under either section 205 or 
206, but 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.
    534. Transmission services create an opportunity for free ridership 
because the nature of power flows over an interconnected transmission 
system does not permit a public utility

[[Page 49926]]

transmission provider to withhold service from those who benefit from 
those services but have not agreed to pay for them. The Commission 
expressed concern over free ridership in Order No. 890, where it noted 
that ``there are free rider problems associated with new transmission 
investment, such that customers who do not agree to support a 
particular project may nonetheless receive substantial benefits from 
it.'' \420\
---------------------------------------------------------------------------

    \420\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 561.
---------------------------------------------------------------------------

    535. In Order No. 890, the Commission recognized that the cost 
causation principle provides that costs should be allocated to those 
who cause them to be incurred and those that otherwise benefit from 
them. We conclude now that this principle 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. In fact, the courts have recognized this aspect of cost 
causation quite independently of an analysis of the scope of our 
statutory jurisdiction over transmission.
    536. The courts have acknowledged that cost causation involves 
``comparing the costs assessed against a party to the burdens imposed 
or benefits drawn by that party.'' \421\ An approach to cost causation 
that is limited to voluntary arrangements such as participant funding 
has the effect of ``focusing us on the most immediate and proximate 
cause of the cost incurred,'' and it precludes looking ``at a host of 
contributing causes for the cost incurred (as ascertained by a review 
of those who benefit from the incurrence of the cost) and assign[ing] 
them liability too.'' \422\ In short, a full cost causation analysis 
may involve ``an extension of the chain of causation'' \423\ beyond 
those causes captured in voluntary arrangements. In other words, to 
identify all causes, we must to some degree begin with their effects, 
i.e., the benefits that they engender and then work back to their 
sources.
---------------------------------------------------------------------------

    \421\ MISO Transmission Owners, 373 F.3d 1361, at 1368 (internal 
citations omitted).
    \422\ KN Energy, 968 F.2d 1295 at 1302.
    \423\ Id.
---------------------------------------------------------------------------

    537. This point was acknowledged in the Seventh Circuit's 
characterization of cost causation in Illinois Commerce Commission. The 
Seventh Circuit states that:

    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.\424\
---------------------------------------------------------------------------

    \424\ Illinois Commerce Commission, 576 F.3d 470 at 476 
(emphasis supplied).

    The court fully recognized that, to identify causes of costs, one 
must to some degree begin with benefits. ColumbiaGrid argues that 
Illinois Commerce Commission does not support the Commission's position 
on cost allocation because the statement just cited is preceded by the 
statement that ``[A]ll approved rates [must] reflect to some degree the 
costs actually caused by the customer who must pay them.'' \425\ 
ColumbiaGrid maintains that this demonstrates the Illinois Commerce 
Commission ``does not support the [Proposed Rule's] approach of 
allocating costs in the absence of an approved rate or a contractual 
relationship between transmission owners and presumed beneficiaries.'' 
\426\ What this argument fails to recognize is that the point 
ColumbiaGrid contests was not before the court in Illinois Commerce 
Commission, and the Commission's jurisdiction over transmission, as 
outlined above, is broad enough to approve rates based on the court's 
characterization of cost causation.\427\ In other words, there is 
nothing in what the court said that can be viewed as preventing the 
Commission from dealing with the free rider problem. Indeed, by 
emphasizing the relationship between beneficiaries identified and cost 
allocation, the court's ruling supports greater attention to that 
issue. Finally, we note that under this Final Rule, transmission 
planning regions are not required to analyze the distribution of 
benefits on an entity-by-entity basis; nothing in this Final Rule 
precludes the regions from doing so, provided that they satisfy the 
cost allocation principles adopted herein. We now turn to other 
individual comments that involve these issues.
---------------------------------------------------------------------------

    \425\ ColumbiaGrid Comments at 29 (citing Illinois Commerce 
Commission, 576 F.3d 470 at 476 (emphasis supplied by 
ColumbiaGrid)).
    \426\ Id.
    \427\ This point applies equally to Sacramento Municipal Utility 
District's objection that the other Commission and court cases 
pertaining to MISO cited in the Proposed Rule are not on point 
because they involve instances where a customer relationship of some 
type had already been established, and that all that these cases 
dealt with was whether an allocation was just and reasonable. When 
Sacramento Municipal Utility District states that ``the cost 
allocation methods approved by FERC in the MISO cases rested on the 
understanding that `the ultimate costs allocated to [MISO] or PJM 
for a so-called cross-border allocation project will be recovered by 
each RTO pursuant to the applicable provisions of their tariffs,' '' 
it is ignoring substance in favor of form. It is focusing on the 
formal mechanisms through which costs are collected, not the 
underlying substance of the cost allocation itself. See Sacramento 
Municipal Utility District Comments at 14 (citing Midwest Indep. 
Transmission Sys. Operator, Inc., 113 FERC ] 61,194 at P 4). The 
mechanism for recovering a rate does not change the identity of the 
provider who is in fact recovering it.
---------------------------------------------------------------------------

    538. Southern Companies' argument that the primary beneficiary of a 
transmission facility is the customer that made the request that causes 
the improvements to be planned and constructed tends to blur the 
distinction between benefits and burdens. As discussed above, the 
courts have acknowledged that distinction as relevant to cost 
allocation and the requirements in this Final Rule are consistent with 
that distinction. To the extent that commenters are supporting 
participant funding as a regional cost allocation method, we address 
those comments below.\428\
---------------------------------------------------------------------------

    \428\ See discussion infra section IV.F.2.
---------------------------------------------------------------------------

    539. We disagree with Sacramento Municipal Utility District and 
Southern Companies that AEP applies only in exceptional circumstances 
and does not support our position here. In that case, the Commission 
expressed a preference for a voluntary resolution of the problem that 
loop flow represented, a position that is consistent with our findings 
here. The Commission's authority is not limited in principle by cases 
where the Commission expresses a preference not to exercise that 
authority. We also disagree with Sacramento Municipal Utility District 
that our reforms represent a perversion of the statutory scheme in 
which an entity could build a transmission facility and then simply 
claim a right to payment for benefits from beneficiaries with which it 
has no contractual or tariff relationship. As we state above, the 
Commission's jurisdiction is broad enough to allow it to ensure 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 transmission facilities. Our cost 
allocation reforms are tied to our transmission planning reforms, which 
require that, to be eligible for regional 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. As such, the public utility 
transmission providers in the regional

[[Page 49927]]

transmission planning process identify the beneficiaries who will pay 
for the costs of the new transmission facility selected in a regional 
plan for purposes of cost allocation.
    540. The fact that the Commission has supported parts of its 
argument through reference to cases in which privity of contract 
existed between public utilities and the entities from which costs were 
recovered does not affect this conclusion.\429\ This issue was not 
before the court in any of these cases, and therefore the mere 
existence of privity of contract does not demonstrate the necessity of 
privity. In response to Nebraska Public Power District, we do not agree 
that the Mobile-Sierra doctrine has applicability here. We are dealing 
here with conditions under which costs can be recovered in rates, not 
conditions under which existing contracts rates can be altered.
---------------------------------------------------------------------------

    \429\ See Midwest Indep. Transmission Sys. Operator, Inc., 109 
FERC ] 61,168; Alliance Cos., 100 FERC ] 61,137.
---------------------------------------------------------------------------

    541. Contrary to ColumbiaGrid's position, Exxon Mobil Corp. does 
not apply here. As ColumbiaGrid states, in Exxon Mobil Corp. the court 
held that the Commission may not require distributors to accept or pay 
for additional service.\430\ Unlike the situation addressed in Exxon 
Mobil Corp., the requirements of this Final Rule with respect to cost 
allocation do not ``impose'' any new service on beneficiaries.
---------------------------------------------------------------------------

    \430\ See Exxon Mobil Corp., 430 F.3d 1166, 1176-77 (DC Cir. 
2005).
---------------------------------------------------------------------------

    542. We also note that our position on joint rates does not have 
any relevance here. The fact that the Commission cannot require two 
public utilities to charge a joint rate without evidence that their two 
systems are in fact acting as one does not preclude the Commission from 
permitting a single public utility to recover its costs from 
beneficiaries of the transmission facilities identified in the 
transmission planning process regardless of the formal customer 
relationships that exist prior to the time that cost allocation is 
authorized. We do not see how the conditions under which a joint rate 
can be imposed has any implications for the range of beneficiaries from 
which a single public utility can recover the costs of its transmission 
services, even when combined with recovery by other public utilities of 
related transmission facilities.
    543. We disagree with Northern Tier Transmission Group that we are 
delegating any authority to transmission providers. All proposed cost 
allocation methods will be subject to Commission approval, and all 
specific allocations will be incorporated in rates that must be filed 
with and accepted by the Commission.
    544. We agree with the Alabama PSC that citizens of Alabama should 
not be responsible for costs of transmission facilities from which they 
derive no benefits. Indeed, the Commission specified in the Proposed 
Rule as a principle of regional cost allocation that ``[t]hose that 
receive no benefit from transmission facilities, either at present or 
in a likely future scenario, must not be involuntarily allocated the 
costs of those facilities.'' \431\ With respect to interregional 
transmission coordination, the Commission specified that 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 facility.'' \432\ In 
addition, ``[c]osts cannot be assigned involuntarily under this rule to 
a transmission planning region in which that facility is not located.'' 
\433\ These cost allocation principles are adopted in this Final Rule, 
and its requirements thus conform fully with the position taken by the 
Alabama PSC.
---------------------------------------------------------------------------

    \431\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 164.
    \432\ Id. P 174.
    \433\ Id.
---------------------------------------------------------------------------

    545. Contrary to the claims of Indianapolis Power & Light, the 
reforms instituted in this Final Rule neither authorize nor will lead 
to subsidization of generation decisions by different states. 
Beneficiaries in one state are not subsidizing anyone in another state 
when they are allocated costs that are commensurate with the benefits 
that accrue to them, even if the transmission facility in question was 
built in whole or part as a result of the other state's transmission 
needs driven by Public Policy Requirements. If no benefits accrue, the 
cost allocation principles we adopt below would prohibit the allocation 
of costs to the non-beneficiaries. If benefits do accrue, however, 
there are no less benefits because Public Policy Requirements played a 
role in the decision to construct the transmission facility. We agree 
with ELCON that estimations of benefits require adequate support. We 
note, however, that benefits are not ``amorphous'' simply because costs 
are to be allocated ``in a manner that is roughly commensurate with 
estimated benefits.'' \434\ The courts have acknowledged the natural 
limits that accompany estimations made in the cost-allocation 
process.\435\
---------------------------------------------------------------------------

    \434\ The Commission discusses in detail the application of this 
cost allocation principle below.
    \435\ Illinois Commerce Commission, 576 F.3d 470 at 476-77 (``We 
do not suggest that the Commission has to calculate benefits to the 
last penny, or for that matter to the last million or ten million or 
perhaps hundred million dollars.''). See also MISO Transmission 
Owners, 373 F.3d 1361 at 1369 (``we have never required a ratemaking 
agency to allocate costs with exacting precision.''); Sithe, 285 
F.3d 1 at 5.
---------------------------------------------------------------------------

    546. We disagree with Coalition for Fair Transmission Policy that 
the Proposed Rule can be read to imply that the Commission may require 
consideration of broad policy goals that are far afield from the 
Commission's core mission. This Final Rule requires that public utility 
transmission providers establish a process for identifying those 
transmission needs driven by Public Policy Requirements that are to be 
considered in the transmission planning process.\436\ In doing this, we 
are simply acknowledging that such Public Policy Requirements are facts 
that may have consequences in the form of increasing or decreasing the 
demand for additional transmission facilities. We are not straying from 
our core mission when we acknowledge that these facts will affect 
matters that are central to that mission and accordingly require that 
they be considered in the transmission planning process, nor are we 
promoting any particular public policy by requiring a process to 
determine what, if any, transmission needs are driven by a Public 
Policy Requirement.\437\
---------------------------------------------------------------------------

    \436\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 4.
    \437\ See discussion supra section III.A.4.
---------------------------------------------------------------------------

    547. Directing a public utility transmission provider to adopt a 
specific cost allocation method or methods in advance does not infringe 
upon a utility's right to propose rates under section 205 of the FPA. 
It simply requires that rate filings meet certain standards. 
ColumbiaGrid cites Atlantic City as supporting the contrary position. 
In that case, the court held that the Commission could not require that 
the PJM Transmission Owners Agreement be modified to eliminate a 
provision that allowed a public utility transmission owner to make a 
unilateral filing to make changes in rate design or terms and 
conditions of jurisdictional services. The court held that public 
utilities have an express right under section 205 to make such filings, 
and the Commission could not require them to relinquish it.\438\ 
Nothing in this Final Rule has the effect of disenfranchising any 
individual or entity of rights under

[[Page 49928]]

section 205 to make filings. The Commission regularly establishes 
standards for filings under section 205, and doing so does not negate 
any rights under that section.
---------------------------------------------------------------------------

    \438\ Atlantic City, 295 F.3d 16, at 21 (DC Cir. 2002).
---------------------------------------------------------------------------

    548. In response to those commenters that argue that our cost 
allocation reforms will affect existing state jurisdiction over utility 
rates, it 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 
specific facts and circumstances, none of which are presented here.
    549. In response to Transmission Access Policy Study Group, we note 
that the issue of joint rates is beyond the scope of this proceeding. 
This Final Rule requires the development of cost allocation methods for 
regional and interregional transmission facilities in connection with 
its planning reforms. As described in the cases that commenters cite in 
their responses to Transmission Access Policy Study Group, the issue of 
joint, non-pancaked rates involves matters that are considerably 
broader than our transmission planning-based cost allocation reforms. 
The Commission will consider any calls for joint, non-pancaked rates on 
a case-by-case basis and in accordance with the principles established 
in these cases.

C. Cost Allocation Method for Regional Transmission Facilities

1. Commission Proposal
    550. The Proposed Rule would require that every public utility 
transmission provider develop a method, or set of methods, for 
allocating the costs of new transmission facilities that are included 
in the transmission plan produced by the transmission planning process 
in which it participates. If the public utility transmission provider 
is an RTO or ISO, then the method or methods would be required to be 
set forth in the RTO or ISO tariff. In other transmission planning 
regions, each public utility transmission provider would be required to 
set forth in its tariff the method or methods for cost allocation used 
in its transmission planning region. This method or methods would have 
to satisfy six regional cost allocation principles, discussed below.
    551. These regional cost allocation principles would apply only to 
the cost allocation method or methods for new transmission facilities 
selected in the regional transmission plan produced by the transmission 
planning process in which the public utility transmission provider 
participates. The Commission also stated that it did not intend to 
require a uniform cost allocation method that every region must adopt 
to allocate the costs of new regional transmission facilities that are 
eligible for cost allocation, but instead recognized that regional 
differences may warrant distinctions in cost allocation methods among 
transmission planning regions.\439\
---------------------------------------------------------------------------

    \439\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 165.
---------------------------------------------------------------------------

    552. The Commission stated in the Proposed Rule that with regard to 
a new transmission facility that is located entirely within one 
transmission owner's service territory, a transmission owner may not 
unilaterally invoke the regional cost allocation method to require the 
allocation of the costs of a new transmission facility to other 
entities in its transmission planning region. However, if the regional 
transmission planning process determines that a new facility located 
solely within a transmission owner's service territory would provide 
benefits to others in the region, allocating the facility's costs 
according to that region's regional cost allocation method or methods 
would be permitted.\440\
---------------------------------------------------------------------------

    \440\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 169.
---------------------------------------------------------------------------

2. Comments on Cost Allocation Method in Regional Transmission Planning
    553. A number of commenters generally support the Commission's 
proposal.\441\ For example, ITC Companies support the promulgation of a 
comprehensive, holistic cost allocation method generally applicable to 
new transmission facilities, citing SPP's highway/byway mechanism as a 
model.\442\
---------------------------------------------------------------------------

    \441\ E.g., MidAmerican; American Transmission; Clean Line; 
Dominion; East Texas Cooperatives; MISO; National Grid; NEPOOL; New 
York ISO; Multiparty Commenters; and WIRES.
    \442\ The arguments in support of this proposal are implicit in 
the comment summaries under the discussion of other cost allocation 
proposals below. See discussion infra section 0. The term ``highway/
byway'' refers to regionwide allocation of the cost of a new high 
voltage transmission facility and the allocation of the cost of a 
new lower voltage transmission facility to a defined portion of the 
region. See Southwest Power Pool, Inc., 131 FERC ] 61,252 (2010).
---------------------------------------------------------------------------

    554. Other commenters express concern with the Commission's 
proposal to require the development of a cost allocation method for 
transmission facilities included in a regional transmission plan.\443\ 
Bonneville Power asserts that mandatory regional cost allocation is not 
necessary to build new transmission in the Pacific Northwest, and such 
a requirement will lead to extended disputes and greater uncertainty. 
Bonneville Power contends that instead, voluntary participation, 
including participation in open seasons, is the best way to encourage 
the development of new transmission for renewables in the Pacific 
Northwest. California Commissions echo the sentiment that cost 
allocation has generally not been a major barrier to entry for new 
transmission in the West. California Commissions are concerned that the 
Commission may do more harm than good by moving aggressively and 
prescriptively on regional cost allocation methods that are not 
necessarily needed to support transmission development.
---------------------------------------------------------------------------

    \443\ E.g., Bonneville Power Administration; California 
Commissions; Eastern Massachusetts Consumer-Owned System; Xcel; and 
Western Area Power Administration.
---------------------------------------------------------------------------

    555. Some commenters, such as Bonneville Power, California ISO, and 
Western Area Power Administration, express a preference for voluntary 
coordination and cost allocation of transmission facilities rather than 
mandatory cost allocation rules. Coalition for Fair Transmission Policy 
urges the Commission to consider whether it is prudent in all cases to 
require the filing of regional cost allocation methods by transmission 
providers in advance of projects being proposed, as not every project 
will fit into a particular model, and adherence to strict rules may 
deter rather than encourage the construction of needed new transmission 
facilities.
    556. New York PSC indicates that it is uncertain as to whether the 
Commission intends to utilize a pre-established cost allocation 
methodology as an automatic right of cost recovery. Therefore, New York 
PSC requests that the Commission clearly indicate when a project would 
be entitled to cost recovery relative to receiving a cost allocation. 
Western Grid Group shares the view that the distinction between cost 
allocation and cost recovery is a pertinent issue. Arizona Public 
Service Company raises concerns about cost recovery in regions where no 
regional tariff mechanisms exist. In the absence of such a cost 
recovery solution, Arizona Public Service Company states that the 
Commission should not place the burden of recovery for third party 
developers on incumbent utilities that may be required to seek such 
recovery

[[Page 49929]]

through state commissions for facilities that the incumbent utilities 
have not built and for which the incumbent utilities may be unable to 
show benefit for their ratepayers.
    557. MISO Transmission Owners agree that a transmission provider 
should not be able to invoke the regional cost allocation method 
unilaterally for a facility located entirely within its own service 
territory. However, they state that in the RTO context, facilities 
located solely within one transmission owner's service territory should 
be allocated in accordance with the Commission-accepted cost allocation 
method. MISO Transmission Owners state that the Proposed Rule should 
not be interpreted to indicate that single-zone facilities are no 
longer eligible for regional cost allocation if such allocation is 
permitted under an RTO or ISO tariff. Additionally, MISO Transmission 
Owners argue that the Commission should not permit this requirement to 
allow attempts to relitigate existing cost allocation method that apply 
to intra-zonal transmission facilities.
3. Commission Determination
    558. We require that a 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. 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. In a non-RTO/ISO transmission 
planning region, each public utility transmission provider located 
within the region must set forth in its OATT the same language 
regarding the cost allocation method or methods used in its 
transmission planning region. In either instance, such cost allocation 
method or methods must be consistent with the regional cost allocation 
principles adopted below.
    559. We conclude that these regional transmission cost allocation 
requirements are necessary to ensure that rates, terms and conditions 
of jurisdictional service are just and reasonable and not unduly 
discriminatory or preferential. In the absence of clear cost allocation 
rules for regional transmission facilities, there is a greater 
potential that public utility transmission providers and nonincumbent 
transmission developers may be unable to develop transmission 
facilities that are determined by the region to meet their needs. 
Conversely, greater certainty as to the cost allocation implications of 
a potential transmission project will enhance the ability of 
stakeholders in the regional transmission planning process to evaluate 
the merits of the transmission project. Moreover, as we have 
established above, there is a fundamental link between cost allocation 
and planning, as it is through the planning process that benefits, 
which are central to cost allocation, can be assessed.
    560. We do not specify here how the costs of an individual regional 
transmission facility should be allocated. However, while each 
transmission planning region may develop a method or methods for 
different types of transmission projects, such method or methods should 
apply to all transmission facilities of the type in question. Although 
we allow a different method or methods for different types of 
transmission facilities, as discussed below regarding regional Cost 
Allocation Principle 6, if public utility transmission providers choose 
to propose a different cost allocation method or methods for different 
types of transmission facilities, each method would have to be 
determined in advance for each type of facility.
    561. We disagree with California Commissions that our actions here 
are too aggressive and prescriptive and with Bonneville Power that 
adopting a mandatory cost allocation method will lead to extended 
disputes and greater uncertainty. We have stressed throughout this 
proceeding that we intend to be flexible and are open to a variety of 
approaches to compliance. By imposing the cost allocation requirements 
adopted here, the Commission seeks to enhance certainty for developers 
of potential transmission facilities by identifying, up front, the cost 
allocation implications of selecting a transmission facility in the 
regional transmission plan for purposes of cost allocation. This does 
not undermine the ability of market participants to negotiate 
alternative cost sharing arrangements voluntarily and separately from 
the regional cost allocation method or methods. Indeed, market 
participants may be in a better position to undertake such negotiations 
as a result of the public utility transmission providers in the region 
having evaluated a transmission project. The results of that 
evaluation, including the identification of potential beneficiaries of 
the transmission project, could facilitate negotiations among 
potentially interested parties.
    562. In response to Coalition for Fair Transmission Policy, we 
require the development of a cost allocation method or a set of methods 
in advance of particular transmission facilities being proposed so that 
developers have greater certainty about cost allocation and other 
stakeholders will understand the cost impacts of the transmission 
facilities proposed for cost allocation in transmission planning. The 
appropriate place for this consideration is the regional transmission 
planning process because addressing these issues through the regional 
transmission planning process will increase the likelihood that 
transmission facilities selected in regional transmission plans for 
purposes of cost allocation are actually constructed, rather than later 
encountering cost allocation disputes that prevent their construction.
    563. With regard to comments regarding matters of cost recovery, we 
acknowledge that cost allocation and cost recovery are distinct. This 
Final Rule sets forth the Commission's requirements regarding the 
development of regional and interregional cost allocation methods and 
does not address matters of cost recovery. We disagree with Arizona 
Public Service Company, however that incumbent utilities may be 
unreasonably burdened by the potential of cost allocation for 
transmission facilities developed by third party developers. For any 
proponent of a transmission facility, whether an incumbent or a 
nonincumbent, to have the costs of a transmission facility allocated 
through the regional cost allocation method or methods, its 
transmission facility first must be selected in the regional 
transmission plan for purposes of cost allocation. This in turn 
requires a determination that the transmission project is an efficient 
or cost-effective solution pursuant to the processes the transmission 
providers in the region have put in place, including consultation with 
stakeholders. Therefore, the benefits of any such transmission project 
should have been clearly identified prior to the allocation of any 
related costs.
    564. With respect to cost allocation for a proposed transmission 
facility located entirely within one public utility transmission 
owner's service territory, we find that a public utility transmission 
owner may not unilaterally apply the regional cost allocation method or 
methods developed pursuant to this Final Rule. However, a proposed 
transmission facility located entirely within a public utility 
transmission owner's service territory could be determined by public 
utility transmission providers in the region to provide benefits to 
others in the region and thus the cost of that transmission facility 
could be allocated according to

[[Page 49930]]

that region's regional cost allocation method or methods.
    565. In response to MISO Transmission Owners' concerns regarding 
relitigation of existing Commission-approved transmission cost 
allocation methods, the Commission declines here to prejudge whether 
any such existing cost allocation methods comply with the requirements 
of this Final Rule. To the extent MISO Transmission Owners believe that 
to be the case with their region, they may take such positions during 
the development of compliance proposals and during Commission review of 
compliance filings. However, we reiterate here that our cost allocation 
reforms apply only to new transmission facilities that are selected in 
a regional transmission plan for purposes of cost allocation and, 
therefore, do not provide grounds for relitigation of cost allocation 
decisions for existing transmission facilities.

D. Cost Allocation Method for Interregional Transmission Facilities

1. Commission Proposal
    566. The Proposed Rule would require that each public utility 
transmission provider within a transmission planning region develop a 
method for allocating the costs of a new interregional transmission 
facility between the two neighboring transmission planning regions in 
which the facility is located or among the beneficiaries in the two 
neighboring transmission planning regions. This common method would 
have to satisfy six interregional cost allocation principles, discussed 
below.
    567. The Commission stated in the Proposed Rule that it would not 
apply the interregional cost allocation principles so as to require 
every pair of regions to adopt the same uniform approach to cost 
allocation for new interregional transmission facilities, but instead 
recognized that there may be legitimate reasons for the public utility 
transmission providers located in different pairs of neighboring 
transmission planning regions to adopt different cost allocation 
methods.\444\
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    \444\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 175.
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2. Comments on Interregional Cost Allocation Reforms
    568. A number of commenters generally support the proposal that 
each transmission provider have an interregional cost allocation method 
for facilities located in more than one region.\445\ NEPOOL states that 
it generally supports the proposal to require formal agreements between 
neighboring control areas that contain cost allocation methods for 
interregional projects, with such methods being subject to the 
principles specified in the Proposed Rule. East Texas Cooperatives 
support the application of the six proposed principles to interregional 
cost allocation methods. AEP states that getting these ground rules in 
place is essential to move forward on major interregional projects and 
to break down decades old barriers to these types of projects. 
Likewise, MidAmerican states that there is little if any coordination 
of transmission cost allocation between MISO and SPP regions and the 
MISO and MAPP regions and, as such, supports the Commission's efforts 
to create a more coordinated and effective way to allocate costs of new 
transmission facilities both within these planning regions and those 
linking adjacent planning regions.
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    \445\ E.g., AEP; Clean Line; MidAmerican; MISO; MISO 
Transmission Owners; NEPOOL; New England States Committee on 
Electricity; Northeast Utilities; Pennsylvania PUC; PSEG Companies; 
and Energy Consulting Group.
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    569. Vermont Electric states that it welcomes the proposed 
requirement for interregional coordination and the Commission's 
attention to what it views as deficiencies in the ISO New England 
transmission planning process. Vermont Electric states that the 
Commission's proposed requirement for a standard cost allocation method 
applicable to interregional projects would prevent delays, reduce costs 
for project developers, and facilitate development of potentially 
valuable interregional projects.
    570. A number of commenters question or express concern about the 
appropriateness of requiring the development of interregional cost 
allocation methods for future interregional transmission facilities in 
advance of a proposal for a specific interregional facility.\446\ For 
example, SoCal Edison notes that voluntary coordination efforts are 
underway, and it argues that there is no reason to impose additional 
mandatory interregional coordination criteria or requirements. ISO New 
England supports the preservation of a voluntary, flexible approach to 
interregional cost allocation that recognizes regional differences. ISO 
New England also states that the Final Rule should either clarify the 
manner in which agreement on cost allocation would be signified by each 
of the two regions or provide for flexibility in recognition of the 
mechanisms that may be most appropriate in light of the internal 
transmission planning processes of the paired regions.
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    \446\ E.g., New York ISO; Coalition for Fair Transmission 
Policy; California ISO; and National Grid.
---------------------------------------------------------------------------

    571. National Grid believes that interregional coordination 
agreements should include general cost allocation principles that will 
apply to interregional projects, but that it would not be beneficial to 
prescribe an interregional cost allocation method in advance of a 
specific interregional project. Similarly, New England Transmission 
Owners and New York Transmission Owners contend that, in light of the 
limited number of projects that are likely to be identified through 
interregional coordination, the Commission should allow cost allocation 
issues to be decided in connection with individual projects instead of 
dictating a generic cost allocation method in advance.
    572. Vermont Electric agrees, suggesting that the Commission impose 
an interregional requirement only to the extent regional planning 
organizations do not respond promptly and effectively to cost 
allocation issues applicable to interregional projects on a case-by-
case basis. New York ISO recommends that the Commission require 
neighboring regions to include language in their tariffs setting forth 
their obligation to negotiate cost allocation rules for any 
interregional projects that are approved in their respective planning 
processes and that such rules must comply with the cost allocation 
principles established in the Final Rule.
    573. Similarly, Transmission Agency of Northern California cautions 
against requiring the development of cost allocation principles between 
planning regions prior to the need for such coordination. California 
ISO and Indianapolis Power & Light also argue that the requirement for 
a mandatory advanced agreement on cost allocation before knowing the 
specific facts and circumstances of an interregional project is neither 
appropriate nor effective. Indianapolis Power & Light also states that 
it would be better to postpone development of such agreements until a 
specific interregional project has been proposed.
    574. California ISO states that the Commission should not mandate 
an interregional cost allocation method or methods because the existing 
case-by-case determination of cost allocation for interregional 
transmission facilities has worked well in the West. California ISO 
states that different parties will bring different interests to the 
table, and different circumstances may warrant different approaches to 
interregional cost allocation. However, California ISO states that 
regardless of what the

[[Page 49931]]

Commission concludes on this issue, it should retain in the Final Rule 
the concept that inclusion of an interregional transmission project in 
each of the relevant regional transmission plans would be a 
prerequisite to applying an interregional cost allocation 
principle.\447\ California ISO argues that this is necessary to ensure 
equitable cost allocation.
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    \447\ See also, e.g., Connecticut & Rhode Island Commissions.
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    575. Edison Electric Institute states that flexibility is 
especially important for multistate projects with a large number of 
likely beneficiaries. It states that flexibility also is important for 
different regions in developing interregional cost allocation methods, 
including methods that provide for a case-by-case evaluation of 
projects in lieu of using prescribed cost allocation formulas. Edison 
Electric Institute states that the Commission should allow a region to 
propose the evaluation of alternative cost-effective projects that 
would result in lower costs to the region's consumers.
    576. Edison Electric Institute also asks the Commission to be clear 
in the Final Rule about whether and how existing interregional cost 
allocation mechanisms and those under development in various regions 
will be affected, if at all. Transmission Dependent Utility Systems and 
Xcel support the proposed requirement, but request that the Commission 
not disrupt or disturb the methods already in place. New England 
Transmission Owners state that the Commission should permit New England 
and New York to move forward to develop coordinated interregional 
coordination based on the principles in their current agreement.
    577. SPP seeks clarification, consistent with Order No. 890, that 
transmission owning members of RTOs and ISOs can comply with the 
proposed interregional cost allocation mandates through their 
participation in the RTO or ISO and the interregional agreements 
executed by the RTO or ISO, rather than requiring them to negotiate 
with their neighbors to develop separate arrangements.
3. Commission Determination
    578. We require a 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.\448\ As we discuss further below, 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. For example, region A and 
region B could have a cost allocation method for the allocation of the 
costs of an interregional transmission facility between regions A and B 
(the interregional cost allocation method) that could differ from the 
respective regional cost allocation method that either region A or 
region B uses to further allocate its share of the costs of an 
interregional transmission facility. In an RTO or ISO region, the 
method must be filed in the OATT. In a non-RTO/ISO transmission 
planning region, the common cost allocation method or methods must be 
filed in the OATT of each public utility transmission provider in the 
transmission planning region. In either instance, such cost allocation 
method or methods must be consistent with the interregional cost 
allocation principles adopted below.
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    \448\ A group of three or more transmission planning regions 
within an interconnection--or all of the transmission planning 
regions within an interconnection--may agree on and file a common 
method or methods for allocating the costs of a new interregional 
transmission facility. However, the Commission does not require such 
multiregional provisions among more than two neighboring 
transmission planning regions.
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    579. As with our regional cost allocation requirements above, we 
are requiring interregional cost allocation requirements to remove 
impediments to the development of transmission facilities that are 
identified as needed by the relevant regions. We conclude 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. This may, in turn, adversely affect rates for 
jurisdictional services, causing them to become unjust and unreasonable 
or unduly discriminatory or preferential.
    580. As in the case of regional cost allocation, we do not require 
a single nationwide approach to interregional cost allocation but 
instead allow each pair of neighboring regions the flexibility to 
develop its own cost allocation method or methods consistent with the 
interregional cost allocation principles adopted in this Final Rule. We 
also clarify that we do not require each transmission planning region 
to have the same interregional cost allocation method or methods with 
each of its neighbors. Each pair of transmission planning 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. Our intention is to preserve the ability of each pair of 
transmission planning regions to plan for future development of 
interregional transmission projects that will be beneficial to both 
transmission planning regions.
    581. We do not specify here how the costs for an individual 
interregional transmission facility should be allocated. However, 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. Although we allow a different cost 
allocation method or methods for different types of transmission 
facilities, as discussed below regarding Interregional Cost Allocation 
Principle 6, if public utility transmission providers choose to propose 
a different cost allocation method or methods for different types of 
transmission facilities, each cost allocation method would have to be 
determined in advance for each type of transmission facility. Also, we 
adopt the requirement that an interregional transmission facility must 
be in the relevant regional transmission plans to be eligible for 
interregional cost allocation pursuant to the interregional cost 
allocation method or methods.
    582. Additionally, a central underpinning to our reforms in this 
Final Rule is the closer alignment of transmission planning and cost 
allocation. As we discuss above in the section on interregional 
transmission coordination,\449\ an interregional transmission facility 
must be selected in both of the relevant regional transmission planning 
processes for purposes of cost allocation in order to be eligible for 
interregional cost allocation pursuant to a cost allocation method 
required under this Final Rule. This is designed, among other things, 
to allow for adequate stakeholder review of the interregional 
transmission facility before the relevant portion of the facility is in 
a regional transmission plan.\450\ This process could be undermined if 
a transmission facility that is located and

[[Page 49932]]

reviewed only within one regional transmission planning process, could 
nevertheless have its costs allocated to potential beneficiaries in 
another region that may not have had an adequate opportunity to review 
the need for the transmission facility and make the resulting 
beneficiary determinations. As we make clear in our discussion of Cost 
Allocation Principle 4,\451\ costs may be assigned on a voluntary basis 
under this Final Rule to a transmission planning region in which an 
interregional transmission facility is not located. 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.
---------------------------------------------------------------------------

    \449\ See discussion supra section III.C.
    \450\ See discussion supra section III.C.
    \451\ See discussion infra section IV.E.5.
---------------------------------------------------------------------------

    583. With respect to existing interregional transmission 
coordination and cost allocation agreements, we do not opine here on 
whether such agreements satisfy the interregional transmission 
coordination requirements and cost allocation principles of this Final 
Rule.\452\ To the extent that a public utility transmission provider 
believes such an agreement satisfies these requirements in whole or in 
part, that public utility transmission provider should describe in its 
compliance filing how the relevant requirements are satisfied by 
reference to tariff sheets on file with the Commission.
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    \452\ Public utility transmission providers may continue to 
enter into such agreements as a means of complying with this Final 
Rule, but any such agreements that are incorporated into the public 
utility transmission provider's OATT by reference must be consistent 
with or superior to this Final Rule.
---------------------------------------------------------------------------

    584. We also clarify in response to commenters that the requirement 
to coordinate with neighboring regions applies to public utility 
transmission providers within a region as a group, not members within 
an RTO or ISO acting individually. Therefore, within an RTO or ISO, the 
RTO or ISO would develop an interregional cost allocation method or 
methods with its neighbors on behalf of its public utility transmission 
owning members.

E. Principles for Regional and Interregional Cost Allocation

1. Use of a Principles-Based Approach
a. Commission Proposal
    585. For the cost allocation method or methods to be just and 
reasonable and not unduly discriminatory or preferential, the Proposed 
Rule would require that each cost allocation method satisfy six general 
cost allocation principles, as set out in the following subsections. 
The Commission proposed six regional cost allocation principles for 
each cost allocation method for regional transmission facilities 
included in the regional transmission plan for purposes of cost 
allocation and six analogous interregional cost allocation principles 
for each cost allocation method for a new transmission facility that is 
located in two neighboring transmission planning regions and is 
accounted for in the interregional transmission coordination process.
    586. Specifically, the Proposed Rule would require that each RTO or 
ISO (on behalf of its transmission owning members) or the individual 
public utility transmission providers in a non-RTO/ISO transmission 
planning region to demonstrate through a compliance filing that its 
cost allocation method or methods for new transmission facilities 
satisfy the following regional cost allocation principles:

    (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.\453\ 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 established by state or federal laws or regulations 
that may drive transmission needs.\454\
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    \453\ See Illinois Commerce Commission, 576 F.3d 470 at 476-77 
(stating that ``[w]e do not suggest that the Commission has to 
calculate benefits to the last penny, or for that matter to the last 
million or ten million or perhaps hundred million dollars''). See 
also MISO Transmission Owners, 373 F.3d 1361 at 1369 (stating that 
``we have never required a ratemaking agency to allocate costs with 
exacting precision''); Sithe, 285 F.3d 1 at 5.
    \454\ As discussed above, the Commission proposed to require 
each public utility transmission provider to amend its OATT such 
that its local and regional transmission planning processes 
explicitly provide for consideration of Public Policy Requirements 
established by state or federal laws or regulations that drive 
transmission needs. As discussed above, we adopt this requirement in 
this Final Rule.
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    (2) Those that receive no benefit from transmission facilities, 
either at present or in a likely future scenario, must not be 
involuntarily allocated the costs of those facilities.
    (3) If a benefit to cost threshold is used to determine which 
facilities have sufficient net benefits to be included in a regional 
transmission plan for the purpose of cost allocation, it must not be 
so high that facilities with significant positive net benefits are 
excluded from cost allocation. A transmission planning region or 
public utility transmission provider may want to choose 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 greater ratio.
    (4) The allocation method for the cost of a regional facility 
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.\455\ 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 there is an agreement for the original region 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 entities in the original region.
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    \455\ In addition, the Commission preliminarily found that this 
principle does not affect the cross-border cost allocation methods 
developed by PJM and MISO in response to Commission directives 
related to their intertwined configuration. Midwest Indep. 
Transmission Sys. Operator, Inc., 113 FERC ] 61,194, at P 10; 
Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ] 61,084; 
Midwest Indep. Transmission Sys. Operator, Inc., 129 FERC ] 61,102. 
As noted above, we adopt this finding in this Final Rule.
---------------------------------------------------------------------------

    (5) The cost allocation method and data requirements for 
determining benefits and identifying beneficiaries for a 
transmission facility must be transparent with adequate 
documentation to allow a stakeholder to determine how they were 
applied to a proposed transmission facility.
    (6) A transmission planning region may choose to use a different 
cost allocation method for different types of transmission 
facilities in the regional plan, such as transmission facilities 
needed for reliability, congestion relief, or to achieve public 
policy requirements established by state or federal laws or 
regulations. Each cost allocation method must be set out clearly and 
explained in detail in the compliance filing for this Final 
Rule.\456\
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    \456\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 164.

    587. The Proposed Rule required each cost allocation method to 
---------------------------------------------------------------------------
comply with the following interregional cost allocation principles:

    (1) The costs of a new interregional facility must be allocated 
to each transmission planning region in which that facility is 
located in a manner that is at least roughly commensurate with the 
estimated benefits of that 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 established by state or federal laws or regulations 
that may drive transmission needs.
    (2) A transmission planning region that receives no benefit from 
an interregional

[[Page 49933]]

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 facility.\457\
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    \457\ For example, a DC line that runs from a first transmission 
planning region, through a second transmission planning region, and 
into a third transmission planning region, with no tap in the second 
region, may not provide any benefits to the second region.
---------------------------------------------------------------------------

    (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 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.
    (4) Costs allocated for an interregional facility must be 
assigned only to transmission planning regions in which the facility 
is located. Costs cannot be assigned involuntarily under this rule 
to a transmission planning region in which that facility is not 
located. However, the interregional planning process must identify 
consequences for other transmission planning regions, such as 
upgrades that may be required in a third transmission planning 
region and, if there is an agreement among the transmission 
providers in the regions in which the facility is located to bear 
costs associated with such upgrades, then the interregional cost 
allocation method must include provisions for allocating the costs 
of the upgrades within the transmission planning regions in which 
the facility is located.
    (5) The cost allocation method and data requirements for 
determining benefits and identifying beneficiaries for an 
interregional facility must be transparent with adequate 
documentation to allow a stakeholder to determine how they were 
applied to a proposed transmission facility.
    (6) The public utility transmission providers located in 
neighboring transmission planning regions may choose to use a 
different cost allocation method for different types of 
interregional facilities, such as transmission facilities needed for 
reliability, congestion relief, or to achieve public policy 
requirements established by state or federal laws or regulations. 
Each cost allocation method must be set out and explained in detail 
in the compliance filing for this rule.

    588. The Proposed Rule also states that public utility transmission 
providers will have the first opportunity to develop cost allocation 
methods for regional and interregional transmission facilities in 
consultation with stakeholders. In the event that no agreement can be 
reached, the Commission 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.
b. Comments on Use of Principles-Based Approach
    589. Many commenters generally support the use of cost allocation 
principles although this support is often expressed as part of general 
support for the Proposed Rule's six proposed cost allocation principles 
as a package.\458\ For example, Dominion believes that by providing 
cost allocation principles linked to planning, the Commission has taken 
the correct approach without being overly prescriptive. Dayton Power 
and Light states that these principles help to reduce uncertainty and 
provide guidance to interested stakeholders. Energy Future Coalition 
Group states that the proposed principles follow the direction laid out 
by the court in the Illinois Commerce Commission case, and address 
legitimate concerns that have been raised by some opponents of broad 
cost allocation policy over the past two years. On the other hand, as 
discussed above,\459\ some comments oppose any generic action on 
regional and interregional cost allocation and therefore do not support 
the use of cost allocation principles to support such action.
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    \458\ E.g., DC Energy; WIRES; Dominion; and Dayton Power and 
Light.
    \459\ See discussion supra section II.
---------------------------------------------------------------------------

    590. Almost all commenters urge the Commission not to adopt a 
``one-size-fits-all'' approach to cost allocation and to retain 
regional and interregional flexibility.\460\ For example, APPA and 
Transmission Agency of Northern California state that the Commission 
should not prescribe a uniform approach to interregional transmission 
cost allocation, and should allow for regional and interregional 
differences. Transmission Agency of Northern California states that 
this issue is being addressed at a level where local and regional 
differences can be addressed more fully, and that it supports the 
Proposed Rule's assumption that this ongoing process should not be 
disrupted by this rulemaking.
---------------------------------------------------------------------------

    \460\ E.g., Large Public Power Council; Kansas Corporation 
Commission; and Nebraska Public Power District.
---------------------------------------------------------------------------

    591. Several commenters ask the Commission to address the Proposed 
Rule's provision regarding ``in the event that no agreement can be 
reached.'' \461\ They contend that if the Commission adopts a rule 
providing that it would select a backstop cost allocation method in the 
event that stakeholders within a region cannot agree to a regional cost 
allocation method or if regions cannot agree on a cost allocation 
method for interregional projects, the Commission should provide 
additional guidance that would help stakeholders to reach agreement. 
For example, Multiparty Commenters request that the Commission clarify: 
The level of stakeholder agreement that is acceptable; what would be 
evidence of an impasse; whether the Commission will defer to the 
majority; and whether the Commission will extend the time in which to 
make compliance filings to afford more time to obtain an agreement. 
Similarly, for interregional cost allocation, Anbaric and PowerBridge 
recommend that the Commission stipulate a reasonable period of time for 
regions to reach agreement on a proposed interregional cost allocation 
method.
---------------------------------------------------------------------------

    \461\ E.g., Anbaric and PowerBridge; AWEA; MidAmerican; 
Multiparty Commenters; and Southern Companies.
---------------------------------------------------------------------------

    592. Some commenters recommend that the Commission adopt an 
interregional default cost allocation method if regions cannot agree to 
such a method themselves, although they note that specific projects 
will involve unique facts and circumstances. Anbaric and PowerBridge 
believe that, if regions cannot agree on an interregional cost 
allocation method, the Commission could impose an agreement based on 
the facts and circumstances of the project. Massachusetts Municipal and 
New Hampshire Electric state that, even if an interregional default 
method is implemented, whether by mutual agreement or by Commission 
directive, disputes will arise about the application of that method to 
a given set of facts. Massachusetts Municipal and New Hampshire 
Electric suggest that the Commission can address these concerns by 
adopting expedited hearing procedures to be applied in such cases.
    593. Other commenters suggest a variation on or alternative to the 
idea that the Commission adopt a default cost allocation method for 
regional and interregional cost allocation if stakeholders or regions 
cannot come to a consensus themselves.\462\ Wind Coalition states that 
having a default cost allocation method would allow construction to 
commence while an alternative cost allocation method is being 
developed, if needed. It states that this would be particularly needed 
for cross-border cost allocation because there are currently few 
interregional agreements on cost allocation. Wind Coalition also states 
that matching cost

[[Page 49934]]

allocation with a proactive regional or interregional plan is important 
for justifying regional cost sharing.
---------------------------------------------------------------------------

    \462\ E.g., American Transmission; AWEA; NextEra; and Wind 
Coalition.
---------------------------------------------------------------------------

    594. Some commenters argue that, if a region or regions fail to 
agree on a method, the Commission should not select a default cost 
allocation method and also should not select a cost allocation method 
based on the record here.\463\ APPA contends that adoption of a default 
cost allocation method or particular cost allocation principles or 
guidelines would influence the prospects for successful regional and 
interregional negotiation because stakeholders that support the default 
method will be unwilling to negotiate, knowing that if no agreement is 
reached, their preferred method will be adopted as the default. PSEG 
Companies argue that adoption of a single default cost allocation 
method would be inconsistent with the Proposed Rule's ``beneficiary 
pays'' approach. PSEG Companies believe that the ``roughly 
commensurate'' standard that the Illinois Commerce Commission decision 
requires will be satisfied only by happenstance under a default cost 
allocation method. PSEG Companies also disagree with comments by 
National Grid, AEP, and others that the Commission should institute a 
default cost allocation method for transmission planning regions that 
would apply regardless of the nature of the facilities planned (i.e., 
reliability or economic). PSEG Companies suggest that the Commission 
clarify how interregional cost allocation will be handled in the 
absence of an interregional agreement, and it should make clear that 
the existence of such an agreement is a prerequisite to the assignment 
of costs to another transmission planning region and its customers. 
PSEG Companies also state that, if certain regions decline to enter 
into interregional agreements, the Commission should adopt a ``do not 
harm'' standard applicable to such regions as a corollary principle, 
that is, no region may plan its system in a way that would impose costs 
on other regions.
---------------------------------------------------------------------------

    \463\ E.g., APPA and PSEG Companies.
---------------------------------------------------------------------------

    595. Some commenters suggest a particular default method that the 
Commission should adopt if it decides to have a default cost allocation 
method, such as the SPP highway/byway mechanism.\464\ However, other 
commenters express concern with establishing a ``one-size-fits-all'' 
default allocation method.\465\ In particular, New England States 
Committee on Electricity and Identified New England Transmission Owners 
urge the Commission to reject recommendations to adopt the highway/
byway mechanism as a default cost allocation method, instead asking the 
Commission to respect regional differences. Sunflower and Mid-Kansas 
submit that the Final Rule should provide for two-third regional (or 
interregional) allocation of costs and one-third to the ultimate sink 
zone for all network upgrades approved through an interregional plan 
that are needed for variable energy resource integration.
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    \464\ Several commenters suggested this method including AWEA, 
Multiparty Commenters, and NextEra.
    \465\ E.g., Connecticut & Rhode Island Commissions; Kansas 
Corporation Commission; Salt River Project; WIRES; and Wisconsin 
Electric.
---------------------------------------------------------------------------

    596. With respect to the question of whether the Commission should 
establish an interim cost allocation method until stakeholders have 
time to reach consensus, AWEA states that the current market structure 
and the mechanisms used to allocate costs between transmission 
providers outside organized market regions needs to mature further 
before transmission providers in many of these market regions will be 
able to fully comply with the Proposed Rule. It states that if 
transmission providers outside organized market regions cannot 
demonstrate a binding cost allocation method as envisioned by the 
Proposed Rule, it would be appropriate for the Commission to consider 
an interim method to address cost allocation in those regions, such as 
using an ``intertie open season'' to create a record about the 
appropriate allocation of costs.
    597. NextEra suggests that, for non-RTO regions, regional cost 
recovery should be promoted by an adder on the transmission rates of 
public utility transmission providers (and extended to non-
jurisdictional utilities via reciprocity). Southern Companies respond 
that this approach is not feasible because it does not address the fact 
that their OATT recovers only the share of the cost attributable to 
their provision of wholesale transmission service. Southern Companies 
state that even with an adder, third parties would be limited to 
recovering approximately 15 percent of their transmission costs, which 
is comparable to Southern Companies' cost recovery.
    598. Massachusetts Departments and MidAmerican state that the 
Commission should narrowly apply any authority it has to develop a cost 
allocation method only for specific projects rather than requiring an 
established mechanism for all projects. For instance, MidAmerican 
proposes that the Commission adopt a default cost allocation method 
that would be used only if the stakeholders fail to agree regarding a 
500 kV or higher alternative current facility (except high voltage 
direct current projects) that is identified by the planning process as 
providing widespread benefits. In this limited case, MidAmerican 
suggests that the Commission adopt a streamlined dispute resolution 
mechanism with a rebuttable presumption in favor of specified regional 
and interregional cost allocation methods. MidAmerican states that the 
record in the proceeding before the Commission on remand from the 
Seventh Circuit Illinois Commerce Commission opinion, demonstrates the 
reliability, economic, and societal benefits of 500 kV and above 
transmission, and it also documents that these benefits are realized 
regionwide whenever extra-high voltage transmission is deployed.
    599. Wisconsin Electric states that it may be useful to consider 
the extent to which statewide stakeholder collaboratives could be 
effective in helping to resolve interstate cost allocation and cost 
recovery controversies. It points to California's Renewable Energy 
Transmission Initiative, which distinguishes stakeholders who are 
willing to work in good faith to resolve a project from those who only 
oppose transmission for self-interested reasons. Northwestern 
Corporation (Montana) is concerned that the proposal could have 
uneconomic consequences in that a high-cost allocation solution could 
be involuntarily allocated to an unwilling entity that has a lower-cost 
solution. Northern Tier Transmission Group is also worried about the 
difficulties that would arise in the context of allocating costs to 
entities that are unwilling to incur them.
    600. Some commenters state that the Commission should not close the 
door on existing or evolving processes.\466\ Salt River Project states 
that requiring involuntary cost sharing would risk foreclosure of 
promising alternatives and superior options for reliable and least-cost 
service for customers. Salt River Project is also concerned that 
arbitrary solutions could result that fail to honor local and regional 
interests.
---------------------------------------------------------------------------

    \466\ In addition, WIRES also notes that a default method where 
regional parties reach an impasse may look more attractive if the 
Commission's principles provide only generalized guidance. However, 
WIRES states that greater reliance on principled, up-front guidance 
for allocating the costs of transmission can provide a high degree 
of reassurance to parties engaged in negotiating a method. It states 
that only the Commission can provide this level of certainty.

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

[[Page 49935]]

    601. Dominion states that it is unlikely any imposed allocation 
method will generate uniform agreement or consensus so if competing 
principled approaches are proposed, the Commission should not make a 
ruling in favor of one over the other, but consider whether a blended 
approach could result in a just and reasonable solution. Southern 
Companies state that the policies of promoting the expansion of the 
transmission grid would be better served by developing a set of 
reasonable cost allocation principles that would be used to develop a 
cost allocation method only when an actual, multi-jurisdictional 
project is pursued. With respect to interregional cost allocation, New 
York Transmission Owners argue that it is neither necessary nor 
reasonable for the Commission to impose an interregional cost 
allocation method if one is not agreed to by the regions.
    602. Further, other commenters tell us that principles alone are 
not enough, and propose alternative solutions. These comments are 
summarized and addressed below in the discussion of the proposed cost 
allocation principles.
c. Commission Determination
    603. The Commission requires each public utility transmission 
provider to show on compliance that its cost allocation method or 
methods for regional cost allocation and its cost allocation 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. Commission 
determinations on each cost allocation principle are set out in the 
subsections below. 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. 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. These 
cost allocation principles do not apply to other new transmission 
facilities and therefore do not foreclose the opportunity for a 
developer or individual customer to voluntarily assume the costs of a 
new transmission facility, as discussed further below in the 
Participant Funding subsection.
    604. We adopt the use of cost allocation principles because we do 
not want to prescribe a uniform method of cost allocation for new 
regional and interregional transmission facilities for every 
transmission planning region. To the contrary, we recognize that 
regional differences may warrant distinctions in cost allocation 
methods among transmission planning regions. Therefore, we retain 
regional flexibility and allow the public utility transmission 
providers in each transmission planning region, as well as pairs of 
transmission planning regions, to develop transmission cost allocation 
methods that best suit the needs of each transmission planning region 
or pair of transmission planning regions, so long as those approaches 
comply with the regional and interregional cost allocation principles 
of this Final Rule.
    605. The Commission recognizes that a variety of methods for cost 
allocation may satisfy a set of general principles. For example, 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.\467\ Similarly, other methods that would allocate costs 
to a narrower class of beneficiaries may be appropriate, provided that 
the methods reflect an evaluation of beneficiaries and is adequately 
defined and supported by the transmission planning region or pairs of 
transmission planning regions.
---------------------------------------------------------------------------

    \467\ We address comments below suggesting that the cost 
allocation principles be applied to require regional cost sharing 
for all transmission facilities at 345 kV or higher.
---------------------------------------------------------------------------

    606. In response to comments that request further detail from the 
Commission on what an appropriate cost allocation method would look 
like, we conclude that public utility transmission providers in each 
transmission planning region or pair of transmission planning regions 
must be allowed the opportunity to determine for themselves the cost 
allocation method or methods to adopt based on their own regional needs 
and characteristics, consistent with the six cost allocation 
principles. With the exception of the limitation on participant funding 
explained below, we decline to prejudge any particular method or set of 
methods generically in this Final Rule.
    607. 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 its proposed requirements. 
Public 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 
as necessary for the Commission to make a determination of the 
appropriate cost allocation method or methods. Each public utility 
transmission provider must make an individual compliance filing that 
includes its own proposed method or set of methods of allocating costs 
and explains how it believes its method or methods satisfy the cost 
allocation principles and is appropriate for its transmission planning 
region or pair of transmission planning regions. Groups of public 
utility transmission providers that agree on a proposed method or 
methods may make a coordinated filing or filings with their common 
views. The public utility transmission providers in each transmission 
planning region or pair of transmission planning regions will have the 
burden of demonstrating that sufficient effort has been made to comply 
with the requirements of this Final Rule.
    608. Interested parties will be provided an opportunity to comment 
on these compliance filings, thereby creating a record on which the 
Commission could develop an appropriate cost allocation method or 
methods, or establish further procedures to do so. We do not impose 
other specific filing requirements for what the record should contain. 
As with any other proceeding before the Commission, should more 
information become necessary during the Commission's review process, 
the Commission may request more information from the parties at that 
time.
    609. The Commission will consider in response to compliance filings 
all issues raised by commenters, such as what constitutes an impasse, 
whether there should be deference to the majority, and whether granting 
additional time for the region to continue negotiations would be 
appropriate. The procedural mechanisms used by the Commission in 
response to compliance filing(s) will depend on the nature of remaining

[[Page 49936]]

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. The Commission will not prejudge the outcome of the dispute 
by stating at this time whether there should be deference to the views 
of any particular segment of stakeholders, as suggested by Multiparty 
Commenters.
    610. We decline to adopt a default regional or interregional cost 
allocation method in this Final Rule. We decline to do so for reasons 
similar to the reasons we declined to impose a uniform cost allocation 
method for all transmission planning regions. Many factors may make it 
appropriate for different transmission planning regions to have 
different cost allocation methods. It thus would not be practical or 
reasonable for the Commission to establish such default methods. We 
agree with APPA and others that having a known default method would 
cause those who favor it not to negotiate in good faith for an 
alternative cost allocation method. For these same reasons, we will not 
establish an interim cost allocation method that applies between the 
time of the issuance of this Final Rule and the time when stakeholders 
reach a consensus.
    611. The twelve regional and interregional proposed cost allocation 
principles are discussed below in pairs of six separate subsections. 
Because the proposed cost allocation principles for regional 
transmission facilities are very similar to the proposed cost 
allocation principles for interregional transmission facilities, almost 
all commenters discussed them together as if they were a single 
principle. Therefore, the Commission discusses the corresponding sets 
of cost allocation principles together and, except where otherwise 
indicated, the Commission determinations regarding each set of cost 
allocation principles apply to both the regional and interregional 
transmission facilities in a regional transmission plan for purposes of 
cost allocation. The cost allocation principles in the Final Rule apply 
only to those new transmission facilities selected in a regional 
transmission plan for purposes of cost allocation and new transmission 
facilities subject to the cost allocation provision of the 
interregional coordination procedures in an OATT.
2. Cost Allocation Principle 1--Costs Allocated in a Way That is 
Roughly Commensurate With Benefits \468\
---------------------------------------------------------------------------

    \468\ For the full text of this principle, see P 0 for regional 
cost allocation and P 0 for interregional cost allocation.
---------------------------------------------------------------------------

a. Comments
    612. Many commenters generally support the Commission's first 
proposed cost allocation principle for both regional and interregional 
cost allocation, which provides that the costs of transmission 
facilities must be allocated to those that benefit in a manner at least 
roughly commensurate with the estimated benefits received.\469\ For 
example, Transmission Access Policy Study Group states that the roughly 
commensurate standard appears to be consistent with the Illinois 
Commerce Commission decision and cost causation principles. 
Additionally, Westar states that transmission customers in a region 
should not pay for transmission projects that do not provide 
commensurate benefits and that only transmission projects that have 
been thoroughly reviewed in the regional process, show a benefit to the 
region and are approved by the transmission provider should be included 
in regional rates. Commenters also generally support the Proposed 
Rule's proposal to adhere to cost causation principles and also support 
a ``beneficiaries pay'' approach.\470\ Dayton Power & Light comments 
that ``beneficiaries pay'' is the touchstone principle for cost 
allocation. American Forest & Paper argues that such an approach 
provides for better incentives for analysis of costs and alternatives.
---------------------------------------------------------------------------

    \469\ E.g., Bay Area Municipal Transmission Group; Santa Clara; 
Consolidated Edison and Orange & Rockland; Transmission Access 
Policy Study Group; United States Senators Dorgan and Reid; 
Professor Ignacio Perez-Arriaga; New York ISO; New York PSC; New 
York Transmission Owners; Westar; City and County of San Francisco; 
Conservation Law Foundation; Energy Future Coalition Group; Solar 
Energy Industries; and EarthJustice.
    \470\ E.g., Dayton Power & Light; Conservation Law Foundation; 
and American Forest & Paper.
---------------------------------------------------------------------------

    613. Several commenters, however, support a broader definition of 
benefits and beneficiaries.\471\ NextEra argues that the Final Rule 
should mandate that planning processes consider various types of 
benefits, rather than leaving it to a transmission provider's 
discretion. Old Dominion asserts that adopting a narrow approach to 
assessing benefits for cost allocation purposes would ignore the 
broader benefits associated with maintaining and expanding the regional 
high voltage transmission system--such as more options when making 
resources decisions in regional markets. Old Dominion notes that 
restricting the cost causation benefits to a snapshot in time would be 
problematic for dynamic high voltage regional transmission facilities. 
National Grid supports a cost allocation method that takes into account 
both the quantitative and qualitative benefits of transmission. Xcel 
suggests that the Commission permit methods, such as SPP's highway/
byway approach, which broadly allocate costs based on general 
determination of the benefits provided to a region and stakeholders. 
AWEA and Multiparty Commenters state that it does not make sense to use 
cost allocation mechanisms that look only at public policy requirements 
established by existing state or federal laws or regulations because 
transmission assets are used for 40 years or longer, and they encourage 
the Commission to clarify that the appropriate cost allocation 
mechanisms should take into account the benefits of transmission in 
addressing likely future public policy requirements as well as existing 
ones. American Antitrust Institute recommends that the pro-competitive 
benefits of transmission be recognized.
---------------------------------------------------------------------------

    \471\ E.g., NextEra; AWEA; EarthJustice; and Atlantic Grid.
---------------------------------------------------------------------------

    614. PUC of Ohio recommends that the definition of beneficiary also 
should include those who gain from the ability to place electricity 
onto the grid. It states that load should not be solely burdened with 
the costs of the transmission grid; generation should be responsible 
for its fair share of the costs. Maine Parties agree, characterizing a 
beneficiary pays as more consistent with cost causation principles than 
a cost socialization method.
    615. In response to comments supporting a broader definition of 
benefits, Powerex states that it disagrees that the Proposed Rule is 
intended to allow for allocation methods that could impose cross-
subsidization and states that cost allocation methods for 
jurisdictional facilities must adhere to cost causation principles. 
Powerex argues that state or federal public policy requirements do not 
constitute evidence of a general or undifferentiated benefit to all 
market participants. Thus, Powerex argues, the Final Rule should 
emphasize that cost causation principles are and will remain the 
foundation of all acceptable cost allocation methods and make clear 
that the Commission rejects cost allocation proposals or outcomes that 
depart from this principle by promoting cross-subsidization.
    616. PSEG Companies take issue with the Proposed Rule's suggestion 
that the determination of who constitutes a beneficiary may be based on 
an assessment of ``likely future scenarios,''

[[Page 49937]]

arguing that regional planners should not be prognosticators and that 
the more ``scenarios'' that are introduced, the more inexact and 
speculative their proposed plans and cost allocation determinations 
will become.
    617. Dayton Power & Light seeks clarification of what it considers 
an ambiguity in regional and interregional Principle 1, which allows a 
regional transmission planning process to consider the extent to which 
facilities ``in the aggregate'' provide benefits.\472\ Dayton Power & 
Light states that this language could be taken to mean that if the 
existing network benefits a utility, then that is a benefit that 
justifies the utility allocating to it the incremental costs created by 
a new transmission project located far away, even if the project did 
not provide incremental benefits. According to Dayton Power & Light, 
this result would be inconsistent with Illinois Commerce Commission 
decision.
---------------------------------------------------------------------------

    \472\ See Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 164, 
174.
---------------------------------------------------------------------------

    618. Some commenters also request that the proposed principle be 
expanded so that the costs of transmission facilities are allocated to 
those within the planning region and adjacent planning regions that 
benefit from those facilities.
    619. Some commenters request clarification regarding what 
constitutes ``benefits'' to be considered in any cost allocation 
method.\473\ Alabama PSC states that the cost allocation proposals are 
too vague and potentially overbroad, and it requests that the 
Commission make clear that costs cannot be recovered from retail 
customers. WIRES requests that the Commission articulate more clearly 
the definitions, presumptions, and methods associated with the 
beneficiary pays approach.
---------------------------------------------------------------------------

    \473\ E.g., California Municipal Utilities; Northern Tier 
Transmission Group; Omaha Public Power District; Gaelectric; and 
Atlantic Grid.
---------------------------------------------------------------------------

    620. A number of commenters differ on what constitutes ``benefits'' 
and who constitutes ``beneficiaries.'' Several commenters state concern 
that the definition of ``benefits'' could be interpreted too broadly, 
particularly with respect to transmission projects driven by public 
policy goals.\474\ Atlantic Wind Connection requests clarification as 
to how the costs associated with public policy initiatives would be 
fairly assigned to beneficiaries, so that a results-oriented action 
plan emerges from the process. Transmission Access Policy Study Group 
argues that benefits are difficult to quantify and cautions the 
Commission against including generalized social or environmental 
benefits in cost allocation calculations. Transmission Access Policy 
Study Group and Colorado Independent Energy Association argue that 
production cost savings by itself is not sufficient to identify the 
universe of beneficiaries.\475\ Transmission Access Policy Study Group 
argues, however, that the Commission should clarify that it will not 
accept cost allocation methods that assign costs regionally based on a 
presumption of some general, unquantified regional benefits or vague 
assertions of possible future benefits.
---------------------------------------------------------------------------

    \474\ E.g., Florida PSC; Public Power Council; Transmission 
Dependent Utility Systems; and Coalition for Fair Transmission 
Policy.
    \475\ E.g., Transmission Access Policy Study Group; and Colorado 
Independent Energy Association.
---------------------------------------------------------------------------

    621. Some commenters raise similar concerns about the difficulty of 
quantifying benefits, and they suggest that benefits resulting in 
allocation of costs be direct, clear, and identifiable.\476\ Other 
commenters also believe it is important to make sure cost allocation 
mechanisms do not favor long-line transmission development or 
artificially depress the value of local renewable resources.\477\ In 
its reply comments, Ohio Consumers' Council agree that benefits should 
not be defined too broadly and recommends that the Commission strictly 
adhere to cost causation principles in implementing the Final Rule. 
Further, Ohio Consumers' Council suggests that the Commission uphold 
cost causation principles by requiring substantial evidentiary showings 
of benefits and costs prior to approving the imposition of regional or 
interregional transmission costs on consumers. With respect to 
interregional cost allocation, North Carolina Agencies contend that if 
the Commission assumes benefits too broadly, a public utility's retail 
customers may bear a share of costs based on the policy objectives of 
other states. Alabama PSC shares this concern. According to Western 
Area Power Administration, only the direct beneficiaries of a project, 
i.e., beneficiaries that make direct use of the facilities, should be 
counted as ``beneficiaries,'' and to the extent that costs are 
allocated to such beneficiaries, only the costs associated with the 
least-cost method of achieving the benefits should be allocated. LS 
Power states that it is important for the Final Rule to acknowledge 
that the factors that drive transmission planning do not fully define 
the range of beneficiaries.
---------------------------------------------------------------------------

    \476\ E.g., East Texas Cooperatives and G&T Cooperatives.
    \477\ E.g., New England States Committee on Electricity; 
Nebraska Public Power District; Sacramento Municipal Utility 
District; California State Water Project; and Northeast Utilities.
---------------------------------------------------------------------------

b. Commission Determination
    622. The Commission adopts 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.\478\

and
---------------------------------------------------------------------------

    \478\ In the Proposed Rule, Regional Cost Allocation Principle 1 
referred to ``public policy requirements established by State or 
Federal laws or regulations that may drive transmission needs.'' As 
defined in P 0 of this Final Rule, we use ``Public Policy 
Requirements'' in Regional Cost Allocation Principle 1 and 
throughout our discussion of the Cost Allocation Principles.
---------------------------------------------------------------------------

    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.\479\

    \479\ We note that the phrase ``individually or in the 
aggregate'' is not contained in Interregional Cost Allocation 
Principle 1 because interregional transmission facilities are 
considered facility by facility by pairs of transmission planning 
regions, unless pairs of transmission planning regions choose to do 
otherwise.
---------------------------------------------------------------------------

    623. As discussed above,\480\ requiring a beneficiaries pay cost 
allocation method or methods is fully consistent with the cost 
causation principle as recognized by the Commission and the courts. As 
the Commission stated in Order No. 890, the one factor that it weighs 
when considering a dispute over cost allocation is whether a proposal

[[Page 49938]]

fairly assigns costs among those who cause the costs to be incurred and 
those who otherwise benefit from them.\481\ Therefore, it is 
appropriate here to adopt a cost allocation principle that includes as 
beneficiaries those that cause costs to be incurred or that benefit 
from a new transmission facility.
---------------------------------------------------------------------------

    \480\ See discussion supra P 0 and section V.B.
    \481\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 559.
---------------------------------------------------------------------------

    624. However, the Commission is not prescribing a particular 
definition of ``benefits'' or ``beneficiaries'' in this Final Rule. In 
our view, the proper context for further consideration of these matters 
is on review of compliance proposals and a record before us. Moreover, 
allowing the flexibility to accommodate a variety of approaches can 
better advance the goals of this rulemaking. The cost allocation 
principles are not intended to prescribe a uniform approach, but rather 
each public utility transmission provider should have the opportunity 
to first develop its own method or methods. Also, we recognize that 
regional differences may warrant distinctions in cost allocation 
methods.
    625. While some commenters express concerns that the definition of 
benefits could be interpreted too broadly or too narrowly, we do not 
believe that further defining ``benefits'' in this Final Rule is a 
necessary or appropriate means to ensure that this will not be the 
case. We expect that concerns regarding overly narrow or broad 
interpretation of benefits will be addressed in the first instance 
during the process of public utility transmission providers consulting 
with their stakeholders. 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 the comments that note the potential 
difficulties in quantifying benefits. We note in response to 
Transmission Access Policy Study Group, that any benefit used by public 
utility transmission providers in a regional cost allocation method or 
methods must be an identifiable benefit and that the transmission 
facility cost allocated must be roughly commensurate with that benefit. 
Western Area Power Administration takes the position that beneficiaries 
should be limited to those that it describes as making direct use of 
the transmission facilities in question, but this fails to acknowledge 
that other benefits may accrue to an interconnected transmission grid.
    626. We agree with Powerex that a departure from cost causation 
principles can result in inappropriate cross-subsidization. This is why 
cost causation is the foundation of an acceptable cost allocation 
method. In response to PSEG Companies, we disagree 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. Scenario 
analysis is a common feature of electric power system planning, and we 
believe 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.
    627. In response to Dayton Power & Light, the provisions of 
Regional Cost Allocation Principle 1 regarding determination of the 
beneficiaries of transmission facilities ``individually or in the 
aggregate'' refer only to cost allocation for new transmission 
facilities. The public utility transmission providers in a transmission 
planning region may 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. We did not intend this language to be a 
finding that the benefits of existing transmission facilities in and of 
itself may justify cost sharing for new transmission facilities. We are 
not ruling on that matter in this Final Rule.
    628. We also decline to expand, as requested by some commenters, 
the scope of beneficiaries for new transmission facilities such that 
costs may be involuntarily allocated to those within an adjacent 
planning region that benefit from those facilities. As discussed in 
adopting Cost Allocation Principle 4 below, the allocation of the cost 
of a transmission facility that is located entirely within one 
transmission planning region may not be subject to a regional cost 
allocation method or methods pursuant to this Final Rule that assigns 
some or all of the cost of that transmission facility to beneficiaries 
in another transmission planning region without reaching an agreement 
with those beneficiaries.\482\
---------------------------------------------------------------------------

    \482\ See discussion infra section IV.E.5.
---------------------------------------------------------------------------

    629. Finally, 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.
3. Cost Allocation Principle 2--No Involuntary Allocation of Costs to 
Non-Beneficiaries \483\
---------------------------------------------------------------------------

    \483\ For the full text of this principle, see P 0 for regional 
cost allocation and P 0 for interregional cost allocation.
---------------------------------------------------------------------------

a. Comments
    630. Most of the commenters that addressed proposed Cost Allocation 
Principle 2 support it.\484\ Ad Hoc Coalition of Southeastern Utilities 
and Nebraska Public Power District state that while the proposition in 
Cost Allocation Principle 2 might seem self supporting, they understand 
that there are those who would encourage the Commission to mandate 
regional or even interconnectionwide cost sharing, but the Commission's 
decision to decline to do so is sensible.
---------------------------------------------------------------------------

    \484\ E.g., Ad Hoc Coalition of Southeastern Utilities; Nebraska 
Public Power District; Connecticut & Rhode Island Commissions; New 
England States Committee on Electricity; New York ISO; and New York 
PSC.
---------------------------------------------------------------------------

    631. Some commenters who express general support also express some 
concerns. For example, MISO Transmission Owners urge the Commission to 
ensure that this principle does not contribute to free rider problems.
    632. Some commenters are concerned that the principle could be 
interpreted too narrowly or too broadly. For instance, NextEra asks 
that the Commission construe the ``no benefit'' standard narrowly by 
providing that there is a benefit if a customer receives any benefit 
from the transmission facility, including an economic, reliability, or 
public policy benefit, particularly at or above certain voltage levels, 
over a reasonable period of time.
    633. Some commenters do not support the principle and raise 
concerns that the ``no benefits'' language in the principle will 
rarely, if ever, be applicable to any transmission customer.\485\ East 
Texas Cooperatives argue that by protecting only those that receive no 
discernible benefit, this principle conflicts with court precedent 
stating that the Commission cannot approve a pricing scheme that 
requires utilities to pay for facilities from which its members derive 
only trivial benefits. East Texas Cooperatives states that Principle 2 
does not go far enough, and the Commission should clarify that only 
those customers who are reasonably expected to receive non-trivial 
benefits can be allocated costs. Other

[[Page 49939]]

commenters, such as E.ON and Public Power Council, are worried that 
there will be stranded costs if a planning process exaggerates the 
benefits resulting from a particular project. Public Power Council 
believes the Commission should permit cost allocations that mitigate 
the risk of stranded costs and give due consideration to the impact on 
ratepayers prior to allocating costs.
---------------------------------------------------------------------------

    \485\ E.g., Transmission Dependent Utility Systems and East 
Texas Cooperatives.
---------------------------------------------------------------------------

    634. On the other hand, Xcel is concerned that the principle, taken 
at face value, gives parties the ability to ``opt out'' of cost 
allocation arising from specific projects even as it offers parties the 
opportunity to participate fully in the planning process. Xcel 
maintains that the Order No. 890 transmission planning process and the 
linkage between transmission planning and cost allocation render moot 
any participant's argument that it receives no benefit. Xcel argues 
that the Order No. 890 planning principles are designed to result in 
the best projects to meet the needs of the planning region, and 
therefore it is unlikely that participants in the planning process 
would produce a plan with a project or set of projects that do not 
provide benefits to stakeholders.
    635. Alliant Energy asks whether the Commission intended that 
membership in an ISO or RTO eliminates the prohibition of cost 
allocation for transmission projects to those entities that do not 
benefit. Alliant Energy does not believe this was the Commission's 
intent, but is seeks clarification to confirm its view.
    636. Alliant Energy also seeks clarification of the term 
``transmission facilities'' within the context of this principle. It 
asks whether the Commission intended that the principle be applied on a 
project-by-project basis, within the context of the entire regional 
transmission plan, or something in between. Alliant Energy believes 
that such evaluations should be done on a holistic basis, noting that 
some individual projects will benefit certain entities more than others 
but that the evaluation of benefits and costs within the context of a 
cost allocation determination could reasonably include the cumulative 
impact of a collection of projects.
b. Commission Determination
    637. The Commission adopts 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.\486\
---------------------------------------------------------------------------

    \486\ We added the words ``any of'' to the Regional Cost 
Allocation Principle 2 stated in the Proposed Rule to be consistent 
with interregional cost allocation Principle 2. We also added 
``transmission'' before ``facilities'' to clarify the term in this 
Regional Cost Allocation Principle 2 and throughout our discussion 
of the Cost Allocation Principles.

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

The principle expresses a central tenet of cost causation and is thus 
essential to proper cost allocation.
    638. In response to MISO Transmission Owners that Principle 2 might 
contribute to free rider problems, we agree that it, like all the other 
principles adopted in this Final Rule, requires careful consideration 
and application to ensure that they are implemented appropriately in 
practice. In response to NextEra, we decline to establish a threshold 
voltage level to define which benefits would be ineligible for cost 
allocation in this Final Rule.
    639. East Texas Cooperatives is concerned that the Commission is 
protecting only those that receive no benefits but not those who derive 
only trivial benefits. It cites the Seventh Circuit's statement in 
Illinois Commerce Commission that emphasized that the Commission is not 
authorized to approve cost allocation methods that require entities 
that receive no benefits or benefits that are trivial in relation to 
the costs to be borne. We note that the court used the term ``trivial'' 
in a relative sense, i.e., benefits that are trivial in relation to the 
costs assigned. This is implied in the concept of cost causation, and 
we therefore see no reason to amend the Principle 2 to include 
reference to it. Principle 1 requires that costs be allocated in a way 
that is roughly commensurate with the benefits received. This precludes 
an allocation where the benefits received are trivial in relation to 
the costs to be borne. Any beneficiaries that believe that the 
application of the cost allocation method or methods would assign to 
them costs for benefits, which are trivial, in relation to those costs 
is free to make a FPA section 205 or 206 filing.
    640. We also require that every cost allocation method or methods 
provide for allocation of the entire prudently incurred cost of a 
transmission project to prevent stranded costs. We disagree with Xcel 
that the Principle 2 gives parties the ability to opt out of a 
Commission-approved cost allocation for a specific transmission project 
if they merely assert that they receive no benefits from it. Whether an 
entity is identified as a beneficiary that must be allocated costs of a 
new transmission facility is not determined by the entity itself but 
rather through the applicable, Commission-approved transmission 
planning processes and cost allocation methods. Permitting each entity 
to opt out would not minimize the regional free rider problem that we 
seek to minimize in this Final Rule.
    641. With respect to Alliant Energy's request for clarification 
regarding RTO or ISO membership, we clarify that all the cost 
allocation principles, including Cost Allocation Principle 2 apply the 
allocation of costs to all new transmission facilities selected in the 
regional transmission plan for purposes of cost allocation, including 
RTO and ISO regions. In response to Alliant Energy's request to clarify 
whether the Commission intended that the principle be applied on a 
project-by-project basis, within the context of the entire regional 
transmission plan, we reiterate that the public utility transmission 
providers in a transmission planning region may propose a cost 
allocation method or methods that considers the benefits and costs of a 
group of new transmission facilities, although they are not required to 
do so. To the extent they propose a cost allocation method or methods 
that considers the benefits and costs of a group of new transmission 
facilities, and adequately support their proposal, Cost Allocation 
Principle 2 would not require a showing that every individual 
transmission facility in the group of transmission facilities provides 
benefits to every beneficiary allocated a share of costs of that group 
of transmission facilities. However, it is required that the aggregate 
cost of these transmission facilities be allocated roughly commensurate 
with aggregate benefits.
4. Cost Allocation Principle 3--Benefit to Cost Threshold Ratio \487\
---------------------------------------------------------------------------

    \487\ For the full text of this principle, see P 0 for regional 
cost allocation and P 0 for interregional cost allocation.
---------------------------------------------------------------------------

a. Comments
    642. Many commenters support the Commission's proposed Cost 
Allocation Principle 3, finding it to be a reasonable approach that 
would result in the construction of new transmission

[[Page 49940]]

projects.\488\ For example, ITC Companies states that the Commission's 
recommended cost threshold ratio is a necessary specification to 
prevent measures such as the sliding cost benefit ratio employed by 
MISO, which can require up to a 3 to 1 benefit to cost ratio for large 
regional long term transmission projects and which has served to 
frustrate the construction of market efficiency projects. American 
Transmission believes that the Commission's proposal seems like a 
reasonable threshold that would likely result in projects actually 
being constructed.
---------------------------------------------------------------------------

    \488\ E.g., ITC Companies; American Transmission; Omaha Public 
Power District; PSEG Companies; and Six Cities.
---------------------------------------------------------------------------

    643. Nonetheless, some commenters raise specific concerns. While 
generally supportive of the proposal, MISO Transmission Owners suggest 
that transmission providers and stakeholders in each planning region be 
permitted to develop a benefit to cost ratio that is appropriate for 
that region, provided that ratios are not set so high as to preclude 
any projects from being built. Similarly, MISO Transmission Owners 
argue that transmission providers and stakeholders should be permitted 
to develop appropriate criteria for defining benefits and costs. They 
also state that the Final Rule should indicate that any benefit to cost 
ratio for interregional transmission facilities should not supersede 
the ratio for a region's regional cost allocation. Transmission 
Dependent Utility Systems support this principle as a general concept, 
but they argue that it should be modified to ensure that the 
implementation of any cost benefit analysis is transparent to 
customers.
    644. Several commenters oppose the use of a fixed benefit-cost 
threshold ratio.\489\ A number of them stress the difficulties in 
quantifying benefits.\490\ Some commenters argue that the Commission 
should focus on regional circumstances.\491\ Northern Tier Transmission 
Group suggests that the Commission's focus should be on defining the 
types of benefits to be measured and how to measure them, rather than 
establishing a set threshold. Massachusetts Departments are concerned 
that a failure to reflect the full menu of benefits that could be 
realized by a proposed project could distort the balance between costs 
and benefits, and could preclude some beneficial projects at the 
planning stage that would have otherwise been approved. NextEra 
requests that benefits for this assessment should cover only economic 
benefits identified with the project, and not reliability or public 
policy benefits, as those benefits cannot be quantified in a similar 
manner.
---------------------------------------------------------------------------

    \489\ E.g., Northeast Utilities; Connecticut & Rhode Island 
Commissions; and Michigan Citizens Against Rate Excess.
    \490\ E.g., Xcel and Northern Tier Transmission Group.
    \491\ E.g., Michigan Citizens Against Rate Excess; Xcel; and 
Massachusetts Departments.
---------------------------------------------------------------------------

    645. Some commenters would like the Commission to establish either 
a higher or a lower benefit-cost ratio threshold. New York PSC believes 
that the proposed threshold is extremely low and does not adequately 
account for uncertainty in cost estimates and potential cost overruns. 
Connecticut & Rhode Island Commissions and Massachusetts Departments 
agree. On the other hand, AWEA, Wisconsin Electric, and NextEra urge 
the Commission to lower the proposed threshold. AWEA argues that if the 
Commission adopts the proposed threshold, it should be applied as a 
ceiling to ensure fair treatment for projects that have broad benefits 
over time. MEAG Power responds to AWEA's argument for a lower 
threshold, arguing that AWEA's proposal would unfairly shift to 
customers all risks associated with project development.
b. Commission Determination
    646. The Commission adopts 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,\492\ 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.
---------------------------------------------------------------------------

    \492\ To ensure consistency in the use of terms in this Final 
Rule, Cost Allocation Principle 3 as stated in the Proposed Rule has 
been changed to refer to facilities ``selected'' in a regional 
transmission plan, ability of a ``public utility transmission 
provider in a transmission planning region'' to use a benefit to 
cost threshold, and potential Commission approval of 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.\493\ 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.
---------------------------------------------------------------------------

    \493\ The phrase ``net benefits to qualify for interregional 
cost allocation'' differs from the language in regional cost 
allocation Principle 3 because there is no plan at the interregional 
level for which projects would be selected. The word ``large'' was 
changed to ``high'' to be consistent with the language in regional 
cost allocation Principle 3.

    647. Cost Allocation Principle 3 does not require the use of a 
benefit to cost ratio threshold. However, if a transmission planning 
region chooses to have such a threshold, the principle limits the 
threshold to one that is not so high as to block inclusion of many 
worthwhile transmission projects in the regional transmission plan. 
Further, it allows 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.
    648. Allowing for a transparent benefit to cost ratio may help 
certain transmission planning regions to determine which transmission 
facilities have sufficient net benefits to be selected in the regional 
transmission plan for purposes of cost allocation. For example, public 
utility transmission providers in a transmission planning region may 
want to use such a ratio to account for uncertainty in the calculation 
of benefits and costs. However, by requiring that a benefit to cost 
ratio, if adopted, not exceed 1.25 to 1 unless the public utility 
transmission providers in a transmission planning region justify, and 
the Commission approves, a greater ratio, will ensure that the ratio is 
not so high that transmission facilities with significant positive net 
benefits that would otherwise be selected in the regional transmission 
plan for purposes of cost allocation are not excluded from the regional 
transmission plan for purposes of cost allocation despite a positive 
ratio. The Commission therefore rejects requests to adopt a higher or 
lower threshold ratio, as advocated by some commenters.
    649. In response to specific comments on this principle, the 
Commission agrees that a benefit to cost ratio should not be set so 
high as to preclude certain beneficial transmission projects from

[[Page 49941]]

being constructed. As such, the Commission finds (and several 
commenters agree) that a benefit to cost ratio of 1.25 to 1 to be a 
reasonable ratio that will not act as a barrier to the development and 
construction of valuable new transmission projects. Furthermore, 
regarding comments requesting that the Commission decline to establish 
a benefit to cost threshold given the difficulty in quantifying 
benefits, we reiterate that the benefit to cost ratio threshold 
identified in this Final Rule applies only if the public utility 
transmission providers of a transmission planning region choose to use 
a benefit to cost ratio to determine which transmission facilities are 
selected in the regional transmission plan for purposes of cost 
allocation. They may decide to have no benefit to cost ratio threshold 
greater than one at all.
    650. Furthermore, in response to MISO Transmission Owners, if the 
issue of whether any benefit to cost ratio threshold for an 
interregional transmission facility may supersede the ratio for a 
transmission planning region's regional transmission cost allocation 
should be presented to us on compliance, we will address it then based 
on the specific facts in that filing.
5. Cost Allocation Principle 4--Allocation to be Solely Within 
Transmission Planning Region(s) Unless Those Outside Voluntarily Assume 
Costs \494\
---------------------------------------------------------------------------

    \494\ For the full text of this principle, see P 0 for regional 
cost allocation and P 0 for interregional cost allocation.
---------------------------------------------------------------------------

a. Comments
    651. Nearly all entities that commented on proposed Cost Allocation 
Principle 4 support it.\495\ For example, NEPOOL states that it 
particularly supports Principle 4, citing New England's successful 
history of voluntarily planning, developing and allocating the costs of 
interregional projects with its neighbors. New York ISO agrees, stating 
that it would be appropriate to allow more expansive voluntary cost 
allocation arrangements, but would be premature and unrealistic to 
require all regions to adopt specific cost allocation methodologies on 
an ex ante basis that would be applicable to future situations as yet 
unknown.
---------------------------------------------------------------------------

    \495\ E.g., ISO New England; Nebraska Public Power District; 
NEPOOL; New York ISO; New York PSC; Northern California Power 
Agency; and New York Transmission Owners.
---------------------------------------------------------------------------

    652. However, some commenters raise specific concerns. East Texas 
Cooperatives argue that the restriction on the involuntary allocation 
of costs on an interregional basis should not be interpreted to prevent 
a transmission provider from proposing methods to capture the costs 
associated with the benefits enjoyed by exported energy. MISO 
Transmission Owners agree with this argument. The New England States 
Committee on Electricity states that interregional Principle 4 aligns 
with its view that any allocation method must not transfer costs to New 
England ratepayers to support development of facilities outside New 
England unless New England concludes that development of such 
facilities are the most cost-effective. Northeast Utilities states that 
it supports the principle in so far as it limits the allocation of 
costs for interregional projects only to facilities located within 
neighboring regions.
    653. Other commenters argue that the Commission should not limit 
the application of interregional cost allocation requirements to 
interregional projects, suggesting that transmission facilities located 
solely within one region may have benefits in other regions.\496\ 
NextEra recommends modifying Principle 4 so that if transmission 
facilities within one region clearly benefit another region, the 
Commission would allow cost recovery by the transmission providers in 
the region providing the benefits to the other. NextEra maintains that 
without such a mechanism, the benefitting region would receive a 
windfall. According to PJM, basing the cost allocation on physical 
location rather than analyzing power flows, reduced congestion, or 
improved reliability, is untenable, would invite gaming of the routing 
and siting process to drive particular cost allocation results, would 
make negotiations on cost allocation among neighbors more difficult, is 
inconsistent with a beneficiary pays approach, and is contrary to the 
existing PJM-MISO interregional cost allocation method. As an 
alternative, PJM suggests providing for the cost allocation of 
transmission to all system users that benefit from the increased 
transfer capability that the new facility provides, thereby moving the 
decision from controversies surrounding particular generation sources 
to the future characteristics of the transmission system, which is a 
subject that is more clearly within the Commission's authority and 
expertise.
---------------------------------------------------------------------------

    \496\ See, e.g., NextEra; MISO; and MISO Transmission Owners.
---------------------------------------------------------------------------

    654. Similarly, MISO seeks clarification that two or more regions 
may mutually designate transmission facilities located entirely within 
a single region as an interregional transmission facility and allocate 
costs accordingly, which is the approach taken in the current cross-
border cost sharing arrangement between MISO and PJM. MISO, along with 
MISO Transmission Owners, argues that projects located entirely in one 
region may provide benefits to entities in the neighboring region.
    655. Large Public Power Council states that its members cannot at 
this time commit to entering into interregional agreements regarding 
cost allocation. It notes that its members are creatures of state and 
municipal governments, and their authority to enter into binding 
arrangements is restricted.
    656. Finally, the Coalition for Fair Transmission Policy sees an 
ambiguity in the Proposed Rule. It states that the Proposed Rule allows 
for costs to be allocated to a beneficiary even when the beneficiary 
has not entered into a voluntary arrangement to pay those costs, but 
proposed Cost Allocation Principle 4 states that costs cannot be 
allocated to an entity or region outside of the geographic boundaries 
of the planning region where the project is being constructed, absent a 
voluntary agreement.
b. Commission Determination
    657. The Commission adopts the following Cost Allocation Principle 
4 for both regional and interregional cost allocation:

    Regional Cost Allocation Principle 4: The allocation method for 
the cost of a transmission facility selected in a regional 
transmission plan \497\ 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.\498\
---------------------------------------------------------------------------

    \497\ The phrase ``an intraregional facility'' was replaced with 
``a transmission facility selected in a regional transmission plan'' 
to be consisted with P 0-0 n this Final Rule.
    \498\ At the end of the sentence, ``entities'' has been changed 
to ``beneficiaries'' to be precise. Slight wording changes have been 
made to the last sentence in this regional cost allocation Principle 
4 and interregional cost allocation Principle 4 to clarify the point 
being made.

---------------------------------------------------------------------------
and

    Interregional Cost Allocation Principle 4: Costs allocated for 
an interregional transmission facility must be assigned only to 
transmission planning regions in which the

[[Page 49942]]

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.\499\ 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.\500\
---------------------------------------------------------------------------

    \499\ The first two sentences of interregional cost allocation 
Principle 4 differ from regional cost allocation Principle 4 because 
at the interregional level, there may be a scenario where a 
transmission facility is located in one transmission planning region 
but provides benefits to another transmission planning region. For 
example, if regions A and B plan an interregional transmission 
facility that they believe benefits region C, regions A and B cannot 
allocate costs of that facility to region C involuntarily.
    \500\ ``Transmission facility'' was changed to ``upgrade'' in 
each instance in this sentence to make it consistent with the last 
sentence in regional cost allocation Principle 4. The end of the 
last sentence is revised to be consistent with Regional Cost 
Allocation Principle 4.

    658. Regarding the allocation of the cost of a transmission 
facility that is located entirely within one transmission planning 
region and that is intended to export electric energy from that 
transmission planning region to another transmission planning region, 
the public utility transmission providers in the exporting transmission 
planning region may not have a regional cost allocation method or 
methods pursuant to this Final Rule that assigns some or all of the 
cost of that transmission facility to beneficiaries in another 
transmission planning region without reaching an agreement with those 
beneficiaries. The public utility transmission providers in such 
transmission planning regions may, however, negotiate an agreement to 
share the transmission facility's costs with the beneficiaries in 
another transmission planning region, as they always have been free to 
do. Doing so is not inconsistent with Regional Cost Allocation 
Principle 4.
    659. Regarding the allocation of the cost of an interregional 
transmission facility that is located in two or more neighboring 
transmission planning regions and that is intended to export electric 
energy from one such transmission planning region to the other 
transmission planning region, this Final Rule requires that the public 
utility transmission providers in each pair of transmission planning 
regions have an interregional cost allocation method or methods for 
sharing the cost of such transmission facilities. However, 
Interregional Cost Allocation Principle 4 does not permit the cost 
allocation method or methods for those two transmission planning 
regions to assign the cost of the transmission facility to 
beneficiaries in a third transmission planning region except where the 
beneficiaries in the third transmission planning region voluntarily 
reach an agreement with the two transmission planning regions in which 
the transmission line is located. They also may satisfy the 
requirements of this Final Rule by having an interregional cost 
allocation method or methods for more than two transmission planning 
regions, although this Final Rule does not require them to do so.
    660. We decline to adopt NextEra's recommendation that we modify 
Principle 4 to allow cost allocation by the public utility transmission 
providers in one transmission planning region to beneficiaries in 
another transmission planning region.\501\ We acknowledge that this 
Final Rule's 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 finds this approach to be appropriate. For 
the reasons discussed herein, we are establishing a closer link between 
regional transmission planning and cost allocation, both of which 
involve the identification of beneficiaries. In light of that closer 
link, we find 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. Indeed, if the 
Commission expected such participation, the resulting regional 
transmission planning processes would amount to interconnectionwide 
transmission planning with corresponding cost allocation, albeit 
conducted in a highly inefficient manner. The Commission is not 
requiring either interconnectionwide planning or interconnectionwide 
cost allocation.
---------------------------------------------------------------------------

    \501\ See discussion supra section IV.D.
---------------------------------------------------------------------------

    661. MISO's and PJM's comments raise a similar issue that our 
proposed reforms inappropriately limit interregional cost allocation to 
those beneficiaries that are physically located in the transmission 
planning region in which the transmission facility is located. We find 
that this approach would raise the same concerns discussed immediately 
above.
    662. We recognize that MISO and PJM have an existing cross-border 
cost allocation method that permits them, in certain cases, to allocate 
to one RTO the cost of a transmission facility that is located entirely 
within the other RTO, even if the facility does not cross the border 
between their two regions. Because MISO and PJM developed their cross-
border allocation method in response to Commission directives related 
to MISO and PJM's intertwined configuration, we find that MISO and PJM 
are not required by this Final Rule to revise their existing cross-
border allocation method in response to Cost Allocation Principle 4. If 
MISO and PJM believe their existing cross-border cost allocation method 
fulfills other principles discussed herein, they may explain that in 
the filings they make in compliance with this Final Rule.
    663. In response to Large Public Power Council, as we discuss 
below,\502\ a non-public utility transmission provider seeking to 
maintain a safe harbor tariff must ensure that the provisions of that 
tariff substantially conform, or are superior to, the pro forma OATT as 
it has been revised by this Final Rule. However, it remains up to each 
non-public utility transmission provider whether it wants to maintain 
its safe harbor status by meeting the transmission planning and cost 
allocation requirements of this Final Rule.
---------------------------------------------------------------------------

    \502\ See discussion infra section V.B.
---------------------------------------------------------------------------

    664. We disagree with Coalition for Fair Transmission Policy's 
argument that there is an ambiguity in our reforms that allows for 
costs to be allocated to a beneficiary when the beneficiary has not 
entered into a voluntary arrangement to pay those costs, while also 
providing in Cost Allocation Principle 4 that the costs of transmission 
facilities in a regional transmission plan cannot be allocated to an 
entity in another transmission planning region, absent a voluntary 
agreement.
6. Cost Allocation Principle 5--Transparent Method for Determining 
Benefits and Identifying Beneficiaries \503\
---------------------------------------------------------------------------

    \503\ For the full text of this principle, see P 0 for regional 
cost allocation and P 0 for interregional cost allocation.
---------------------------------------------------------------------------

a. Comments
    665. Nearly all commenters that address this proposed principle 
supported it.\504\ PSEG Companies agree

[[Page 49943]]

that there is a need for transparent cost allocation and that customers 
cannot be expected to support the construction of new transmission 
unless they understand who will pay the associated costs. Further, PSEG 
Companies state that it should be clear which customers are benefiting 
from and paying for system upgrades before they are built, as this will 
minimize after-the-fact debates and litigation.
---------------------------------------------------------------------------

    \504\ E.g., SPP; Transmission Access Policy Study Group; and 
Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    666. Some commenters that support the principle caution that it 
will be difficult to determine costs and benefits with mathematical 
precision.\505\ In light of such difficulties, Connecticut & Rhode 
Island Commissions suggest that transmission cost allocation methods be 
pragmatic. DC Energy raises concerns about the use of biased 
assessments, and it suggests that one method for improving the 
reliability of cost-benefit analyses is to require that only direct 
costs and benefits be considered in economic studies since they offer 
greater certainty. PSEG Companies agree with the proposed principle and 
suggest that for non-reliability projects, there should be a more 
definitive link between identified beneficiaries and the costs to be 
paid.
---------------------------------------------------------------------------

    \505\ E.g., NextEra and Sunflower and Mid-Kansas.
---------------------------------------------------------------------------

    667. Several commenters raise specific issues with respect to the 
proposed principle. Transmission Dependent Utility Systems urge the 
Commission to recognize that transparency alone is insufficient without 
load serving entity involvement in the planning and development of the 
cost allocation method. Finally, MISO Transmission Owners argue that 
current RTO processes provide significant transparency.
b. Commission Determination
    668. The Commission adopts the following Cost Allocation Principle 
5 for both regional and interregional cost allocation:

    Regional Cost Allocation Principle 5: The cost allocation method 
and data requirements for determining benefits and identifying 
beneficiaries for a transmission facility must be transparent with 
adequate documentation to allow a stakeholder to determine how they 
were applied to a proposed transmission facility.

and

    Interregional Cost Allocation Principle 5: The cost allocation 
method and data requirements for determining benefits and 
identifying beneficiaries for an interregional transmission facility 
must be transparent with adequate documentation to allow a 
stakeholder to determine how they were applied to a proposed 
interregional transmission facility.\506\
---------------------------------------------------------------------------

    \506\ ``Interregional'' has been added before ``transmission 
facility'' at the end of the sentence to be precise.

    669. Requiring cost allocation methods and their corresponding data 
requirements for determining benefits and beneficiaries to be open and 
transparent ensures that such methods are just and reasonable and not 
unduly discriminatory or preferential. Furthermore, greater stakeholder 
access to cost allocation information will help aid in the development 
and construction of new transmission, as stakeholders will be able to 
see clearly who is benefiting from, and subsequently who has to pay 
for, the transmission investment. In addition, the Commission agrees 
that such access to information may avoid contentious litigation or 
prolonged debate among stakeholders.
    670. As the Commission stated in the Proposed Rule, we recognize 
that identifying which types of benefits are relevant for cost 
allocation purposes, which beneficiaries are receiving those benefits, 
and the relative benefits that accrue to various beneficiaries can be 
difficult and controversial. However, the Commission finds that a 
transparent transmission planning process is the appropriate forum to 
address these issues, and by addressing these issues, there will be a 
greater likelihood that regions can build the new transmission 
facilities selected in the regional transmission plan for purposes of 
cost allocation.
    671. We acknowledge the concerns that the method or methods for 
determining benefits and beneficiaries must balance being pragmatic and 
implementable with being accurate and unbiased. Cost Allocation 
Principle 5 requires that the method or methods be known and 
transparent. As stakeholders participate in the development of such 
methods, their input should ensure that the method or methods 
ultimately agreed upon is balanced and does not favor any particular 
entity. In developing this method or methods, public utility 
transmission providers and their stakeholders are also free to consider 
suggestions, such as those made by DC Energy, that only direct costs 
and benefits should be considered in economic studies. We will not, 
however, opine on such suggestions at this time. Rather, the Commission 
will review such matters once the cost allocation method or methods are 
filed on compliance.
    672. In response to MISO Transmission Owners, the Commission 
declines at this time to rule on whether any current RTO and ISO 
processes provide enough transparency to satisfy Cost Allocation 
Principle 5. Such determinations will be made upon the submittal of a 
compliance filing by any RTO or ISO.
7. Cost Allocation Principle 6--Different Methods for Different Types 
of Facilities \507\
---------------------------------------------------------------------------

    \507\ For the full text of this principle, see P 0 for regional 
cost allocation and P 0 for interregional cost allocation.
---------------------------------------------------------------------------

a. Comments
    673. Many commenters generally support proposed Cost Allocation 
Principle 6, arguing that transmission projects are built for different 
purposes, such as for reliability or economic reasons, and different 
methods may therefore be appropriate.\508\ Four G&T Cooperatives state 
that the planning regions should be given latitude to determine within 
reason the range of benefits that can be considered for cost allocation 
purposes, as well as the prioritization and relative value of such 
benefits. Pennsylvania PUC contends that cost allocation methods should 
maintain stable transmission rates that will be preferable both to the 
customers who pay the rates and the system planners who have to 
forecast future expenditures for the system. It argues that a cost 
allocation method should be flexible enough to accommodate different 
types of renewable energy from a diversity of sources, public policy 
changes, and potential shifts from older fossil fuel generation and 
development of other energy sources such as nuclear generation. 
Pennsylvania PUC also suggests that a cost allocation method be able to 
accommodate different types of facilities such as those serving 
renewable and non-renewable generators, both economic and reliability 
projects, as well as specialized projects such as generator 
interconnection facilities. MISO Transmission Owners agree and state 
that the applicable method should be determined through the stakeholder 
planning process. Dayton Power & Light states that one method may be 
appropriate, such as the beneficiary-pays approach, but the method by 
which beneficiaries are identified may depend on the type of project 
involved. New Jersey Board also supports flexibility and states that 
further analysis must be completed to

[[Page 49944]]

determine how best to allocate costs for transmission driven primarily 
by public policy requirements because the beneficiaries may differ 
markedly from the beneficiaries of transmission facilities built for 
reliability purposes.
---------------------------------------------------------------------------

    \508\ E.g., Indianapolis Power & Light; NEPOOL; Public Power 
Council; Northeast Utilities; New Jersey Board; E.ON; American 
Transmission; Dayton Power and Light; Delaware PSC; Dominion; New 
England States Committee on Electricity; and PSEG Companies.
---------------------------------------------------------------------------

    674. PSEG Companies request that reliability and non-reliability 
projects be treated differently for cost allocation purposes, and they 
advocate adopting a voting mechanism for economic projects that would 
require that proposed economic upgrades be voted on by the entities 
that have been deemed to benefit from them and who in turn would be 
responsible for paying for them. National Grid, however, is concerned 
about the use of supermajority voting requirements for economic 
transmission projects. In response, Con Edison points favorably to New 
York ISO's supermajority voting requirements for economic transmission 
projects in its transmission planning process.
    675. In its reply comments, PJM proposes a possible way to 
reconcile what it views as competing directives in the Proposed Rule 
regarding transmission planning and cost allocation related to 
economic, reliability, and public policy projects. Economic and 
reliability projects would be included in one category, under which a 
beneficiary pays approach would match the planning purposes used (e.g., 
avoiding a violation of a reliability standard). Public policy projects 
would comprise the second category, under which the Commission would 
align the planning and cost allocation for such projects with regional 
action taken by states sharing similar public policy objectives. PJM 
suggests that regions could form interstate compacts to identify shared 
public policy goals and resource requirements and accept the allocation 
of costs associated with those projects. PJM further suggests a ``safe 
harbor'' to prevent states from having to absorb costs for public 
policy projects undertaken in other states.
    676. Large Public Power Council believes that the interregional 
allocation of costs is a topic on which consensus is feasible only in 
the context of specific projects proposed by project developers to 
satisfy identified market needs.
    677. Some commenters point to existing approaches as being adequate 
to meet this principle. Northeast Utilities states that a comprehensive 
approach using the current New England method should be appropriate. 
Northeast Utilities contends that the existing cost allocation rules in 
the ISO-New England OATT would meet the proposed requirements for 
regional cost allocation with the addition of a clearer cost allocation 
method for economic projects and a separately stated method for 
projects intended to meet public policy requirements.
    678. Some commenters are concerned as to whether the Commission 
should allow different cost allocation methods for different 
facilities.\509\ These commenters make several arguments: (1) New 
transmission facilities seldom serve one function and may provide 
general reliability and other benefits to the transmission system; (2) 
the benefits of a given project may vary over time; and (3) such 
designations have been the source of substantial delays and conflict as 
planning participants spend time and resources arguing over a project's 
designation.
---------------------------------------------------------------------------

    \509\ E.g., ITC Companies; Multiparty Commenters; NextEra; and 
Wind Coalition.
---------------------------------------------------------------------------

    679. Xcel states that while it does not oppose the concept of using 
different cost allocation mechanisms for projects with different 
drivers, it believes that an excessive amount of time is being spent 
splitting benefits into their component buckets. It argues that the 
appropriate focus of cost allocation methods instead should be 
determining the multiple benefits that any transmission projects 
provide to a planning region and its stakeholders. Xcel explains that 
one objective of the state transmission certification process is to 
ensure that, regardless of the initial driver, projects are ultimately 
scoped and right-sized to provide multiple benefits. Xcel thus argues 
that cost allocation methods should concentrate on identifying and 
measuring multiple benefits that transmission facilities provide, 
rather than developing a new cost allocation method for each initial 
project driver.
    680. Multiparty Commenters express concern that there could be a 
proliferation of cost allocation designs if the Commission allows 
different cost allocation methods for different types of facilities and 
for interregional and regional planning processes. They believe that 
this will lead to protracted disputes about the function of a 
transmission facility.
    681. Transmission Dependent Utility Systems believe that Cost 
Allocation Principle 6 could place too much discretion in the hands of 
the transmission providers, particularly in non-RTO/ISO regions, and 
they urge the Commission to require transmission providers to make 
these decisions in collaboration with customers. They state that 
including load serving entities in these discussions would go a long 
way towards alleviating their concern with having a separate cost 
allocation method for facilities driven by public policy requirements.
    682. Several commenters seek clarification of Principle 6. New York 
ISO seeks clarification that public utility transmission providers may 
adopt cost allocation methods for different types of transmission 
projects without creating a specific cost allocation mechanism 
applicable solely to public policy projects. New York ISO states that 
the Proposed Rule appears to contemplate this and contends that such a 
clarification would be appropriate, especially for regions such as New 
York that do not currently have a rule requiring that public policy 
projects be constructed. New York ISO states that such cost allocation 
methods can and should be determined on a project-specific basis 
depending on the policy driving the agreed-upon transmission project.
    683. Long Island Power Authority suggests that imposing a single 
regional cost allocation method for public policy driven projects may 
inhibit the development of transmission that facilitates the 
interconnection of renewable energy generation and would allocate costs 
of each public policy driven project to the same beneficiaries, leading 
to the assignment of duplicative costs to specific entities and to 
increases in rates that reduce, or possibly eliminate, an entity's 
ability to incur costs for its own renewable generation or energy 
efficiency goals. Long Island Power Authority therefore believes the 
Final Rule should not direct project costs to non-beneficiaries and not 
impose costs that prevent non-jurisdictional entities from satisfying 
their own lawful public policy goals.
    684. Alliant Energy seeks clarification that for purposes of 
Principle 6 the terms ``region'' and ``regional'' cover the entire RTO 
or ISO footprint in the case where there is a Commission-approved 
planning region within an RTO or ISO, such as American Transmission 
within MISO. Alliant Energy contends that Principle 6 invites the 
opportunity for discrimination and unintended consequences if the 
Commission determines that a region could constitute a single 
transmission provider within the RTO or ISO footprint. It states that 
cost allocation policies within an RTO or ISO footprint must be 
consistent.
b. Commission Determination
    685. The Commission adopts the following Cost Allocation Principle 
6 for both regional and interregional cost allocation:

    Regional Cost Allocation Principle 6: A transmission planning 
region may choose to

[[Page 49945]]

use a different cost allocation method for different types of 
transmission facilities in the regional transmission plan, such as 
transmission facilities needed for reliability, congestion relief, 
or to achieve Public Policy Requirements.\510\ Each cost allocation 
method must be set out clearly and explained in detail in the 
compliance filing for this rule.
---------------------------------------------------------------------------

    \510\ ``Public Policy Requirements'' replaces ``public policy 
requirements established by State or Federal laws or regulations 
that may drive transmission needs'' as defined in P 0 of this Final 
Rule.

---------------------------------------------------------------------------
and

    Interregional Cost Allocation Principle 6: The public utility 
transmission providers located in neighboring transmission planning 
regions may choose to use a different cost allocation method for 
different types of interregional transmission facilities, such as 
transmission facilities needed for reliability, congestion relief, 
or to achieve Public Policy Requirements.\511\ Each cost allocation 
method must be set out clearly and explained in detail in the 
compliance filing for this rule.\512\
---------------------------------------------------------------------------

    \511\ ``Public Policy Requirements'' replaces ``public policy 
requirements established by State or Federal laws or regulations 
that may drive transmission needs'' as defined in P 0 of this Final 
Rule.
    \512\ The word ``clearly'' has been added to this sentence to 
make it consistent with the last sentence in regional cost 
allocation Principle 6.

    686. We agree with the Pennsylvania PUC and others that 
transmission planning regions should be afforded the opportunity to 
develop a different cost allocation method for different transmission 
project types.\513\ The development of such cost allocation method, 
however, rests with the public utility transmission providers 
participating in regional transmission planning processes in 
consultation with stakeholders. Cost Allocation Principle 6 permits but 
does not require the public utilities in a transmission planning region 
to designate different types of transmission facilities, and it permits 
but does not require the public utilities in a transmission planning 
region that choose to designate different types of transmission 
facilities to have a different cost allocation method for each type. 
However, we clarify that if the public utilities choose to have a 
different cost allocation method for each type of transmission 
facility, there can be only one cost allocation method for each type.
---------------------------------------------------------------------------

    \513\ We note that a method, such as a highway-byway method for 
a reliability project, may itself further distinguish types of 
facilities, for example by voltage, and allocate costs differently 
for each type.
---------------------------------------------------------------------------

    687. It may be appropriate to have different cost allocation 
methods for transmission facilities that are planned for different 
purposes or planned pursuant to different regional transmission 
planning processes, provided that these methods are applied 
consistently. In particular, in response to some commenters, we clarify 
that we are not requiring a distinct regional or interregional cost 
allocation method applicable solely to transmission facilities for 
Public Policy Requirements and that are selected in a regional 
transmission plan for purposes of cost allocation, but we allow it.
    688. Moreover, as the Commission recognized in Order No. 890, 
states have a critical role with respect to transmission planning.\514\ 
That role may be particularly important with respect to planning for 
transmission needs driven by Public Policy Requirements, where multiple 
states may be impacted by the selection (or cost) of a given 
transmission project needed to meet transmission needs driven by a 
particular state's Public Policy Requirement. Therefore, we strongly 
encourage states to participate actively not only in transmission 
planning processes in general, but specifically in the identification 
of transmission needs driven by Public Policy Requirements. We also 
note that agreements among states with respect to cost allocation may 
be particularly important for transmission facilities designed to meet 
transmission needs driven by Public Policy Requirements. States could 
pursue such agreements in various forms, including a committee of state 
regulators or through a compact among states that receives appropriate 
approval from Congress.
---------------------------------------------------------------------------

    \514\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 574.
---------------------------------------------------------------------------

    689. We leave it to each transmission planning region or pair of 
transmission planning regions to propose on compliance whether, and 
how, to distinguish between types of transmission facilities. We also 
note that a public utility transmission provider together with other 
public utility transmission providers in a transmission planning 
region, and an RTO or ISO, which is itself a public utility 
transmission provider, may have a single cost allocation method for all 
proposed transmission facilities or different methods for different 
types of transmission facilities. For example, cost allocation methods 
may distinguish among transmission facilities that are driven by needs 
associated with maintaining reliability, addressing economic 
considerations, and achieving Public Policy Requirements, all of which 
would be required to be considered in the regional transmission 
planning process as explained in this Final Rule. The Commission 
recognizes that several transmission planning regions that have 
different cost allocation methods by type of transmission project 
currently have transmission planning procedures and cost allocation 
methods that refer only to the first two types of transmission 
projects. This Final Rule allows a public utility transmission provider 
through its participation in a transmission planning region to 
distinguish or not distinguish among these three types of transmission 
facilities, as long as each of the three types is considered in the 
regional transmission planning process and there is a means for 
allocating the costs of each type of transmission facility to 
beneficiaries. In response to PSEG Companies, we clarify that a 
regional cost allocation method for one type of regional transmission 
facility or for all regional transmission facilities may include voting 
requirements for identified beneficiaries to vote on proposed 
transmission facilities.
    690. However, a public utility transmission provider must have a 
regional cost allocation method for any transmission facility selected 
in a regional transmission plan for purposes of cost allocation. It may 
not designate a type of transmission facility that has no regional cost 
allocation method applied to it, which would effectively exclude that 
type of transmission facility from being selected in a regional 
transmission plan for purposes of cost allocation. In response to New 
York ISO and Long Island Power Authority, a transmission facility 
proposed to address a Public Policy Requirement must be eligible for 
selection in a regional transmission plan for purposes of cost 
allocation and must not be designated as a type of transmission 
facility for which the cost allocation method must be determined only 
on a project-specific basis. However, in contrast to what New York 
ISO's comment implies, the regional cost allocation method for such a 
transmission facility may take into account the transmission needs 
driven by a Public Policy Requirement, who is responsible for complying 
with that Public Policy Requirement, and who benefits from the 
transmission facility. If a regional transmission plan determines that 
a transmission facility serves several functions, as many commenters 
point out it may, the regional cost allocation method must take the 
benefits of these functions of the transmission facility into account 
in allocating costs roughly commensurate with benefits.
    691. As stated elsewhere, we decline to opine here on whether any 
existing processes satisfy Cost Allocation Principle 6 in the regional 
and

[[Page 49946]]

interregional context. For example, if a region believes that its 
regional transmission planning process meets Regional Cost Allocation 
Principle 6 for all facilities, including transmission facilities 
driven by a Public Policy Requirement, it may submit evidence in 
support of this position in a compliance filing pursuant to this Final 
Rule.
    692. Some commenters are concerned that designation of transmission 
facility type can result in substantial delay because transmission 
facilities may serve multiple functions and benefits and beneficiaries 
may vary over time. This concern should be addressed in each region's 
transmission planning process. However, we note that many regional 
transmission planning processes currently have mechanisms for 
distinguishing between types of transmission facilities, and there is 
no reason to believe that transmission facilities designation 
necessarily results in a substantial delay.
    693. In response to Alliant Energy's comment, the Commission 
addressed this concern in the regional transmission planning section 
above.\515\
---------------------------------------------------------------------------

    \515\ See discussion supra section III.A.
---------------------------------------------------------------------------

8. Whether To Establish Other Cost Allocation Principles
a. Commission Proposal
    694. The Proposed Rule sought comment on whether additional 
principles should apply to cost allocation for either regional or 
interregional transmission facilities, and it asked commenters to 
submit and explain the need for those principles.\516\
---------------------------------------------------------------------------

    \516\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 178.
---------------------------------------------------------------------------

b. Comments
    695. Six Cities ask the Commission to include a new principle or a 
corollary requirement that the transmission planning processes include 
provisions to encourage cost containment, a point echoed in other 
comments on cost allocation.\517\ The New England States Committee on 
Electricity also argues that the Commission should establish 
transmission cost control and review mechanisms to ensure that 
construction is performed as efficiently as possible and the costs 
incurred are reasonable.
---------------------------------------------------------------------------

    \517\ E.g., California Commissions; California Municipal 
Utilities; City of Santa Clara; Connecticut & Rhode Island 
Commissions; NEPOOL; New England States Committee on Electricity; 
New England Transmission Owners; Northeast Utilities; Northern 
California Power Agency; and Transmission Agency of Northern 
California. While San Diego Gas & Electric agrees that it is 
appropriate for commenters to seek safeguards with respect to cost 
overruns, it takes issue as a factual matter with California 
Municipal Utilities' inclusion of the Sunrise-Powerlink project as 
one that is a clear example that cost overruns are endemic.
---------------------------------------------------------------------------

    696. ELCON and Associated Industrial Groups urge the Commission to 
adopt two technical principles related to the costs of new transmission 
investments being allocated on a representatively-determined capacity 
(MW) basis, not on an volumetric (MWh) basis and periodic adjustment of 
cost allocation to reflect changes in power flows.\518\ However, ITC 
Companies do not support periodic adjustments of cost allocation and 
describe it as disruptive and potentially risky.
---------------------------------------------------------------------------

    \518\ See also East Texas Cooperatives and Maine Parties.
---------------------------------------------------------------------------

    697. Other commenters propose principles that look to safeguard 
particular participants in the transmission planning process. For 
example, City of Los Angeles Department of Water and Power states that 
there should be appropriate safeguards that allow non-public utilities 
to seek required approvals before they are allocated costs for new 
transmission projects, and that participation in the regional 
transmission planning process by non-public utilities remain voluntary. 
Similarly, Transmission Dependent Utility Systems state that if a 
particular customer is not allowed to participate fully in a regional 
planning process, there should be a presumption that the customer is 
not receiving benefits from the regional plan.
    698. San Diego Gas & Electric proposed policy changes for 
transmission projects that span multiple balancing authority areas and 
for which a voluntarily negotiated cost allocation arrangement proves 
feasible. Its proposed policy changes focused on payment by loads, 
allocation of costs to balancing authority areas that do or do not 
benefit, and encouragement for non-jurisdictional governmental agencies 
to adopt reciprocal cost allocation policies.
    699. Michigan Citizens Against Rate Excess proposed three 
additional principles that limit transmission costs driven by public 
policy requirements to the state or states of origin,\519\ that 
transmission cost recovery should not be a means to subsidize non-
transmission projects, and that no state or region should shoulder the 
cost alone when benefits accrue to others as well, namely for 
reliability projects only.
---------------------------------------------------------------------------

    \519\ See also Electricity Consumers Resource Council and the 
Associated Industrial Groups and Public Power Council.
---------------------------------------------------------------------------

    700. PUC of Ohio maintains that the Commission should consider 
principles when considering any long-term transmission rate design that 
provide the utility the opportunity to recover an authorized revenue 
amount, is equitable, provides for customer understanding and rate 
continuity, minimizes customer impact and undue cost shifts, and 
recognizes the use and benefits of the transmission system.
    701. Environmental Defense Fund, the Wilderness Society, and 
Western Resource Advocates recommended principles that they argue will 
assist in identifying the full range of benefits that must be accounted 
for when justifying a project.\520\ They state that project costs 
should be allocated consistent with the range/distribution of benefits 
that are likely to accrue in both the near- and long-term, that the 
benefits of projects must include carbon emissions reductions and the 
attainment of other state and federal policy imperatives, and that 
beneficiaries under any beneficiaries-pay cost allocation policy be 
defined to include consideration of the myriad of beneficial outcomes 
described above, as well as other benefits likely to accrue to 
transmission system users over the life of the grid investment.
---------------------------------------------------------------------------

    \520\ E.g., Environmental Defense Fund; Wilderness Society; and 
Western Resource Advocates. Sonoran Institute also proposes the 
second and third principles proposed by Environmental Defense Fund 
and Wilderness Society and Western Resource Advocates.
---------------------------------------------------------------------------

    702. American Antitrust Institute states that the Commission should 
consider how cost-benefit tests for cost allocation and recovery can be 
designed to promote competition and encourages the Commission to 
carefully scrutinize cost allocation approaches based on voting rules 
that give incumbent utility transmission providers the ability to vote 
against economic transmission projects that benefit ratepayers.
    703. Energy Consulting Group suggests that beneficiaries, including 
those receiving firm transmission service should to be obligated to pay 
the allocated costs of the improvements through a specified tariff rate 
and relieved of any obligations to pay current OATT rates for 
improvements.
c. Commission Determination
    704. We agree with Six Cities, New England States Committee on 
Electricity, and others that cost containment is important. However, we 
decline to establish a corresponding cost allocation principle as 
recommended, primarily because cost containment concerns the level of 
costs, not how costs should be allocated among beneficiaries. While we 
understand and agree that those receiving a cost allocation are 
appropriately concerned

[[Page 49947]]

that the level of the cost being allocated should be controlled 
accordingly, we do not believe that a new principle or corollary 
requirement in this Final Rule is the appropriate mechanism to promote 
cost containment.
    705. We have considered all the other additional principles 
proposed by commenters but decline to adopt them. We do not believe 
that any additional principles are necessary at this time. Moreover, we 
believe that many of the suggestions of commenters, if required by this 
Final Rule, would limit the flexibility we provide in this Final Rule 
for public utility transmission providers to propose the appropriate 
cost allocation method or methods for their transmission planning 
region or pair of transmission planning regions. If a commenter 
believes that one or more of its suggestions is consistent with the six 
principles we adopt herein, that commenter is free to work within a 
regional stakeholder process to see if its concerns could be addressed. 
We will permit each transmission planning region or pair of 
transmission planning regions to propose cost allocation methods that 
satisfy additional requirements that they deem necessary to meet the 
specific needs of that transmission planning region or transmission 
planning regions provided they are consistent with the cost allocation 
principles of this Final Rule. Any such requirements should be 
submitted as part of the cost allocation method or methods on 
compliance, along with an explanation of how they comply with the 
requirements of this Final Rule.

F. Application of the Cost Allocation Principles

    706. The Proposed Rule addressed several potential applications of 
the cost allocation principles, seeking general comment on the 
appropriateness of these six cost allocation principles and how they 
should be applied to the costs of new regional and interregional 
transmission facilities that are eligible for cost allocation.\521\
---------------------------------------------------------------------------

    \521\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 178.
---------------------------------------------------------------------------

1. Whether To Have Broad Regional Cost Allocation for Extra-High 
Voltage Facilities
a. Commission Proposal
    707. The Commission declined in the Proposed Rule to address in the 
abstract and in the absence of a record whether several candidate cost 
allocation methods, either in use today in a region or proposed by some 
commenters, would satisfy the proposed regional and interregional cost 
allocation principles.
b. Comments on Cost Allocation for Extra-High Voltage Facilities
    708. Several commenters recommend that the Commission establish a 
rebuttable presumption that the costs of extra-high voltage 
transmission facilities be allocated widely across a region.
    709. NextEra argues that extra-high voltage lines, typically 345 kV 
and above, provide regional benefits, and that the Commission should 
require that every cost allocation method include a rebuttable 
presumption that the costs of such lines will be allocated widely. 
WIRES agrees, pointing out that this is essentially the approach taken 
in PJM for projects above 500 kV. NextEra suggests that those seeking 
to rebut this presumption in the context of a particular extra-high 
voltage project should bear the burden of showing they receive no 
benefits from the project. To accomplish this, NextEra recommends that 
the Commission adopt a pro forma transmission cost allocation method, 
and that transmission providers and stakeholders could either follow 
the pro forma model or propose a method that is consistent with or 
superior to that model. Multiparty Commenters also support a rebuttable 
presumption for extra-high voltage lines.\522\ Similarly, AEP argues 
that extra-high voltage facilities provide regionwide benefits and the 
costs of such facilities should be allocated widely across a region. 
AEP also suggests that extra-high voltage AC facilities that 
interconnect electrical regions and that are identified as needed under 
the applicable interregional coordination agreement benefit both 
regions, and AEP states that the costs of such facilities should be 
allocated across those regions. Clean Line supports allocating the 
costs for extra-high voltage lines across the largest region possible.
---------------------------------------------------------------------------

    \522\ Multiparty Commenters append an analysis performed by CRA 
International that purports to show the widely dispersed benefits of 
extra-high voltage transmission facilities (CRA Study).
---------------------------------------------------------------------------

    710. Baltimore Gas & Electric submits that the Final Rule should 
apply highway/byway principles to projects that traverse RTOs and to 
projects within RTOs. It states that the cost allocation principles 
espoused in the Proposed Rule should be adopted, and that the 
Commission should at least allow for the Opinion No. 494 method to be 
continued in PJM,\523\ regardless of the methods that are deemed 
appropriate for other RTOs.\524\ However, Baltimore Gas & Electric 
states that other RTOs must maintain cost allocation mechanisms with 
respect to each other that provide for reciprocal treatment. It states 
that new, high voltage, RTO-approved facilities should be paid for 
uniformly by all rate zones because they provide significant benefits 
to all rate zones.
---------------------------------------------------------------------------

    \523\ PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ] 
61,063 (2007), Opinion No. 494-A, 112 FERC ] 61,082 (2008) (cost 
allocation methods for new transmission facilities that 
distinguished between facilities below and above 500 kV), remanded, 
Illinois Commerce Comm'n v. FERC, 576 F.3d 470 (7th Cir. 2009).
    \524\ Delaware PSC and American Forest & Paper also support 
PJM's cost allocation method for high voltage facilities. American 
Forest & Paper asserts PJM's method is preferable to the energy 
allocator method proposed in MISO.6
---------------------------------------------------------------------------

    711. Several reply commenters oppose proposals to establish a 
rebuttable presumption for extra-high voltage facilities.\525\ Large 
Public Power Council argues that such proposals cannot be squared with 
the cost allocation principle set forth in Illinois Commerce Commission 
that utilities cannot be required to pay for facilities from which its 
members derive no or only trivial benefits. Ad Hoc Coalition of 
Southeastern Utilities replies that there is no basis to presume that 
an extra-high voltage transmission overlay is beneficial to all 
customers, and that such a position is inconsistent with Illinois 
Commerce Commission. Ad Hoc Coalition of Southeastern Utilities 
emphasizes that the addition of extra-high voltage facilities can 
overload the underlying transmission system and change power flows, 
requiring upgrades to lower voltage lines and operational changes. Ad 
Hoc Coalition of Southeastern Utilities contends that broadly 
socializing the costs of extra-high voltage facilities could bias the 
integrated resource planning process total-cost analyses toward such 
facilities in that at least some of their costs will be spread 
throughout the region and not incurred by the utility causing the need 
for the facilities. Similarly, Southern Companies states that its 
integrated resource planning has not shown that extra-high voltage 
lines are a cost-effective, reliable solution to meeting identified 
transmission needs and that constructing such lines in the Southeast 
and then broadly socializing their costs over the entire load in the 
region would result in higher costs to consumers than implementing non-
extra-high voltage solutions. Southern Companies also argue that such 
an approach would skew the evaluations of which transmission and non-
transmission

[[Page 49948]]

alternatives are the least cost means to meet an identified need. MEAG 
Power provides illustrations of how such a proposal could result in 
unjust and unreasonable rates. Coalition for Fair Transmission Policy 
argues that the CRA Study filed by Multiparty Commenters is flawed 
because it neglects to mention that in some cases extra-high voltage 
facilities impose costs on some parts of a region as well, and that 
such impacts can be ascertained only by examining specific projects. 
MEAG Power similarly asserts that the CRA study is flawed for a number 
of reasons, including the fact that it examines only the existing grid, 
omits several regions from its analysis and fails to estimate any 
dollar benefits accruing to any party.
---------------------------------------------------------------------------

    \525\ E.g., Coalition for Fair Transmission Policy; Ad Hoc 
Coalition of Southeastern Utilities; Southern Companies; Large 
Public Power Council; East Texas Cooperatives; New England States 
Committee on Electricity; and APPA.
---------------------------------------------------------------------------

    712. In addition, in its reply comments, SoCal Edison disagrees 
with NextEra's proposal for a pro forma cost allocation agreement, 
arguing that there is not sufficient evidence to determine that such an 
approach is consistent with the principle that costs be allocated 
roughly commensurate with benefits.
c. Commission Determination
    713. We are not persuaded to adopt a rebuttable presumption that 
the costs of extra-high voltage facilities, such as 345 kV and above, 
should be allocated widely across a transmission planning region. Such 
a presumption would be akin to a default cost allocation method which, 
as discussed above,\526\ we do not adopt. For the same reason, we do 
not agree that a pro forma cost allocation method is appropriate.
---------------------------------------------------------------------------

    \526\ See discussion supra section IV.E.1.
---------------------------------------------------------------------------

    714. The Commission recognizes and intends that several approaches 
to cost allocation may satisfy the principles adopted in this Final 
Rule. If it were otherwise, the offer of regional flexibility would be 
an empty offer. Therefore, we do not impose a single cost allocation 
method for any transmission planning region. If public utility 
transmission providers and their stakeholders in a transmission 
planning region reach a consensus that the costs of extra-high voltage 
facilities, such as 345 kV and above, should be allocated widely and 
that this would result in a distribution of costs that is at least 
roughly commensurate with the benefits received, and support this 
conclusion with evidence, they may submit the method to the Commission 
on compliance.
2. Whether To Limit the Use of Participant Funding
a. Commission Proposal
    715. Following the presentation of these six cost allocation 
principles in the Proposed Rule, the Commission discussed their 
application to participant funding as a regional or interregional cost 
allocation method for satisfying these principles. The Commission 
explained that in transmission planning regions outside of the RTO and 
ISO footprints, many of the cost allocation methods that the Commission 
accepted in the Order No. 890 compliance proceedings rely exclusively 
on a ``participant funding'' approach to cost allocation, in which the 
costs of a new transmission facility are allocated only to entities 
that volunteer to bear those costs.\527\ The Commission proposed that 
participant funding is not a cost allocation method that would satisfy 
these principles. The Commission further noted that a cost allocation 
method that relies exclusively on a participant funding approach, 
without respect to other beneficiaries of a transmission facility, 
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. However, the 
Proposed Rule did not prohibit voluntary participant funding for those 
that choose to use it.
---------------------------------------------------------------------------

    \527\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 121-28.
---------------------------------------------------------------------------

b. Comments on Limiting Participant Funding
    716. Many commenters generally agree that a cost allocation method 
based exclusively on a participant funding approach neither achieves 
the goal of timely development of building transmission facilities nor 
results in just and reasonable rates.\528\ In support of this position, 
several commenters maintain that participant funding does not allocate 
the costs of new regional transmission projects to their multiple 
beneficiaries.\529\ East Texas Cooperatives request that the Commission 
define the scope of acceptable benefits that may be considered, provide 
that cost allocation methods ensure that customers receive benefits 
commensurate with their share of costs, and conclude that participant 
funding is a failed cost allocation method.
---------------------------------------------------------------------------

    \528\ E.g., AWEA; East Texas Cooperatives; Gaelectric; ITC 
Companies; Multiparty Commenters; NextEra; Transmission Access 
Policy Study Group; Transmission Dependent Utility Systems; and 
WIRES.
    \529\ E.g., AWEA; Gaelectric; Multiparty Commenters; and 
Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    717. Several commenters agree that the Commission should clarify 
what regional cost allocation approaches are not acceptable.\530\ AWEA 
states that to ensure that future cost allocation proposals do not 
serve as barriers to transmission expansion, and can support 
transmission additions that are ``right sized'' to meet the long-term 
needs of the system, the Commission should specify when participant 
funding, and other such cost allocation methods, should not be allowed, 
or what level of participant funding it might find acceptable. NextEra 
argues that the use of participant funding should be minimized, and 
that the Final Rule should specify that costs of transmission projects 
identified through the transmission planning process cannot be 
allocated to generators because any other outcome would simply continue 
the status quo of discouraging development of new resources.
---------------------------------------------------------------------------

    \530\ E.g., AWEA; ITC Companies; Multiparty Commenters; NextEra; 
and WIRES.
---------------------------------------------------------------------------

    718. In contrast, other commenters argue that the Commission should 
promote flexibility, and continue to allow for participant funding of 
projects with voluntary agreements on cost sharing.\531\ Some 
commenters appear to believe the Proposed Rule would prohibit the use 
of participant funding in all circumstances, not just for new 
transmission facilities in a regional transmission plan for purposes of 
regional cost allocation to regional beneficiaries. As a starting 
point, a few commenters state that the Commission has accepted and 
continues to accept rates using participant funding. For example, E.ON 
points out that the Commission approved negotiated rates for the 
Chinook and Zephyr merchant transmission projects, which it believes is 
evidence that participant funding may be of practical use and may have 
more widespread application as transmission customers are required to 
access electricity from renewable generation. Therefore, some 
commenters argue that the Commission first must present factual 
evidence that current cost allocation methods are unjust and 
unreasonable, or otherwise unduly discriminatory, which it has not 
done.

[[Page 49949]]

Ad Hoc Coalition of Southeastern Utilities and Arizona Corporation 
Commission argue that participant funding most closely follows ``but 
for'' cost causation principles, and Ad Hoc Coalition of Southeastern 
Utilities adds that it is most consistent with judicial precedent 
regarding what constitutes an appropriate cost allocation method. 
Similarly, many commenters contend that the participant funding 
approach has led to the building of transmission projects that meet the 
reliability and economic needs of customers, and state and local policy 
goals.\532\ Ad Hoc Coalition of Southeastern Utilities emphasizes that 
a requestor pays approach has been the norm for intersystem 
transmission projects in both the electric and gas industries. Arizona 
Corporation Commission, Salt River Project, City of Los Angeles 
Department of Water and Power, and Tucson Electric state that, in the 
West and Southwest, the participant-funded method of cost allocation 
has not delayed construction of transmission facilities and has been 
effective. Northern Tier Transmission Group believes that facilitating 
willing parties to make rational business decisions has a higher 
probability of causing the construction of new transmission than does a 
situation where costs could be forced upon unwilling parties, as is 
contemplated by the Proposed Rule.
---------------------------------------------------------------------------

    \531\ E.g., Ad Hoc Coalition of Southeastern Utilities; Arizona 
Corporation Commission; Arizona Public Service Company; City of Los 
Angeles Department of Water and Power; Santa Clara; E.ON; Large 
Public Power Council; Nebraska Public Power District; Northern Tier 
Transmission Group; Salt River Project; Transmission Agency of 
Northern California; Tucson Electric; Washington Utilities and 
Transportation Commission; WestConnect; and Westar.
    \532\ E.g., Ad Hoc Coalition of Southeastern Utilities; Arizona 
Corporation Commission; City of Los Angeles Department of Water and 
Power; and Tucson Electric.
---------------------------------------------------------------------------

    719. In its reply comments, Entergy states that it believes that 
participant funding is an appropriate pricing method and should not be 
excluded from consideration in the Final Rule. Entergy requests 
clarification that any adverse finding against participant funding 
would not apply to customer-specific requests for service under the pro 
forma OATT. It notes that the Commission provided this clarification in 
Order No. 890, and it suggests that the Commission had the same intent 
in the Proposed Rule. Entergy argues that the types of projects set 
forth in the Proposed Rule do not include customer-specific requests 
for service, and it explains that such requests are evaluated pursuant 
to specific OATT procedures that govern system impact and facilities 
studies, and are performed in consultation with the affected customer, 
not vetted through a regional stakeholder process. Entergy notes that 
upgrades necessary to meet the specific request are similarly 
constructed to meet the needs of the customers, and are not subjected 
to a cost-benefit test to identify beneficiaries. Entergy cites to its 
own proposal regarding customer-specific service requests that the 
Commission found ``will promote, not discourage, efficient 
investments.'' \533\
---------------------------------------------------------------------------

    \533\ Entergy Servs., Inc., 115 FERC ] 61,095, at P 168 (2006).
---------------------------------------------------------------------------

    720. Some commenters that support participant funding as a cost 
allocation method raise concerns about overly broad socialization of 
costs absent such a mechanism.\534\ Large Public Power Council adds 
that the potential for cost socialization will lead to the planning 
process becoming vastly more contentious. Southern Companies argue that 
the proposed reforms are not consistent with cost causation principles. 
Likewise, Transmission Agency of Northern California argues that broad 
socialization of costs among all transmission customers is inconsistent 
with cost causation principles. Avista and Puget Sound state that the 
cost allocation proposals appear to improperly shift costs to existing 
customers that do not participate in projects. American Forest & Paper 
is concerned about the potential for overly broad socialization of 
costs to diminish incentives for cost-effective planning.
---------------------------------------------------------------------------

    \534\ E.g., Arizona Public Service Company; Large Public Power 
Council; Nebraska Public Power District; WestConnect; and 
Transmission Agency of Northern California.
---------------------------------------------------------------------------

    721. Some commenters believe that existing participant funding cost 
allocation processes are adequate and do not see a need at this time to 
change those existing processes.\535\ These commenters and others,\536\ 
primarily located in the Western Interconnection, believe that 
voluntary coordination and cost allocation of transmission facilities 
are more appropriate, particularly given their experiences, and that a 
mandatory cost allocation requirement could impede the transmission 
planning process and unintentionally delay or impede the development of 
new transmission.\537\ California Commissions contend that this 
voluntary approach has minimized disputes and litigation. Arizona 
Public Service Company, Tucson Electric, and others suggest that 
voluntary participant funding of projects has permitted participants to 
successfully engage in allocating costs for transmission projects in 
the Southwest.
---------------------------------------------------------------------------

    \535\ E.g., WestConnect; PUC of Nevada; Transmission Agency of 
Northern California; and Coalition for Fair Transmission Policy.
    \536\ E.g., Arizona Public Service Company; Bonneville Power; 
Tucson Electric; and California Transmission Planning Group.
    \537\ E.g., Arizona Public Service Company; California 
Commissions; and Western Area Power Administration.
---------------------------------------------------------------------------

    722. Commenters note other challenges to restricting participant 
funding. For example, California Commissions explain that assessment of 
benefits and beneficiaries is particularly challenging for long 
distance interregional transmission that would access remote renewable 
resources, given the uncertainties surrounding the ultimate build-out, 
cost (and cost competitiveness), and long-term purchasers for these 
resources, which are greatly complicated by the fact that energy and 
renewable energy credits may be purchased separately. Xcel states that 
MISO included a proposed solution to the ``first move/free rider'' 
issue, namely, that a generator interconnection customer who funds 
network upgrades pays the entire cost of those upgrades, regardless of 
other parties who may use them. Xcel asks that the Commission encourage 
such flexible and innovative solutions to such issues, particularly as 
public policy requirements are incorporated into transmission planning 
processes.
c. Commission Determination
    723. The Commission finds that participant funding is permitted, 
but not as a regional or interregional cost allocation method. 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. The Commission is 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 as needed in the regional transmission planning process 
would not be constructed in a timely manner, adversely affecting 
ratepayers. On the other hand, we agree that if the costs of a 
transmission facility were to be allocated to non-beneficiaries of that 
transmission facility, then those non-beneficiaries are likely to 
oppose selection of the transmission facility in a regional 
transmission plan for purposes of cost allocation or to otherwise 
impose obstacles that delay or prevent the transmission facility's 
construction. For this reason, we adopt the cost allocation principles 
above that seek, among other things, to ensure that any regional cost 
allocation method or methods developed in compliance with this Final 
Rule allocates costs roughly commensurate with benefits.

[[Page 49950]]

    724. We therefore disagree with commenters who challenge this Final 
Rule's limitation on the use of participant funding on the grounds that 
it is inconsistent with the cost causation principle. Through the cost 
allocation principles adopted above, we require in all cases that 
regional and interregional cost allocation methods result in the 
allocation of costs for new transmission facilities in a manner that is 
roughly commensurate with the benefits received by those who will pay 
those costs. In proposing any cost allocation method or methods on 
compliance, there must be a demonstrated link between the costs imposed 
through a cost allocation method and the benefits received by 
beneficiaries that must pay those costs. However, 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. Indeed, the evaluation of the potential benefits 
and beneficiaries of a proposed transmission facility may facilitate 
negotiations among such entities, potentially leading to greater use of 
participant funding for transmission projects not selected in the 
regional transmission plan for purposes of cost allocation.
    725. Thus, we will not permit participant funding to be the cost 
allocation method for regional or interregional projects that are 
selected in a regional transmission plan for purposes of cost 
allocation. However, 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.
    726. Ad Hoc Coalition of Southeastern Utilities and Arizona 
Corporation Commission have not shown why participant funding is 
uniquely the cost allocation method that most closely follows ``but 
for'' cost causation principles. In fact, established precedent argues 
against this claim. Cost causation principles specify 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 [because] 
without the expectation of its contributions, the facilities might not 
have been built, or might have been delayed.'' \538\ This statement 
embodies ``but for'' reasoning, and since participant funding does not 
in all cases capture all beneficiaries of new facilities, it cannot be 
said to be the cost allocation method that mostly follows ``but for'' 
cost causation principles.\539\ Northern Tier Transmission Group argues 
that participant funding has a higher probability of causing the 
construction of new transmission facilities because it relies on 
willing parties and does not involve parties who are unwilling to bear 
costs and who will engage in litigation to oppose transmission project 
development. Yet nothing in this Final Rule precludes the use of 
participant funding for those transmission projects with the support of 
individual market participants. We find that Northern Tier Transmission 
Group's argument that other cost allocation methods will impair 
construction to be speculative and see no reason to conclude that other 
methods in fact will have this result.
---------------------------------------------------------------------------

    \538\ Illinois Commerce Commission, 576 F.3d 470 at 476.
    \539\ We discuss Ad Hoc Coalition of Southeastern Utilities' 
claim regarding the consistency of participant funding with judicial 
precedent on cost allocation methods below in section IV.F.2.
---------------------------------------------------------------------------

    727. In response to Transmission Agency of Northern California, 
Avista, and Puget Sound, we note that a limitation on participant 
funding is far from a mandate for broad cost socialization. There is 
nothing in our cost allocation reforms that requires broad 
socialization or supports improper cost shifting in violation of cost 
causation principles. As discussed fully above, our cost allocation 
principles require that costs be allocated roughly commensurate with 
the benefits received by those that pay those costs.
    728. In any event, nothing in this Final Rule applies to existing 
transmission facilities with existing cost allocations or to 
transmission projects currently under development.\540\
---------------------------------------------------------------------------

    \540\ See also discussion supra section III.A.3.
---------------------------------------------------------------------------

    729. In response to Entergy's request, we clarify that our cost 
allocation reforms in this Final Rule are not intended to modify 
existing pro forma OATT transmission service mechanisms for individual 
transmission service requests or requests for interconnection service.
3. Whether Regional and Interregional Cost Allocation Methods May 
Differ
a. Commission Proposal
    730. In the Proposed Rule, the Commission explained that the method 
used for allocating interregional transmission facility costs between 
any two transmission planning regions may be different from the method 
used by the public utility transmission providers located in either of 
those transmission planning regions to allocate the costs of new 
regional facilities. Additionally, the Commission proposed that the 
cost allocation method used by the public utility transmission 
providers located in a transmission planning region to allocate the 
costs of new regional facilities could be different from the cost 
allocation method by which the public utility transmission providers in 
the same transmission planning region further allocate costs to be 
borne by that transmission planning region pursuant to an agreed-upon 
method for allocating the costs of interregional facilities.\541\
---------------------------------------------------------------------------

    \541\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 176.
---------------------------------------------------------------------------

b. Comments
    731. Several commenters agree with the Commission's proposal that 
the method used for allocating interregional transmission facility 
costs may differ from the method used to allocate regional costs.\542\ 
Georgia Transmission Corporation states that if an interregional 
coordination obligation would require entities to enter into agreements 
with neighboring regions, the Commission should specify that it would 
not require the transmission entity to accept the neighboring entity's 
cost allocation method. Indianapolis Power & Light states that the cost 
allocation provisions of an interregional coordination agreement should 
set forth how costs are divided between the regions and leave it up to 
the regions to determine how their shares are divided among their 
subregions/zones/customers. MISO Transmission Owners state that 
transmission providers and their stakeholders should be permitted to 
determine whether the cost allocation methods used for regional 
projects should apply to the transmission provider's share of 
interregional facilities.
---------------------------------------------------------------------------

    \542\ E.g., Georgia Transmission Corporation; Indianapolis Power 
& Light; MISO Transmission Owners; NEPOOL; and Northeast Utilities.
---------------------------------------------------------------------------

    732. ISO New England supports the preservation of a voluntary, 
flexible approach to interregional cost allocation that recognizes 
regional differences. It also states that the Final Rule should either 
clarify the manner in which

[[Page 49951]]

agreement on a cost allocation would be signified by each of the two 
regions or provide for flexibility in recognition of the mechanisms 
that may be most appropriate in light of the internal transmission 
planning processes of the paired regions.
c. Commission Determination
    733. We find that the method or methods for interregional cost 
allocation used by two transmission planning regions may be different 
from the method or methods used by either of them for regional cost 
allocation. Also, the method or methods for allocating a region's share 
of the cost of an interregional transmission facility may differ from 
the method or methods for allocating the cost of a regional facility 
within that region.
    734. Although the public utility transmission providers in a 
transmission planning region may choose to allocate their share of the 
costs of an interregional transmission facility using their regional 
cost allocation method or methods, we see no reason to require them to 
do so. Indeed, for a transmission planning region that shares the cost 
of regional transmission facilities broadly, it may be inappropriate to 
apply broad cost sharing for an interregional transmission facility 
that is found to benefit only part of that transmission planning 
region. In addition, an interregional transmission facility may be of 
such greater scale than most regional transmission facilities that it 
may result in different types of benefits and beneficiaries than for a 
regional transmission facility.
    735. In response to Georgia Transmission Corporation, we clarify 
that we do not require the public utility transmission providers in a 
transmission planning region to accept the regional transmission 
planning method or methods of another transmission planning region with 
which it participates regarding interregional transmission 
coordination. Each transmission planning region would determine for 
itself how to allocate the costs of a new interregional transmission 
facility consistent with this Final Rule.
4. Recommendations for Additional Commission Guidance on the 
Application of the Transmission Cost Allocation Principles
    736. Several comments recommend that the Commission provide 
additional guidance on how to apply the cost allocation principles.
a. Comments
    737. A number of commenters provide additional suggestions on cost 
allocation methods. Duke states that without clear pricing guidelines 
that do more than restate general cost allocation principles, regional 
and interregional transmission projects will have trouble getting out 
of the starting gate. Pennsylvania PUC asserts that cost allocation 
principles and methods should be reasonably clear and explainable to 
all stakeholders so that development of a cost allocation paradigm can 
be effectively grasped by all participants. East Texas Cooperatives 
believe that the costs of all transmission facilities needed to 
maintain reliability or to deliver long-term resources to load serving 
entities should be rolled into the applicable zonal, regional, or 
interregional rate, and that individual cost allocation methods should 
clearly set forth a plan for identifying beneficiaries and allocating 
costs to them. Washington Utilities and Transportation Commission is 
concerned that necessary certainty on cost allocation would not be 
achieved if the Final Rule lacks detail on the standards to be applied 
when reviewing or approving cost allocations proposals and the 
Commission opts to develop more precise cost allocation policies on a 
case-by-case basis.
    738. Federal Trade Commission encourages the Commission to consider 
providing stronger guidance regarding transmission cost allocation 
principles. It expresses its concern that unnecessary variance in 
allocation methods will have a disruptive effect on multi-area 
transmission proposals, akin to the disruptive effects that unnecessary 
diversity in methods for calculating available transmission capacity 
had on transmission services spanning multiple areas. Federal Trade 
Commission encourages the Commission to consider whether stronger 
guidance would promote consensus sooner and avoid creating a patchwork 
of transmission cost allocation methods that may not support broad, 
efficient regional markets and low-cost compliance with environmental 
and energy security policy initiatives.
    739. WIRES states that, as proposed, the principles provide only 
the most general outer bounds of acceptable practice and do not specify 
the characteristics of cost allocation methods that the Commission is 
likely to consider just and reasonable. WIRES states that the use of a 
relatively complete set of principles affords the Commission an 
opportunity to help short-cut the endless debates about limited merits 
of participant funding in a network environment and about the extent to 
which the benefits of transmission can be quantified in specific 
instances.
    740. Northwestern Corporation (Montana) asserts that new 
transmission lines should not be insulated from sharing a portion of 
the network costs and/or an allocation of the network revenue 
requirement because new transmission lines experience enhanced 
reliability by connecting to the network transmission system.
    741. Illinois Commerce Commission urges the Commission to remove 
``postage stamp'' cost allocation from the list of acceptable cost 
allocation methods.\543\ It maintains that postage stamp cost 
allocation is highly unlikely to produce just, reasonable, and 
nondiscriminatory rates, and continuing to maintain it as a possible 
cost allocation method is paralyzing transmission expansion.
---------------------------------------------------------------------------

    \543\ ``Postage stamp'' here refers to regionwide allocation of 
the cost of a transmission facility.
---------------------------------------------------------------------------

    742. Other commenters make suggestions or requests for guidance 
that are similar to other commenters' recommendations for additional 
cost allocation principles discussed above. For example, some 
commenters suggest that cost allocation methods should be periodically 
recalculated or reevaluated. Many commenters believe that changes to 
transmission system topology and amendments to state policies could 
alter disbursement of benefits, so the Final Rule should require cost 
allocations to be periodically reviewed and recalculated.\544\ Some of 
these commenters believe that permanent cost allocations may inhibit 
investing in transmission upgrades and that there should be periodic 
reassessments to address any unintended consequences.\545\ For example, 
E.ON and East Texas Cooperatives suggest that cost allocation 
reevaluation should occur every five years. Pennsylvania PUC states 
that a cost allocation method should be designed to evolve and reflect 
system changes over time.
---------------------------------------------------------------------------

    \544\ E.g., Sunflower and Mid-Kansas; Electricity Consumers 
Resource Council and Associated Industrial Groups; PUC of Ohio; East 
Texas Cooperatives; E.ON; and Transmission Dependent Utility 
Systems.
    \545\ E.g., Transmission Dependent Utility Systems; Sunflower 
and Mid-Kansas; E.ON; East Texas Cooperatives; and Massachusetts 
Municipal and New Hampshire Electric.
---------------------------------------------------------------------------

    743. Ohio Consumers Counsel and West Virginia Consumer Advocate 
Division suggest that the Commission adopt a process that allows for 
expedited resolution of disputes over cost allocation that may arise 
during the regional planning process. ISO New

[[Page 49952]]

England recommends Commission-sponsored mediation or other alternative 
dispute resolution for interregional cost allocation to assist two 
regions on reaching agreement if they cannot do so.
    744. Commenters also submitted comments suggesting multiple ways to 
allocate costs of public policy driven projects.\546\ FirstEnergy 
Service Company believes the Commission should clarify that the cost 
causation principle, including the requirement that costs are at least 
roughly commensurate with benefits, applies with full force to public 
policy driven projects in the regional planning process. First Wind 
believes the Commission should seek state input and rely upon state 
judgment on cost allocation for projects flowing from state policy. 
NEPOOL and New England States Committee on Electricity believe that 
each region should have considerable flexibility to develop public 
policy cost allocations. Transmission Dependent Utility Systems notes 
that not all projects proposed to implement public policy are worthy of 
presumptive acceptance and should be rigorously scrutinized in the 
stakeholder process.
---------------------------------------------------------------------------

    \546\ E.g., FirstEnergy Service Company; First Wind; NEPOOL; New 
England States Committee on Electricity; New England Transmission 
Owners; Public Power Council; and Transmission Dependent Utility 
Systems.
---------------------------------------------------------------------------

b. Commission Determination
    745. The Commission appreciates interested commenters' views, 
suggestions and requests for additional Commission guidance regarding 
the development of an acceptable cost allocation method or methods to 
comply with the identified cost allocation principles for new regional 
and interregional transmission facilities. We believe, however, that 
the principles adopted in this Final Rule provide sufficient general 
guidance for public utility transmission providers. The principles 
establish threshold criteria for a cost allocation method or methods to 
facilitate the development of a just and reasonable and not unduly 
discriminatory or preferential cost allocation method or methods. 
Additionally, the principles afford public utility transmission 
providers in individual transmission planning regions the flexibility 
necessary to accommodate unique regional characteristics. The 
Commission is concerned that providing the additional guidance or 
limitations requested by commenters would unduly restrict this 
flexibility. As we explained above, the Commission recognizes the need 
for regions to retain some level of flexibility to account for specific 
regional characteristics, resource types, or policy mandates.
    746. We emphasize, however, that any variations between regions 
must be consistent with the six cost allocation principles. For 
example, East Texas Cooperatives suggest periodic reevaluation of cost 
allocation methods to respond to system changes. We do not view such a 
proposal as inconsistent with the cost allocation principles adopted 
above and, as such, it could be presented and evaluated at the regional 
level and, if agreed upon, proposed to be implemented by that 
transmission planning region. However, the Commission declines to 
prescribe such a policy for all transmission planning regions 
nationwide.
    747. With respect to comments regarding how to allocate costs for 
public policy driven transmission projects, as discussed above,\547\ we 
are not requiring public utility transmission providers to use the same 
cost allocation method for public policy and other types of 
transmission facilities. Instead, as discussed for Cost Allocation 
Principle 6, we permit different regional and interregional cost 
allocation methods for different types of transmission projects. Thus, 
whether each region or pair of transmission planning regions has a 
separate cost allocation method for public policy driven transmission 
projects depends on the consensus within that transmission planning 
region or those transmission planning regions, and we will not 
prescribe a uniform method for such transmission projects.
---------------------------------------------------------------------------

    \547\ See discussion supra section III.E.7.
---------------------------------------------------------------------------

    748. In response to Illinois Commerce Commission, the Commission 
declines to find in advance that a ``postage stamp'' cost allocation 
may not be an acceptable cost allocation method. If public utility 
transmission providers in a region, in consultation with their 
stakeholders, agree to such a method, and it is demonstrated to be 
consistent with the cost allocation principles and is supported with an 
appropriate assessment of benefits, then such an allocation may be 
submitted to the Commission on compliance, and the Commission will 
determine then whether the method meets its requirements.
    749. We also clarify that, by establishing the six principles for 
regional and interregional cost allocation, the Commission is not 
attempting to supersede the cost causation principle. Rather, these six 
principles serve as guidelines for public utility transmission 
providers to use to create cost allocation methods that are consistent 
with the cost causation principle.
    750. With regard to the concerns of Ohio Consumers' Counsel, West 
Virginia Consumer Advocate Division, and ISO New England about dispute 
resolution, the Commission believes that the dispute resolution 
processes in place under Order No. 890, enhanced as may be necessary to 
comply with our transmission planning reforms, will be adequate to 
address in the first instance, any disagreements that may arise 
regarding the allocation of transmission costs. The Commission reviewed 
and approved all of the dispute resolution procedures currently in 
place during our review of the compliance filings in response to Order 
No. 890, requiring enhancements in a number of cases.\548\ We will 
review any changes to those dispute resolution procedures in response 
to compliance filings submitted in response to this Final Rule.
---------------------------------------------------------------------------

    \548\ See, e.g., Idaho Power Co., 128 FERC ] 61,064 at P 30-40; 
Duke Energy Carolinas, LLC, 127 FERC ] 61,281, at P 38-41 (2009); 
New York Indep. Sys. Operator, Inc., 125 FERC ] 61,068, at P 61-64 
(2008).
---------------------------------------------------------------------------

G. Cost Allocation Matters Related to Other Commission Rules, Joint 
Ownership, and Non-Transmission Alternatives

    751. Commenters also raised cost allocation issues related to 
generator interconnection costs in Order No. 2003,\549\ pancaked 
transmission rates policy in Order No. 2000,\550\ transmission rate 
incentives in Order No. 679,\551\ the relationship of this proceeding 
to the proceeding on variable energy resources, Docket No. RM10-11-000, 
and joint transmission ownership.
---------------------------------------------------------------------------

    \549\ Standardization of Generator Interconnection Agreements 
and Procedures, Order No. 2003, 68 FR 49846 (Aug. 18, 2003), FERC 
Stats. & Regs. ] 31,146, at P 676 (2003), order on reh'g, Order No. 
2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160, 
order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), FERC 
Stats. & Regs. ] 31,171 (2004), order on reh'g, Order No. 2003-C, 70 
FR 37661 (Jun. 30, 2005), 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 (DC Cir. 2007), cert. denied, 552 U.S. 1230 (2008).
    \550\ Regional Transmission Organizations, Order No. 2000, 65 FR 
809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 (1999), order on 
reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. & 
Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist. No. 1 of 
Snohomish County, Washington v. FERC, 272 F.3d 607 (DC Cir. 2001).
    \551\ Order No. 679, 71 FR 43294, FERC Stats. & Regs. ] 31,222, 
order on reh'g, Order No. 679-A, 72 FR 1152, FERC Stats. & Regs. ] 
31,236, order on reh'g, 119 FERC ] 61,062.

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[[Page 49953]]

1. Whether To Reform Cost Allocation for Generator Interconnections
    752. In the Proposed Rule, the Commission did not propose to alter 
the cost recovery provisions of its generator interconnection rules.
a. Comments
    753. Several commenters address the interaction between Order No. 
2003 and the cost allocation requirements of this Final Rule. For 
example, Duke seeks clarification that impacts on transmission owners 
in neighboring regions resulting from a specific generator 
interconnection or transmission service request will continue to be 
addressed under the existing generation or transmission interconnection 
arrangements. East Texas Cooperatives urge the Commission to require 
development of an integrated process for studying network and point-to-
point transmission service requests and generator interconnection 
requests that affect neighboring regions.
    754. Other commenters address the interaction between Order No. 
2003 and the transmission planning requirements. For instance, Solar 
Energy Industries and Large-scale Solar state that the Commission 
should require transmission providers to coordinate the transmission 
planning study process with the generator interconnection study 
process. PPL Companies agree stating that this would ensure that 
interconnection customers and native load bear their fair share of the 
costs of new transmission. On the other hand, NextEra believes that the 
costs of transmission projects identified through the transmission 
planning process should not be allocated to generators.
    755. Some commenters urge the Commission to reevaluate the cost 
responsibilities in Order No. 2003 because they believe these are being 
used to circumvent the transmission planning process, creating a 
situation where load serving entities are forced to finance projects 
without project beneficiaries being identified.\552\ If this continues, 
Bay Area Municipal Transmission Group asserts that greater transparency 
in the interconnection process is needed to facilitate the 
determination of the most cost-effective interconnection alternative. 
California Municipal Utilities argue that, if the costs of network 
upgrades identified through generator interconnection studies are borne 
by load within a region, those upgrades should be examined by the 
regional transmission planning process as a necessary precondition to 
approval by the relevant transmission provider. Six Cities note that 
the California ISO had represented in an Order No. 890 compliance 
filing that all interconnection-related network upgrades would be 
submitted through the request window open in each planning cycle and 
evaluated in the transmission planning process. Northern California 
Power Agency asserts that the generator interconnection process 
includes a loophole whereby transmission providers can circumvent the 
transmission planning process by proposing individual projects that are 
constructed by transmission providers, and recommends that the 
Commission limit the use of interconnection-related upgrades by 
ensuring they are a cost-effective means of grid expansion.
---------------------------------------------------------------------------

    \552\ E.g., Bay Area Municipal Transmission Group; California 
Municipal Utilities; and City of Santa Clara.
---------------------------------------------------------------------------

    756. Several commenters discuss cost allocation for generation 
interconnection in the context of public policy projects. For example, 
Imperial Irrigation District asks the Commission to clarify that 
generation interconnection customers and their off-takers can be 
allocated the costs of public policy projects under the principles 
developed by transmission providers in each region when those 
generation project developers and their off-takers cause the need for 
or benefit from the public policy projects. In its reply comments, City 
of Santa Clara agrees with Imperial Irrigation District. Old Dominion 
agrees with PJM that greater clarity is needed regarding the extent to 
which the Commission is proposing that cost allocation for public 
policy driven projects depart from the existing Order No. 2003 
framework. Old Dominion recommends that the Commission require all 
transmission providers to describe in their respective transmission 
planning and cost allocation tariff filings specific rules governing 
cost allocation for such projects.
    757. East Texas Cooperatives state that they support a cost 
allocation policy under which the costs of network upgrades required to 
serve the native load of a transmission provider's network customers 
are rolled into the transmission provider's rates. They recommend that 
if a network upgrade is needed to accommodate an interconnection 
request for a generating facility that has not been designated as a 
network resource or is not otherwise contractually committed to serve 
customers within the transmission provider's footprint on a long-term 
basis, the interconnecting customer should be required to pay for the 
cost of network upgrades that would not have been required but for the 
interconnection request. They state that applying this policy would 
provide a level of assurance that the cost of such facilities will be 
allocated roughly commensurate to the estimated benefits.
    758. Northern Tier Transmission Group asserts that, if a 
transmission provider does not execute an interconnection agreement 
with a generator, then the transmission provider has no mechanism to 
assess costs upon the generator. Northern Tier Transmission Group 
states that, to the extent the Commission chooses to address this 
practical issue, it should be done in the context of the generator 
interconnection procedures and agreements and not in the context of 
transmission planning.
    759. In response, California ISO argues that such suggestions are 
beyond the scope of this proceeding and, if the Commission wishes to 
overhaul Order No. 2003, it should do so in a separate rulemaking so 
that parties have adequate notice that the Commission is proposing to 
modify its pro forma large generator interconnection procedures. 
Replying to Six Cities, California ISO argues that their assertion is 
based on a misconception that interconnection-related network upgrades 
need to be approved through the transmission planning process. 
California ISO states that Order No. 890 did not apply to such network 
upgrades.
b. Commission Determination
    760. The Commission agrees with the California ISO and other 
commenters that issues related to the generator interconnection process 
and to interconnection cost recovery are outside the scope of this 
rulemaking. Order No. 2003 sets forth the procedures for the 
interconnection of a large generating transmission facility to the bulk 
power system. This Final Rule does not set forth any new requirements 
with respect to such procedures for interconnecting large, small, or 
wind or other generation facilities. Therefore, this Final Rule is not 
the proper proceeding for commenters to raise issues about the 
interconnection agreements and procedures under Order

[[Page 49954]]

Nos. 2003,\553\ 2006 \554\ or 661.\555\ However, in not addressing 
these issues here, 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 use requests for generator interconnections in developing 
assumptions to be used in the transmission planning process.
---------------------------------------------------------------------------

    \553\ 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 (DC Cir. 2007), cert. denied, 
552 U.S. 1230 (2008).
    \554\ 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.
    \555\ 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.
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2. Pancaked Rates
a. Comments
    761. A few commenters ask the Commission to address the pancaking 
of rates within transmission planning regions. Transmission Dependent 
Utility Systems assert that the Proposed Rule should eliminate regional 
rate pancaking as it remains a significant financial dilemma for many 
transmission customers and is destructive to regional planning. 
Transmission Dependent Utility Systems submit that if the Commission is 
going to implement a requirement for regional cost allocation, it 
should, at a minimum, eliminate pancaked rates unless there is an 
existing regional cost allocation method in place.
    762. Sunflower and Mid-Kansas, on the other hand, contend that the 
Commission should modify its ``no pancaking'' policies for an RTO or 
ISO because the policy is not appropriate for large interregional 
projects and will potentially create extremely high rate increases for 
customers.
    763. Gaelectric North America explains that merchant transmission 
developers are creating new pancaked rates. It asserts that, as public 
utilities construct radial merchant lines and allocate their costs 
through participant funding, they are creating additional pancaked 
rates for new generation owners who may wish to utilize these new 
facilities. Gaelectric North America argues that such pancaked rates 
inhibit the development and use of renewable resources. Further, it 
states that stringing radial transmission over network facilities is 
inefficient and pursued only to avoid appropriate cost allocation.
b. Commission Determination
    764. We decline to make new findings with respect to pancaked rates 
in this Final Rule as it is beyond the scope of this proceeding. In 
particular, we do not make any modifications to the Commission's 
pancaked rate provisions for an RTO under Order No. 2000. 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 this Final Rule or make a separate 
filing with the Commission under section 205 or 206 of the FPA, as 
appropriate.
3. Transmission Rate Incentives
    765. In the Proposed Rule, the Commission did not propose to alter 
its transmission rate incentive policies of Order No. 679.
a. Comments
    766. Some commenters suggest that the Commission revisit its policy 
on transmission rate incentives, as set forth in Order No. 679. For 
example, they relate the Commission's proposals regarding nonincumbent 
transmission developers to transmission rate incentives.\556\ 
Transmission Access Policy Study Group suggests that the Commission 
could require an incumbent transmission provider that exercises a 
federal right of first refusal to own and build a transmission facility 
to forgo any incentives on that facility. It argues that an incumbent 
transmission owner that exercises a federal right of first refusal 
should not then be given an incentive as necessary to encourage it to 
construct needed transmission. Minnesota Public Utilities Commission 
and Minnesota Office of Energy Security believe that one reason a 
federal right of first refusal may be justified is because there are 
instances where an incumbent transmission provider's rate of return is 
significantly lower than the incentive rate of return the Commission 
has approved for nonincumbent transmission developers. ITC Companies 
replies that such instances only demonstrate that different 
transmission incentives have been awarded in different cases by 
different regulatory bodies, noting that there are a variety of 
approved utility ROEs across the industry.
---------------------------------------------------------------------------

    \556\ E.g., New England States Committee on Electricity; 
Transmission Access Policy Study Group; and Southern California 
Edison.
---------------------------------------------------------------------------

    767. Other commenters tie the Commission's cost allocation 
proposals to transmission rate incentives. For example, APPA states 
that there is a clear causal connection between thorny cost allocation 
concerns and the Commission's incentive policy. APPA argues that when 
excessive transmission rate incentives are awarded to project sponsors, 
no one benefits from the associated costs except for the sponsors. 
Transmission Access Policy Study Group also suggests that the 
Commission use this opportunity to reevaluate application of Order No. 
679 so that it does not add burdens on the economy or make siting and 
cost allocation issues more difficult than they already are. 
Transmission Dependent Utility Systems also state that transmission 
providers should be able to recover only the costs associated with a 
major transmission project through formula rates if that project was a 
product of an Order No. 890-compliant planning process that also meets 
the requirements of the Final Rule.
    768. Joint Commenters recite cases in which project developers have 
been granted rate incentives that they believe substantially exceed the 
incentives that would result in just and reasonable rates. Joint 
Commenters also assert that the Commission has failed to recognize that 
the financial ground has shifted, citing the recent recession, 
historically low interest rates, and high unemployment. According to 
Joint Commenters, the rate of return needed to attract investment in a 
long-lived asset used to provide monopoly service is less than it was a 
few years ago. Finally, Joint Commenters recommend that the Commission 
revisit two features of its 1992 incentive rate policy statement,\557\ 
concerning the requirement that incentive rate mechanisms be 
symmetrical and the requirement that applicants quantify the benefits 
to ratepayers as the incentive payment is awarded, arguing that these 
principles are equally important today. In its reply comments, Illinois 
Commerce Commission generally agrees with Joint Commenters, as does 
Organization of MISO States.
---------------------------------------------------------------------------

    \557\ Incentive Ratemaking for Interstate Natural Gas Pipelines, 
Oil Pipelines, and Electric Utilities, 61 FERC ] 61,168 (1992).
---------------------------------------------------------------------------

    769. Pacific Gas & Electric recommends that the Commission clearly 
signal in the Final Rule that rate incentives are available for 
utilities that dedicate resources to the successful development of 
needed regional projects. In particular, Pacific Gas & Electric 
suggests that incentives for partnership in the development of major 
backbone projects crossing multiple

[[Page 49955]]

jurisdictions are appropriate. Pacific Gas & Electric suggests that 
incentives should be offered for partnerships to both independent 
transmission companies and incumbent utilities, and that the incentives 
should be conditioned upon establishment of development arrangements 
that ensure consistent design standards are used that are compatible 
with the incumbent system, ongoing coordination of maintenance 
arrangements by responsible entities, and proper bilateral 
interconnection or coordinated operation agreements that will ensure 
the continuity and sustained reliability of the system.
    770. However, a number of commenters oppose calls to reopen Order 
No. 679 in this proceeding.\558\ Several commenters argue that such 
comments are beyond the scope of this rulemaking. They note that Order 
No. 679 was implemented in response to the direction of Congress, 
codified in section 219 of the FPA, to incent transmission investment. 
Some commenters note that Order No. 679 does not undermine transmission 
planning and cost allocation processes because the grant of incentives 
is conditioned on approval of the project under the relevant regional 
transmission planning processes. APPA states that it opposes blanket 
statements supporting the applicability of incentives under Order No. 
679, and notes that Pacific Gas & Electric's request is illuminating 
because it shows how accustomed investor-owned utilities have become to 
obtaining such incentives and how they assume the Commission will 
simply rubber stamp in advance their requests for more incentives.
---------------------------------------------------------------------------

    \558\ E.g., AEP; Edison Electric Institute; EIF Management; ITC 
Companies; National Grid; Pacific Gas & Electric; and PSEG 
Companies.
---------------------------------------------------------------------------

b. Commission Determination
    771. We acknowledge commenters concerns regarding the Commission's 
policy on transmission rate incentives under Order No. 679. However, we 
decline to revisit or modify our policy under Order No. 679 in this 
Final Rule, as it is beyond the scope of this proceeding.\559\
---------------------------------------------------------------------------

    \559\ The Commission issued a Notice of Inquiry on May 19, 2011 
regarding its policy on transmission incentives under Order No. 679. 
See Promoting Transmission Investment Through Pricing Reform, Notice 
of Inquiry, 135 FERC ] 61,146 (2011).
---------------------------------------------------------------------------

4. Relationship of This Proceeding to the Proceeding on Variable Energy 
Resources
a. Comments
    772. APPA argues that, contrary to the Commission's decision not to 
address transmission planning and cost allocation issues in its 
proceeding on the integration of variable energy resources (VER), 
Docket No. RM10-11-000, it believes that the two issues are not easy to 
compartmentalize. According to APPA, effective integration of VERs into 
regional transmission systems depends in large part on the availability 
of transmission facilities to support such integration, which in turn 
raises the issue of who will pay for the additional transmission 
facilities needed to undertake this integration effort. Thus, APPA 
urges the Commission to consider the tariff modification issues raised 
by VERs integration together with the need to develop cost allocation 
methods to pay for the additional transmission facilities that such 
integration requires.\560\
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    \560\ APPA also incorporates by reference the comments it 
submitted in Docket No. RM10-11-000.
---------------------------------------------------------------------------

    773. In its reply comments, Exelon argues that the Commission 
should address in this proceeding the operational issues entailed in 
integrating large amounts of VERs onto the grid in tandem with its 
rules for transmission planning and cost allocation. It states that 
whether or not the Commission issues a single rule in these dockets, it 
should rely on the record developed in the VERs rulemaking proceeding 
in deciding the Final Rule here, arguing that the record in the VERs 
proceeding fully supports the Commission requiring full accounting for 
the costs of integrating wind and other variable resources.
b. Commission Determination
    774. This Final Rule establishes minimum requirements to guide the 
affected entities in developing their own transmission planning 
processes and cost allocation methods, which then will be submitted for 
filing with the Commission. The requirements established by this Final 
Rule apply to transmission planning and cost allocation for all 
resources. The VERs proceeding, however, addresses operational issues. 
To the extent that entities consider it necessary or appropriate to 
consider such operational issues in this Final Rule, they may do so by 
making a separate section 205 filing rather than raise issues on 
compliance in this proceeding.
5. Joint Ownership
a. Comments
    775. A number of commenters urge the Commission to consider joint 
transmission ownership as a financing and cost allocation tool within 
the Proposed Rule. APPA and Six Cities ask the Commission to promulgate 
a rule favoring joint transmission ownership and to require that 
eligibility for rate incentives depend on an applicant's showing that 
it has offered reasonable opportunities for joint transmission 
ownership. APPA asserts that joint ownership diversifies financial 
risks and reduces the overall costs of the project as well as the need 
for transmission incentives. Transmission Access Policy Study Group and 
Transmission Agency of Northern California state that joint ownership 
leads to a more collaborative process in planning and development for 
both pooled systems and load serving entities. Transmission Access 
Policy Study Group states that joint ownership results in more diverse 
generation scenarios, shorter permitting processes during siting, and 
simpler resolutions of cost allocation issues, and points out that 
joint ownership spreads the risk of projects and provides a variety of 
sources of capital for projects.
b. Commission Determination
    776. Specific financing techniques such as joint ownership are 
beyond the scope of this proceeding. Transmission developers are, of 
course, free to consider joint ownership when proposing and developing 
a transmission project. Just as we are not requiring any specific cost 
allocation method, we do not specifically address joint ownership as a 
cost allocation tool in this proceeding. However, we reiterate here our 
statement in Order No. 890 that we believe there are benefits to joint 
ownership of transmission facilities, particularly large backbone 
facilities, both in terms of increasing opportunities for investment in 
the transmission grid, as well as ensuring nondiscriminatory access to 
the transmission grid by transmission customers.\561\
---------------------------------------------------------------------------

    \561\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 593.
---------------------------------------------------------------------------

6. Cost Recovery for Non-Transmission Alternatives
a. Comment Summary
    777. GridSolar suggests that the Commission require utilities and 
RTOs/ISOs to evaluate alternatives to traditional transmission 
solutions on the same basis, using the same standards as those used for 
traditional transmission solutions, and that this could be done through 
a competitive solicitation. GridSolar notes that distributed energy 
resources connect at voltages below 69 kV and therefore do not qualify 
for cost allocation treatment under the

[[Page 49956]]

transmission planning process although they provide the same services 
as other transmission resources. Similarly, 26 Public Interest 
Organizations argue that transmission and non-transmission solutions 
should be treated comparably for cost recovery purposes.
    778. FirstEnergy Service Company argues that while the Proposed 
Rule does not address cost recovery for non-transmission projects, only 
the costs of facilities that perform a transmission function (including 
energy storage projects) should be included in transmission rates. 
FirstEnergy Service Company argues that regional transmission planning 
processes should not be a vehicle for owners of generation or demand 
side management projects that are eligible to earn revenue from sales 
of energy, capacity, and ancillary services to earn subsidies from 
transmission customers.
b. Commission Determination
    779. As we make clear above in the section on Regional Transmission 
Planning, we are maintaining the approach taken in Order No. 890 and 
will require that generation, demand resources, and transmission be 
treated comparably in the regional transmission planning process.\562\ 
However, while the consideration of non-transmission alternatives to 
transmission facilities may affect whether certain transmission 
facilities are in a regional transmission plan, we conclude that the 
issue of cost recovery for non-transmission alternatives is beyond the 
scope of the transmission cost allocation reforms we are adopting here, 
which are limited to allocating the costs of new transmission 
facilities.\563\
---------------------------------------------------------------------------

    \562\  See discussion supra Section III.A.
    \563\ As we stated in the Proposed Rule, the Commission has 
recognized that, in appropriate circumstances, alternative 
technologies may be eligible for treatment as transmission for 
ratemaking purposes. See Proposed Rule, FERC Stats. & Regs. ] 32,660 
at n.58 (citing Western Grid Development, LLC, 130 FERC ] 61,056 
(2010)).
---------------------------------------------------------------------------

V. Compliance and Reciprocity Requirements

A. Compliance

1. Commission Proposal
    780. With the exception of the proposed interregional transmission 
coordination and interregional cost allocation requirements, the 
Proposed Rule would require each public utility transmission provider 
to submit a compliance filing within six months of the effective date 
of the Final Rule in this proceeding. With regard to the proposed 
interregional transmission coordination and interregional cost 
allocation requirements, the Proposed Rule would require each public 
utility transmission provider to submit a compliance filing within one 
year of the effective date of the Final Rule in this proceeding.\564\ 
The Commission proposed that it would assess whether each compliance 
filing satisfies the proposed requirements and principles stated above 
and issue additional orders as necessary to ensure that each public 
utility transmission provider meets the requirements of the Proposed 
Rule.
---------------------------------------------------------------------------

    \564\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 179.
---------------------------------------------------------------------------

2. Comments
    781. Exelon urges the Commission to adhere to its original time 
schedule for compliance filings of six months for intraregional 
transmission planning and one year for interregional agreements. In its 
reply comments, LS Power argues that the six-month and twelve-month 
compliance deadlines are far more generous than the 60-day deadline 
that the Commission provided for compliance with Order No. 888 and the 
filing of revised power pooling and multilateral coordination 
agreements, respectively.
    782. Some commenters suggest that the Commission extend the 
compliance deadlines for up to three years.\565\ Indianapolis Power & 
Light and SPP state that the proposed six-month and one-year deadlines 
do not allow sufficient time for the stakeholder process. Indianapolis 
Power & Light states that this is particularly true if the right of 
first refusal is removed and recommends that the Commission extend the 
deadlines by a minimum of one year. SPP recommends that the Commission 
extend the proposed deadline for regional transmission planning by at 
least six months and for interregional transmission planning and cost 
allocation to three years. MISO Transmission Owners state that the 
Commission should extend all compliance deadlines by a minimum of six 
months. Arizona Corporation Commission states that the Commission 
should recognize that most public utility transmission providers in the 
West are not members of an RTO and will need more time, perhaps 24-36 
months, to draft regional and interregional transmission plans. Arizona 
Public Service Company agrees in is reply comments that the compliance 
deadlines are too aggressive, arguing that the Commission is proposing 
a vast array of changes that will require utilities to develop 
positions, collaborate with neighboring utilities, and reach consensus 
with regional groups.
---------------------------------------------------------------------------

    \565\ E.g., Indianapolis Power & Light; SPP; MISO Transmission 
Owners; Arizona Corporation Commission; and Arizona Public Service 
Company.
---------------------------------------------------------------------------

    783. Western Area Power Administration recommends that, in lieu of 
compliance filings, the Commission require transmission providers to 
file periodic status reports regarding intraregional and interregional 
efforts. As an alternative approach, it recommends that the Commission 
extend the compliance filing deadline to one year for intraregional 
transmission planning and cost allocation issues and two years for 
interregional issues. Ad Hoc Coalition of Southeastern Utilities and 
Large Public Power Council recommend that in lieu of the proposed one-
year compliance filing requirement, that the Commission call for status 
updates on these matters in one year's time, potentially to be followed 
by further orders on a regional basis establishing reasonable timeline 
targets.
    784. Focusing on the six month regional planning compliance 
deadline, some commenters express the view that six months is a 
reasonable compliance period.\566\ LS Power notes that many of the 
commenters expressing opposition to the six-month compliance deadline 
are the same entities that are opposed to removal of the federal right 
of first refusal, suggesting that any extension of compliance periods 
not apply to the federal right of first refusal from jurisdictional 
OATTs and agreements.
---------------------------------------------------------------------------

    \566\ E.g., Northwest & Intermountain Power Procedures Coalition 
and LS Power.
---------------------------------------------------------------------------

    785. Other commenters express concern about the ability of 
transmission providers to meet the six-month compliance filing 
requirement for regional transmission planning requirements.\567\ New 
England States Committee on Electricity states that a Final Rule 
addressing the rights and obligations of nonincumbent transmission 
providers within the regional planning process should provide the 
planning regions adequate time to sort through a means of complying. 
Xcel urges the Commission to allow entities in the Western 
Interconnection sufficient time and latitude to develop mechanisms that 
effectively meet the needs of the region; it states that, given the 
needs of the western region, six months or even one year is an 
unreasonably short period of time to build a structure to comply with 
the Commission's regional transmission planning requirements. 
Washington Utilities and Transportation Commission states that the 
Commission need not proceed with urgency but

[[Page 49957]]

should allow existing regional processes to mature, which may lead to a 
more expeditious and effective transmission planning process.
---------------------------------------------------------------------------

    \567\ E.g., New England States Committee on Electricity and 
Xcel.
---------------------------------------------------------------------------

    786. Focusing on the one year interregional compliance deadline, 
East Texas Cooperatives state that, given the urgent need for 
interregional transmission planning reform, the Commission should 
require filing of interregional transmission planning agreements within 
six months of the effective date of the Final Rule. In its reply 
comments, East Texas Cooperatives add that shortening this deadline 
would motivate transmission providers to improve coordination with 
their adjacent regions. Exelon states that for sets of regions that 
currently have Commission-approved joint operating agreements, the 
Commission should require a six-month compliance filing.
    787. Other commenters contend that the one-year time period for 
compliance filings relating to interregional transmission planning 
agreements is unworkable. Southern Companies doubt that an 
interregional cost allocation agreement could be developed in the 
Southeast within the proposed one-year deadline. ISO/RTO Council states 
that this proposal is unworkable due to the complexity, limited 
resources, the need to involve stakeholders, and potentially the number 
of agreements to be reached. NV Energy agrees, stating that significant 
additional time is needed to address interregional transmission 
agreements and cost allocation issues given the number of parties 
involved. Xcel agrees that the proposed one-year deadline is 
unattainable and the Commission should allow more time for 
interregional planning and cost allocation initiatives to develop 
voluntarily.
    788. Duke and Georgia Transmission Corporation state that the 
Commission should provide two years to submit interregional 
transmission planning agreements, given the number of parties that may 
be involved and the difficulties of developing cost allocation methods. 
Edison Electric Institute requests that the Commission be flexible 
regarding compliance deadlines for interregional agreements and cost 
allocation and consider allowing up to two years for compliance. 
Pennsylvania PUC states that interregional agreements will require many 
actions internal to RTOs and ISOs and planning organizations, therefore 
the Commission should consider expanding the compliance period from one 
year to 18 or 24 months.
    789. With regard to compliance filings by RTOs and ISOs, New York 
ISO argues that the Commission should narrow the scope of the 
compliance filings required under the Final Rule so that RTOs and ISOs 
are not effectively compelled to demonstrate compliance with 
requirements that they have already satisfied in their individual Order 
No. 890 planning proceedings. Several commenters also urge the 
Commission to consider existing RTO or ISO cost allocation methods as 
compliant with the proposed cost allocation principles and to avoid 
reopening debates about regional cost allocation methods already 
approved by the Commission.\568\ Some of these commenters argue that 
existing processes, such as those used in California ISO and ISO New 
England, are reasonable \569\ while others disagree.\570\
---------------------------------------------------------------------------

    \568\ E.g., California ISO; SoCal Edison; San Diego Gas & 
Electric; Eastern Mass. Consumer Owned System; Northeast Utilities; 
MISO; New York ISO; NEPOOL; New England States Committee on 
Electricity; Kansas Corporation Commission; and Xcel.
    \569\ E.g., California PUC; Pacific Gas & Electric; NEPOOL; and 
Connecticut & Rhode Island Commissions.
    \570\ Several commenters, such as the Integrated Transmission 
Benefits Model Proponents and Maine Parties argue that ISO New 
England's current transmission planning and cost allocation methods 
do not comply with this Final Rule. These concerns should be raised 
during the stakeholder process used to develop compliance with this 
Final Rule. To the extent that a commenter believes that its 
concerns have not been resolved in the relevant compliance filing, 
it can raise those concerns at that time in a protest to the 
compliance filing.
---------------------------------------------------------------------------

    790. Several commenters state that the Commission should not 
lightly change existing regional cost allocation methods.\571\ For 
example, Duke states that parties challenging the appropriateness of an 
existing Commission-approved method should bear a heavy burden of 
showing why that method is inconsistent with the Final Rule. 
Transmission Dependent Utility Systems state that the Commission should 
not automatically disrupt current regional cost allocation methods but 
instead require compliance filings that demonstrate that the regional 
cost allocation method was indeed the product of an open and inclusive 
stakeholder process and that the regional cost allocation method either 
meets the Commission's proposed cost allocation principles, or that the 
existing regional cost allocation method is consistent with or superior 
to the requirement of those principles.
---------------------------------------------------------------------------

    \571\ E.g., Duke; New Jersey Board; Northeast Utilities; and 
Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    791. Additionally, MISO Transmission Owners, Indianapolis Power & 
Light, and SPP recommend that the Commission clarify that transmission 
owners in an RTO or ISO are permitted to participate in the compliance 
filing of the RTO or ISO without making a separate compliance filing of 
their own. Omaha Public Power District suggests that providers that are 
not members of an RTO be allowed to participate in the relevant RTO 
planning process to achieve the interregional planning mandate because 
this would reduce the cost of coordination and improve its efficiency 
and effectiveness.
3. Commission Determination
    792. Given the various comments requesting a longer compliance 
period, we extend the compliance filing requirements set forth in the 
Proposed Rule. Accordingly, we find that, with the exception of the 
requirements with respect to interregional transmission coordination 
procedures and an interregional cost allocation method or methods, each 
public utility transmission provider must submit a compliance filing 
within twelve months of the effective date of this Final Rule revising 
its OATT or other document(s) subject to the Commission's jurisdiction 
as necessary to demonstrate that it meets the requirements set forth in 
this Final Rule.\572\ The Commission also requires each public utility 
transmission provider to submit a compliance filing within eighteen 
months of the effective date of this Final Rule revising its OATT or 
other document(s) subject to the Commission's jurisdiction as necessary 
to demonstrate that it meets the requirements set forth herein with 
respect to interregional transmission coordination procedures and an 
interregional cost allocation method or methods. As explained below, we 
expect that the twelve month and eighteen month deadlines provide 
sufficient time for each public utility transmission provider to meet 
the requirements of this Final Rule.
---------------------------------------------------------------------------

    \572\ See Appendix C for the pro forma Attachment K consistent 
with this Final Rule.
---------------------------------------------------------------------------

    793. For those suggesting that current transmission planning and 
cost allocation initiatives should be allowed more time to develop, we 
find that the need to provide rates, terms and conditions of 
jurisdictional service that are just and reasonable and not unduly 
discriminatory or preferential, and the need to build new transmission 
facilities that more efficiently or cost-effectively support the 
reliable development and operation of wholesale electricity markets, 
requires that the reforms adopted in this Final Rule are implemented in 
a timely

[[Page 49958]]

fashion.\573\ The Commission concludes that the time periods provided 
for adoption of these reforms--twelve months for regional transmission 
planning and cost allocation reforms and eighteen months for 
interregional reforms--are reasonable and achievable. These extended 
time periods provide additional time for public utility transmission 
providers to work with their stakeholders to develop transmission 
planning and cost allocation processes that conform with the 
requirements adopted herein.
---------------------------------------------------------------------------

    \573\ This finding is supported by our discussion above in 
section II.
---------------------------------------------------------------------------

    794. We find that the compliance time periods established in this 
Final Rule strike an appropriate balance between implementing needed 
reforms to transmission planning and cost allocation processes in a 
timely fashion and providing time for those involved in these processes 
to work with stakeholders to develop transmission planning and cost 
allocation processes that conform with the requirements adopted herein. 
Moreover, we believe these compliance filing deadlines 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, discussed above in 
section I.C and III.C.I, under which the participants of each 
interconnection are currently collaborating on transmission planning to 
produce an initial long-term plan in mid-2012 and a final plan in 2013. 
For this same reason, we are not persuaded by those commenters that 
recommend that the Commission require periodic status reports in lieu 
of compliance filings.
    795. In response to commenters' requests, we clarify that an RTO or 
ISO and its public utility transmission provider members may make a 
compliance filing that demonstrates that some or all of its existing 
RTO and ISO transmission planning processes are already in compliance 
with this Final Rule, and we will consider this demonstration and any 
contrary views on compliance. We require every public utility 
transmission provider, including an RTO or ISO transmission provider, 
to file its existing or proposed OATT provisions with an explanation of 
how these provisions meet the requirements of this Final Rule. While 
many of the existing transmission planning and cost allocation 
processes and methods may be similar to what this Final Rule requires, 
others may differ because this Final Rule's requirements expand on the 
Order No. 890 requirements. Whether an existing process was approved 
previously by the Commission is not dispositive of whether that process 
complies with this Final Rule.
    796. We recognize that it is possible that some existing RTO and 
ISO transmission planning and cost allocation processes may already 
satisfy the Commission's proposal in whole or in part. However, we 
decline to rule generically, in the absence of a record based on a 
comparison of existing practices with the provisions of this Final 
Rule, on the degree to which a particular RTO or ISO may already be in 
compliance.
    797. Furthermore, public utility transmission owners that are part 
of Commission-jurisdictional RTOs and ISOs may demonstrate compliance 
through that RTO's or ISO's compliance filing and are not required to 
make a separate compliance filing. This includes, in response to SPP, 
compliance with the interregional transmission coordination 
requirements to the extent an RTO or ISO has negotiated the necessary 
arrangements on behalf of its members. In response to Omaha Public 
Power District, we encourage both RTO and ISO members and those not in 
an RTO or ISO to work together regarding regional transmission 
planning. We neither prohibit non-RTO/ISO members that are 
geographically adjacent to and/or contiguous with an RTO/ISO from 
participating in the RTO/ISO's regional transmission planning process 
nor do we require an RTO/ISO to admit nonmembers to its regional 
transmission planning process. The decision on whether to combine their 
transmission planning efforts in this way to comply with the regional 
transmission planning and regional cost allocation requirements and the 
interregional transmission coordination requirements and interregional 
cost allocation requirements of this Final Rule is a decision that is 
best left to the individual entities as well as to the two regions in 
question. In addition, the OATT for the RTO or the ISO of which a 
public utility transmission provider is a part should include commonly 
agreed-to language describing that RTO/ISO's interregional transmission 
coordination with each neighboring transmission planning region.
    798. In addition, in non-RTO/ISO regions, if public utility 
transmission providers in those regions decide to make combined 
compliance filings, they are free to do so. However, each public 
utility transmission providers' OATT must include the reforms required 
in this Final Rule.

B. Reciprocity

1. Commission Proposal
    799. The Commission proposed that transmission providers that are 
not public utilities (i.e., non-public utility transmission providers) 
would have to adopt the requirements of the Proposed Rule as a 
condition of maintaining the status of their safe harbor tariff or 
otherwise satisfying the reciprocity requirement of Order No. 888.\574\ 
The Commission also stated that if it finds on the appropriate record 
that a non-public utility transmission provider is not participating in 
the proposed regional transmission planning and cost allocation 
processes set forth in this Final Rule, the Commission may exercise its 
authority under FPA section 211A \575\ on a case-by-case basis.\576\
---------------------------------------------------------------------------

    \574\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 181 
(citing Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63). 
Under the pro forma OATT, a non-public utility transmission provider 
may satisfy the reciprocity condition in one of three ways. First, 
it may provide service under a tariff that has been approved by the 
Commission under the voluntary ``safe harbor'' provision 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. See Order No. 890, FERC Stats. & Regs. ] 
31,241 at P 163.
    \575\ FPA section 211A(b) provides, in pertinent part, that 
``the Commission may, by rule or order, require an unregulated 
transmitting utility to provide transmission services--(1) at rates 
that are comparable to those that the unregulated transmitting 
utility charges itself; and (2) on terms and conditions (not 
relating to rates) that are comparable to those under which the 
unregulated transmitting utility provides transmission services to 
itself and that are not unduly discriminatory or preferential.'' The 
non-public utility transmission providers referred to in this Final 
Rule include unregulated transmitting utilities that are subject to 
FPA section 211A.
    \576\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 43.
---------------------------------------------------------------------------

2. Comments
    800. Some commenters question whether non-jurisdictional entities 
can legally be required to participate in regional and interregional 
transmission planning and cost allocation processes. Several non-
jurisdictional entities suggest that they cannot. For example, 
Bonneville Power asserts that the proposed mandatory cost allocation 
reforms could conflict with its statutory obligations. Bonneville Power 
states that

[[Page 49959]]

it is required by statute to have Congressional approval before it can 
build facilities outside the Pacific Northwest or build major 
transmission facilities within the Pacific Northwest. Bonneville Power 
states that it is obligated to determine the appropriateness of its 
transmission expenditures, and those expenditures are subject to 
specific directives or limitations that Congress may include in its 
appropriation acts. As a result of these statutory obligations, 
Bonneville Power contends that it must retain the right to review each 
proposal and agree to any proposed allocation of costs from another 
party.
    801. Western Area Power Administration states that it is a federal 
power marketing administration and must comply with statutory 
requirements that apply to such entities, such as the Anti-Deficiency 
Act, the Reclamation Project Act of 1939, and the Flood Control Act of 
1944. Western Area Power Administration argues that these statutory 
requirements preclude involuntary cost allocation of third-party 
transmission facilities to it. Western Area Power Administration also 
argues that requiring it to incorporate a mandatory cost allocation 
share into its rates is inconsistent with the jurisdiction over, and 
power to review, Western Area Power Administration's rates that the 
Department of Energy delegated to the Commission.
    802. Bonneville Power requests that the Commission explain the 
effect of reciprocity in the context of transmission planning and cost 
allocation. Bonneville Power states that if the Commission conditions 
reciprocity on adherence to the Proposed Rule, it requests that the 
Commission state in the Final Rule that it will accommodate deviations 
in compliance filings that are necessary to allow non-public utilities 
to participate. Bonneville Power contends that if the Commission does 
not accept regional deviations, coordinated regional planning and cost 
allocation will likely be unworkable for both public and non-public 
utilities in the Pacific Northwest.
    803. Public Power Council asserts that the Commission's proposed 
cost allocation method will drive non-public utilities out of the 
voluntary planning process. Public Power Council states that 
governmentally-owned utilities are subject to state statutes that may 
limit their ability to enter into contracts involving unknown future 
costs and that bind future district commissions or city councils. 
Public Power Council thus argues that the Commission should either 
abandon its proposal to require binding cost allocation agreements for 
non-RTO areas or withdraw its proposal that voluntary participant 
funding cannot be the sole method of cost allocation when the 
transmission provider is not a participant in an RTO. Omaha Public 
Power District states that it is committed to voluntary participation 
in the transmission planning process. However, it also states that as a 
state political subdivision it is not subject to the Commission's 
general jurisdiction under the FPA and that the Commission has no 
authority to set rates for it without its consent.
    804. Four G&T Cooperatives argues that the Commission does not have 
jurisdiction under the FPA to require non-public utilities to 
participate in regional transmission planning processes or to agree to 
regional cost allocation methods. It also argues that the reciprocity 
provisions under Order Nos. 888 and 890 and the pro forma OATT do not 
provide a basis for requiring non-public utilities to participate in 
regional transmission planning and cost allocation. National Rural 
Electric Coops state that the Commission has consistently refused to 
expand the reach of the reciprocity provision to include transmission 
customers other than those from which the non-public utility is taking 
service and those who are transmission-owning members of an RTO or ISO. 
G&T Cooperatives and National Rural Electric Coops request 
clarification that the Commission is not modifying the scope of the 
reciprocity requirement as established in Order Nos. 888, 890, and 890-
A.
    805. Western Grid Group, on the other hand, recommends that to 
engage non-jurisdictional utilities in regional planning groups, the 
Commission should make it clear that such participation is a 
requirement for Commission recognition of reciprocity tariffs and that 
all entities that share the grid have an obligation in the public 
interest to help plan its expansion and modernization.
    806. SPP states that, consistent with the approach set forth in 
Order No. 890, the Commission should continue to encourage 
participation by non-jurisdictional entities in regional transmission 
planning processes. SPP also states that the Commission should consider 
requiring non-jurisdictional entities that have reciprocity tariffs on 
file with the Commission to modify those tariffs specifically to 
address the obligation to participate in the regional transmission 
planning process and cost allocation mechanism development. Similarly, 
San Diego Gas & Electric suggests that Order No. 888's reciprocity 
requirements be enforced, as necessary. Anbaric and PowerBridge also 
believe that the Final Rule should apply to all transmission providers, 
including to those subject to the Commission's reciprocity 
requirements.
    807. A number of commenters also address the Commission's authority 
under FPA section 211A. National Rural Electric Coops argue that the 
Commission's jurisdiction under FPA section 211A is limited to 
requiring a subset of unregulated transmitting utilities to provide 
transmission services to others on terms and conditions (not relating 
to rates) that are comparable to those under which the unregulated 
transmitting utility provides transmission services to itself and that 
are not unduly discriminatory or preferential. National Rural Electric 
Coops asserts that it is concerned that the Commission may be 
interpreting FPA section 211A to mean that it could invoke the 
provision in circumstances other than those in which it makes a finding 
that an unregulated transmitting utility is not treating its 
transmission customers in a way that is comparable to the way it treats 
itself. National Rural Electric Coops request that the Commission 
clarify that it will address questions of non-comparable treatment on a 
case-by-case basis as necessary. National Rural Electric Coops state 
that such a clarification could help avoid unnecessary litigation.
    808. Imperial Irrigation District questions the Commission's legal 
authority to allocate costs to non-public utilities via either the 
reciprocity principle or FPA section 211A. It states that cost 
allocation is a rate issue, and Congress has not authorized the 
Commission to set rates for non-public utilities. It argues that under 
the Commission's reciprocity principle, the Commission does not set 
rates of non-public utilities.
    809. Large Public Power Council and Nebraska Public Power District 
state that the proposed reciprocity requirement would dramatically 
expand the commitment that non-public utilities were asked to make 
under Order No. 888 and ensuing orders and would greatly exceed the 
Commission's authority. They state that FPA section 211A does not 
permit the Commission to compel a non-public utility to contribute 
funding for regional or interregional transmission projects, nor would 
it enable the Commission to exercise any authority over the 
transmission planning or construction plans of a non-public utility. 
Sacramento Municipal Utility District urges the Commission to 
reconsider its proposal to invoke FPA section 211A

[[Page 49960]]

authority on a case-by-case basis. It states that this is unnecessary, 
beyond the limited reciprocity requirements of Order Nos. 888 and 890, 
and it is beyond the Commission's authority. Western Area Power 
Administration states that FPA section 211A does not authorize the 
Commission to require unregulated transmitting utilities to engage in 
regional transmission planning and cost allocation.
    810. Western Area Power Administration and National Rural Electric 
Coops request clarification that the Commission did not intend its 
statements in the Proposed Rule regarding FPA section 211A and the 
reciprocity provisions of Order Nos. 888 and 890 to expand its 
authority over non-public utilities. Georgia Transmission Cooperative 
argues that the Commission has not provided evidence to support 
application of FPA section 211A and that applying it would be 
inconsistent with prior Commission statements that non-public utilities 
are not subject to the same cost allocation rules as public utilities.
    811. Transmission Access Policy Study Group and Colorado 
Independent Energy Association support the Commission's proposal to 
invoke reciprocity for non-jurisdictional transmission providers as 
needed to achieve its goals, and they agree with the Commission's 
decision not to invoke its authority under FPA section 211A. Colorado 
Independent Energy Association also recommends that to avoid the use of 
FPA section 211A, the Commission should provide a pro forma OATT and a 
date certain for non-jurisdictional entities to report their progress 
to the Commission regarding incorporation of the principles set forth 
in the Proposed Rule into their OATTs and practices. Transmission 
Agency of Northern California believes that the demonstrated 
willingness of non-public utility transmission providers to comply 
voluntarily with Commission directives shows that an explicit 
requirement that they comply with the Proposed Rule is unnecessary.
    812. Other commenters, including MidAmerican and NextEra, suggest 
that the Commission should apply reciprocity or exercise its authority 
under FPA section 211A to require non-public utilities to participate 
in regional and interregional transmission planning and cost allocation 
processes. MidAmerican states that the Commission has the authority to 
require all non-jurisdictional utilities to comply with, and remain 
subject to, the proposed transmission planning and cost allocation 
requirements and that the Commission should use this authority if it 
intends to achieve its stated objectives on a non-discriminatory basis. 
MidAmerican believes that failure to include all transmission providers 
will result in an inequitable burden for jurisdictional utilities and 
their customers, and it will create additional investment uncertainty 
for projects included in the regional plan. NextEra supports the use of 
FPA section 211A to extend the requirements of the Final Rule to 
unregulated transmitting utilities. It believes that invoking FPA 
section 211A on a case-by-case basis is risky and may not ensure 
maximum participation by unregulated utilities. AWEA states that the 
Commission should make clear its intention to invoke FPA section 211A 
as necessary to ensure needed participation in regional transmission 
efforts and cost allocation requirements.
    813. Bonneville Power asserts in its response that neither the 
Proposed Rule, nor any of the initial comments, provide evidence that 
supports invoking FPA section 211A, either on a case-by-case basis or 
generically. Bonneville Power disagrees with MidAmerican that public 
utility transmission providers would be subject to undue discrimination 
if non-public utilities do not participate in transmission planning and 
cost allocation. It argues that any differences in treatment would 
result from adopting the Proposed Rule, not from discrimination by non-
public utilities. Large Public Power Council disagrees that the 
Commission has authority under FPA section 211A to compel non-public 
utilities to participate fully in whatever planning and cost allocation 
rules are adopted in this proceeding. It also states that the 
Commission cannot accomplish indirectly through its reciprocity 
provisions what it cannot accomplish directly under the statute.
    814. MidAmerican also suggests that the Commission use its 
conditioning authority to require non-jurisdictional utilities to 
participate in the regional transmission planning and cost allocation 
processes, stating that the Commission has already taken this approach 
under FPA section 215. However, in reply, Large Public Power Council 
disagrees, noting that section 215 explicitly extends Commission 
jurisdiction for reliability purposes over a wide range of entities, 
thereby confirming that express direction from Congress is required 
before the Commission can exercise jurisdiction over otherwise non-
jurisdictional entities.
3. Commission Determination
    815. 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 this Final Rule. As noted in the Proposed Rule, we are 
encouraged, based on the efforts that followed Order No. 890, that both 
public utility and non-public utility transmission providers 
collaborate in a number of regional transmission planning processes. We 
therefore do not believe it is necessary at this time to invoke our 
authority under FPA section 211A, which gives us authority to require 
non-public utility transmission providers to provide transmission 
services on a comparable and not unduly discriminatory or preferential 
basis. However, if the Commission finds on the appropriate record that 
non-public utility transmission providers are not participating in the 
transmission planning and transmission cost allocation process required 
by this Final Rule, the Commission may exercise its authority under FPA 
section 211A on a case-by-case basis.
    816. Given our decision above, we decline to adopt SPP's suggestion 
that the Commission require non-public utility transmission providers 
that have safe harbor tariffs on file to modify those tariffs 
specifically to address the transmission planning and cost allocation 
processes required by this Final Rule. Rather, it remains up to each 
non-public utility transmission provider whether it wants to maintain 
its safe harbor status by meeting the transmission planning and cost 
allocation requirements of this Final Rule.\577\ We also note in 
response to National Rural Electric Coops and others that the 
Commission is not proposing any changes to the reciprocity provision of 
the pro forma OATT or any other document. The Commission is not 
modifying the scope of the reciprocity provision.
---------------------------------------------------------------------------

    \577\ For this same reason, we find that it is not necessary to 
address Anbaric and PowerBridge's suggestion that this Final Rule 
should apply to all transmission providers, including those subject 
to the Commission's reciprocity provisions and enforced as 
necessary. However, we reiterate our determination in section 
IV.E.2. that an entity participating in the regional transmission 
planning process can be identified as the beneficiary of a regional 
transmission facility and allocated associated costs, irrespective 
of its status as a public utility under the FPA.
---------------------------------------------------------------------------

    817. We disagree with Colorado Independent Energy Association that 
the Commission should impose any requirements on non-public utility 
transmission providers for the purpose of avoiding recourse to section 
211A, as we do not see any necessity, at this time, to invoke our 
authority under that

[[Page 49961]]

section. In addition, we disagree with MidAmerican, NextEra, and SPP 
that we should establish requirements regarding participation by non-
public utility transmission providers in regional and interregional 
transmission planning and cost allocation processes beyond those 
required by reciprocity. We likewise disagree with Western Grid Group 
that we need to clarify for non-public utility transmission providers 
the importance of their participation in the processes established by 
this Final Rule.
    818. The Commission recognizes that many of the existing regional 
transmission planning processes are comprised of both public and non-
public utility transmission providers. In the Proposed Rule, the 
Commission described the significance of its proposal for non-public 
utility transmission providers in terms of the principle of 
reciprocity.\578\ None of the commenters has provided a persuasive 
reason for departing from the position taken in the Proposed Rule. 
Thus, as noted above, and consistent with the approach taken in Order 
No. 890, the Commission expects all public utility and non-public 
utility transmission providers to participate in the transmission 
planning and cost allocation processes set forth in this Final Rule. 
The success of the reforms implemented here will be enhanced if all 
transmission owners participate. Further, we believe 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. 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.
---------------------------------------------------------------------------

    \578\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 43.
---------------------------------------------------------------------------

    819. In response to G&T Cooperatives and others, we note that the 
Commission is not acting here under the FPA to require non-public 
utility transmission providers to participate in regional transmission 
planning processes or to agree to a method or methods for allocating 
the costs of their transmission facilities. Under the reciprocity 
provision, if a public utility transmission provider seeks transmission 
service from a non-public utility transmission provider to which it 
provides open access transmission service, 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.\579\ A non-public utility 
transmission provider that elects to receive such service, therefore, 
must do so on terms that satisfy the reciprocity condition. We disagree 
that we are using the principle of reciprocity to expand our 
jurisdiction over non-public utility transmission providers. Non-public 
utility transmission providers are free to decide whether they will 
seek transmission service that is subject to the Commission's 
jurisdiction, and we do not exercise jurisdiction over them when we 
determine the terms under which public utility transmission providers 
must provide that transmission service.
---------------------------------------------------------------------------

    \579\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 163.
---------------------------------------------------------------------------

    820. While a number of commenters argue that this Final Rule's 
reforms could conflict with their statutory obligations, no specific 
conflict has been presented for us to act on in this Final Rule. 
Concerns about possible conflicts should be raised in transmission cost 
allocation discussions and any subsequent Commission proceedings on 
proposed transmission cost allocation methods.
    821. We disagree with National Rural Electric Coops that our 
discussion of FPA section 211A in the Proposed Rule is unclear or 
ambiguous. However, in response to National Rural Electric Coops we 
note that our intent is to invoke section 211A only on a case-by-case 
basis. We see no reason to reconsider our position on section 211A as 
Sacramento Municipal Utility District requests, nor a need to address 
additional arguments concerning the scope of our authority under 
section 211A given that we are not acting under section 211A in issuing 
this Final Rule. Likewise, in response to Georgia Transmission 
Cooperative, we do not need to provide evidence in this proceeding to 
support the application of FPA section 211A because we are not applying 
it here.
    822. With regard to Transmission Agency of Northern California's 
suggestion that an explicit requirement that non-public utility 
transmission providers comply with the Proposed Rule is unnecessary 
because they are already complying, we note that this Final Rule does 
not include any such explicit requirement and instead only notes an 
expectation that non-public utility transmission providers will 
participate voluntarily.

VI. Information Collection Statement

    823. The Office of Management and Budget (OMB) requires that OMB 
approve certain information collection and data retention requirements 
imposed by agency rules.\580\ 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.
---------------------------------------------------------------------------

    \580\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------

    824. The Commission is submitting the proposed modifications to its 
information collections to OMB for review and approval in accordance 
with section 3507(d) of the Paperwork Reduction Act of 1995.\581\ In 
the Proposed Rule, the Commission solicited comments on the need for 
this information, whether the information will have practical utility, 
the accuracy of provided burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected or retained, 
and any suggested methods for minimizing the respondent's burden, 
including the use of automated information techniques. The Commission 
also included a chart that listed the estimated public reporting 
burdens for the proposed reporting requirements, as well as a 
projection of the costs of compliance for the reporting requirements. 
The Commission received one comment from Arizona Public Service Company 
specifically addressing the Commission burden estimate in the Proposed 
Rule.
---------------------------------------------------------------------------

    \581\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    825. Arizona Public Service Company states that while it supports 
the need for a robust regional transmission planning process, it 
contends that the burden estimate in the Proposed Rule understated the 
number of hours and the average rates of the employees working on these 
processes. As an example, Arizona Public Service Company states that it 
participates in WestConnect, which in the past twelve months has 
involved over two dozen regional or subregional transmission planning 
meetings. According to Arizona Public Service Company, many of these 
meetings last an entire day, and require a significant amount of 
preparation work prior to the meeting. It further contends that the 
Commission should have included calculation of travel expenses of 
participants in the regional transmission planning

[[Page 49962]]

processes, including transportation, lodging, and meal expenses.
    826. In the Proposed Rule, the Commission estimated the number of 
hours required for the average public utility transmission provider to 
comply with the minimum requirements included in the Proposed Rule. The 
burden estimates in this Final Rule represent the incremental burden 
changes related only to the requirements set forth in this Final 
Rule.\582\ It should also be noted that the burden estimates are 
averages for all of the filers. Furthermore, we acknowledge that some 
regional transmission planning processes have been developed to date 
that may require more time to participate than the estimate that the 
Commission provided in the Proposed Rule. However, the fact that such 
processes have been developed reflects the choice of the participants 
in those regional transmission planning processes on how to comply with 
the Commission's rules, it does not mean that the Commission's rules 
necessarily required such processes. For example, we note that public 
utility transmission providers may decide, in a particular region or 
between regions, to develop a regional transmission planning process 
that includes more objectives and procedures than the minimum set forth 
in this Final Rule, which may increase the number of hours necessary to 
participate. In any event, Arizona Public Service Company did not 
provide any estimates of the number of hours that it has taken to 
participate in its regional transmission planning processes, nor 
suggested alternative estimates. Thus, for the most part, the 
Commission adopts the burden estimates that it set out in the Proposed 
Rule.
---------------------------------------------------------------------------

    \582\ 5 CFR 1320.3(b)(1)-(2).
---------------------------------------------------------------------------

    827. As for the hourly rates of the employees, the Commission 
relies on average national salaries to develop hourly rates of the 
employees necessary to comply with the requirements adopted in this 
Final Rule. Again, we note that this is an average rate, and that rates 
may be higher or lower depending on the area of the country where the 
public utility transmission provider is located. Therefore, we find 
that the averages in the Proposed Rule are reasonable estimates of the 
average national rates for the employees described below.
    828. Finally, the Commission has included, in its burden estimate, 
the number of hours that a public utility transmission provider may 
need to travel to participate in a regional transmission planning 
process and interregional transmission coordination procedures.
    Burden Estimate and Information Collection Costs: The estimated 
Public Reporting burden and cost for the requirements contained in this 
Final Rule follow.

----------------------------------------------------------------------------------------------------------------
                                                                                                        Total
                                         Annual       Annual                               Total        annual
    FERC-917--Proposed reporting       number of    number of     Hours per  response      annual      hours in
       requirements in RM10-23        respondents   responses                             hours in    subsequent
                                        (filers)                                           year 1       years
----------------------------------------------------------------------------------------------------------------
Participation in a transparent and            132          132  110 hrs in Year 1; 52         14520         6864
 open regional transmission planning                             hrs in subsequent
 process that meets regional                                     years.
 transmission planning principles,
 includes consideration of
 transmission needs driven by Public
 Policy Requirements, identifies and
 evaluates transmission facilities
 to meet needs, develops cost
 allocation method(s), and produces
 a regional transmission plan that
 describes and incorporates a cost
 allocation method(s) that meets the
 Commission's principles.
Development of interregional                  132          132  133 hrs in Year 1; 43         17556         5676
 transmission coordination                                       hrs in subsequent
 procedures that meet the                                        years.
 Commission's requirements,
 including the ongoing requirement
 to provide or post certain
 transmission planning information
 and provide annual data exchange,
 as well as the development of a
 cost allocation method for
 interregional transmission
 facilities that meets the
 Commission's principles.
Conforming tariff changes for local           132          132  57 hrs in Year 1; 25           7524        33000
 transmission planning, including                                hrs in subsequent
 those related to consideration of                               years.
 transmission needs driven by Public
 Policy Requirements; and conforming
 tariff changes for regional
 transmission planning and
 interregional transmission
 coordination.
                                                                                       -------------------------
    Total Estimated Additional        ...........  ...........  ......................        39600        15840
     Burden Hours, Proposed for FERC-
     917 in NOPR in RM10-23.
----------------------------------------------------------------------------------------------------------------

Cost to Comply

    Year 1: $4,514,400 or [39,600 hours x $114 per hour \583\]
---------------------------------------------------------------------------

    \583\ 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: $1,805,760 or [15,840 hours x $114 per hour]
    Title: FERC-917.
    Action: Proposed Collections.
    OMB Control No: 1902-0233.
    Respondents: 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

    829. Building on the reforms in Order No. 890, the Federal Energy 
Regulatory Commission adopts these amendments to the pro forma OATT to 
correct certain deficiencies in the transmission planning and cost 
allocation requirements for public utility transmission providers. The 
purpose of this Final Rule 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

[[Page 49963]]

and reasonable and not unduly discriminatory or preferential. We expect 
to achieve this goal through this Final Rule by reforming electric 
transmission planning requirements and establishing a closer link 
between cost allocation and regional transmission planning processes.
    830. 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, e-mail: 
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 
Comments concerning the collection of information and the associated 
burden estimate(s), may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street, 
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission, phone: (202) 395-4638, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically 
to the following e-mail address: oira_submission@omb.eop.gov. Comments 
submitted to OMB should include OMB Control No. 1902-0233 and Docket 
No. RM10-23-000.

VII. Environmental Analysis

    831. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\584\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Proposed Rule 
because section 380.4(a)(15) of the Commission's regulations provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to rates and charges for the transmission or 
sale of electric energy subject to the Commission's jurisdiction, plus 
the classification, practices, contracts and regulations that affect 
rates, charges, classifications, and services.\585\ The reforms herein 
do not require transmission or other facilities to be built, but rather 
establish transmission planning mechanisms that will result in a more 
appropriate allocation of costs and thus better ensure just and 
reasonable and not unduly discriminatory or preferential rates.
---------------------------------------------------------------------------

    \584\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
] 30,783 (1987).
    \585\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act Analysis

    832. The Regulatory Flexibility Act of 1980 (RFA) \586\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small entities. 
This Final Rule applies to public utilities that own, control or 
operate interstate transmission facilities other than those that have 
received waiver of the obligation to comply with Order Nos. 888, 889, 
and 890. The total number of public utility transmission providers 
that, absent waiver, must modify their current OATTs by filing the 
revised pro forma OATT is 132. Of these public utility transmission 
providers, only 9 filers, or 6.8 percent, have output of four million 
MWh or less per year.\587\ The Commission does not consider this a 
substantial number and, in any event, each of these entities retains 
its rights to request waiver of these requirements. The criteria for 
waiver that would be applied under this rulemaking for small entities 
is unchanged from that used to evaluate requests for waiver under Order 
Nos. 888, 889, and 890. Accordingly, the Commission certifies that this 
Final Rule will not have a significant economic impact on a substantial 
number of small entities.
---------------------------------------------------------------------------

    \586\ 5 U.S.C. 601-612.
    \587\ A firm is ``small'' if, including its affiliates, it is 
primarily engaged in the generation, transmission, and/or 
distribution of electric energy for sale and its total electric 
output for the preceding fiscal year did not exceed 4 million 
megawatt-hours. Based on the filers of the annual FERC Form 1 and 
Form 1-F, as well as the number of companies that have obtained 
waivers, we estimate that 6.8 percent of the filers are ``small.''
---------------------------------------------------------------------------

IX. Document Availability

    833. 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.
    834. 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, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    835. 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 e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

X. Effective Date and Congressional Notification

    836. These regulations are effective October 11, 2011. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. The Commission will submit 
this Final Rule to both houses of Congress and the Government 
Accountability Office.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission. Commissioner Moeller is dissenting, in part, 
with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends part 35, 
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 71-7352.

0
2. Amend Sec.  35.28 as follows:
0
a. Paragraphs (c)(1) through (c)(1)(iii) are revised.
0
b. Paragraph (c)(1)(vi) is revised.
0
c. Paragraphs (c)(3), (c)(3)(i), and (c)(3)(ii) are revised.
0
d. Paragraphs (c)(4) through (c)(4)(ii) are revised.
0
e. Paragraph (d)(1) is revised.
0
f. Paragraph (e)(1) is revised.

Sec.  35.28   Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce must have on file with the Commission a tariff of general 
applicability for transmission services,

[[Page 49964]]

including ancillary services, over such facilities. Such tariff must be 
the open access pro forma tariff contained in Order No. 888, FERC 
Stats. & Regs. ] 31,036 (Final Rule on Open Access and Stranded Costs), 
as revised by the open access pro forma tariff contained in Order No. 
890, FERC Stats. & Regs. ] 31,241 (Final Rule on Open Access Reforms) 
and further revised in Order No. 1000, FERC Stats. & Regs. ] 31,323 
(Final Rule on Transmission Planning and Cost Allocation by 
Transmission Owning and Operating Public Utilities), or such other open 
access tariff as may be approved by the Commission consistent with 
Order No. 888, FERC Stats. & Regs ] 31,306, Order No. 890, FERC Stats. 
& Regs. ] 32,241, and Order No. 1000, FERC Stats. & Regs. ] 31,323.
    (i) Subject to the exceptions in paragraphs (c)(1)(ii), 
(c)(1)(iii), (c)(1)(iv) and (c)(1)(v) of this section, the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as 
revised by the open access pro forma tariff contained in Order No. 890, 
FERC Stats. & Regs. ] 31,241 and further revised in Order No. 1000, 
FERC Stats. & Regs. ] 31,323, and accompanying rates, must be filed no 
later than 60 days prior to the date on which a public utility would 
engage in a sale of electric energy at wholesale in interstate commerce 
or in the transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities 
used for the transmission of electric energy in interstate commerce as 
of October 11, 2011, it must file the revisions to the pro forma tariff 
contained in Order No. 890, FERC Stats. & Regs. ] 31,241, as amended by 
Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to section 206 
of the FPA and accompanying rates pursuant to section 205 of the FPA in 
accordance with the procedures set forth in Order No. 890, FERC Stats. 
& Regs. ] 31,241 and Order No. 1000, FERC Stats. & Regs ] 31,323.
    (iii) If a public utility owns, controls, or operates transmission 
facilities used for the transmission of electric energy in interstate 
commerce as of October 11, 2011, such facilities are jointly owned with 
a non-public utility, and the joint ownership contract prohibits 
transmission service over the facilities to third parties, the public 
utility with respect to access over the public utility's share of the 
jointly owned facilities must file the revisions to the pro forma 
tariff contained in Order No. 890, FERC Stats. & Regs. ] 31,241 as 
amended by Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to 
section 206 of the FPA and accompanying rates pursuant to section 205 
of the FPA.
* * * * *
    (vi) Any public utility that seeks a deviation from the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as 
revised in Order No. 890, FERC Stats. & Regs. ] 31,241 and Order No. 
1000, FERC Stats. & Regs. ] 31,323, must demonstrate that the deviation 
is consistent with the principles of Order No. 888, FERC Stats. & Regs 
] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. 
1000, FERC Stats. & Regs. ] 31,323.
* * * * *
    (3) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce, and that is a member of a power pool, public utility holding 
company, or other multi-lateral trading arrangement or agreement that 
contains transmission rates, terms or conditions, must have on file a 
joint pool-wide or system-wide open access transmission tariff, which 
tariff must be the pro forma tariff contained in Order No. 888, FERC 
Stats. & Regs. ] 31,036, as revised by the pro forma tariff contained 
in Order No. 890, FERC Stats. & Regs. ] 31,241 and further revised in 
Order No. 1000, FERC Stats. & Regs. ] 31,323, or such other open access 
tariff as may be approved by the Commission consistent with Order No. 
888, FERC Stats. & Regs. ] 31,036, Order No. 890, FERC Stats. & Regs. ] 
31,241, and Order No. 1000, FERC Stats. & Regs. ] 31,323.
    (i) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed after October 11, 2011, 
this requirement is effective on the date that transactions begin under 
the arrangement or agreement.
    (ii) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed on or before October 
11, 2011, a public utility member of such power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
owns, controls, or operates facilities used for the transmission of 
electric energy in interstate commerce must file the revisions to its 
joint pool-wide or system-wide open access transmission tariff 
consistent with Order No. 890, FERC Stats. & Regs. ] 31,241 as amended 
by Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to section 
206 of the FPA and accompanying rates pursuant to section 205 of the 
FPA in accordance with the procedures set forth in Order No. 890, FERC 
Stats. & Regs. ] 31,241 and Order No. 1000, FERC Stats. & Regs ] 
31,323.
* * * * *
    (4) Consistent with paragraph (c)(1) of this section, every 
Commission-approved ISO or RTO must have on file with the Commission a 
tariff of general applicability for transmission services, including 
ancillary services, over such facilities. Such tariff must be the pro 
forma tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, 
as revised by the pro forma tariff contained in Order No. 890, FERC 
Stats. & Regs. ] 31,241 and further revised in Order No. 1000, FERC 
Stats. & Regs. ] 31,323, or such other open access tariff as may be 
approved by the Commission consistent with Order No. 888, FERC Stats. & 
Reg. ] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order 
No. 1000, FERC Stats. & Regs. ] 31,323.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to the pro forma tariff 
contained in Order No. 890, FERC Stats. & Regs. ] 31,241 as amended by 
Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to section 206 
of the FPA and accompanying rates pursuant to section 205 of the FPA in 
accordance with the procedures set forth in Order No. 890, FERC Stats. 
& Regs. ] 31,241 and Order No. 1000, FERC Stats. & Regs ] 31,323.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its 
existing open access tariff is consistent with or superior to the 
revisions to the pro forma tariff contained in Order No. 888, FERC 
Stats. & Regs. ] 31,036, as revised by the pro forma tariff in Order 
No. 890, FERC Stats. & Regs. ] 31,241 and further revised in Order No. 
1000, FERC Stats. & Regs. ] 31,323, or any portions thereof, the 
Commission-approved ISO or RTO may instead set forth such demonstration 
in its filing pursuant to section 206 in accordance with the procedures 
set forth in Order No. 1000, FERC Stats. & Regs ] 31,323.
    (d) * * *
    (1) No later than October 11, 2011, or
* * * * *
    (e) * * *
    (1) A non-public utility may submit a transmission tariff and a 
request for declaratory order that its voluntary transmission tariff 
meets the requirements of Order No. 888, FERC Stats. & Regs. ] 31,036, 
Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. 1000, FERC 
Stats. & Regs. ] 31,323.
* * * * *

    Note: The following appendices will not be published in the Code 
of Federal Regulations.

[[Page 49965]]

                              Appendix A--Summary of Compliance Filing Requirements
----------------------------------------------------------------------------------------------------------------
  Deadline (months after the effective
        date of the final rule)                  Compliance action                Section of the final rule
----------------------------------------------------------------------------------------------------------------
12 months..............................  Submit revised Attachment K of     Section III.A.
                                          the pro forma OATT and any other
                                          Commission jurisdictional
                                          documents to include local and
                                          regional transmission planning
                                          processes that are consistent
                                          with the requirements of this
                                          Final Rule.
12 months..............................  Submit revised Attachment K of     Section III.C.
                                          the pro forma OATT and other
                                          Commission jurisdictional
                                          documents to include a cost
                                          allocation method or methods for
                                          regional cost allocation
                                          consistent with principles of
                                          this Final Rule.
18 months..............................  Submit revised Attachment K of     Section IV.C.
                                          the pro forma OATT and any other
                                          Commission jurisdictional
                                          documents to include an
                                          interregional transmission
                                          coordination procedure or
                                          procedures consistent with the
                                          requirements of this Final Rule.
18 months..............................  Submit revised Attachment K of     Section IV.D.
                                          the pro forma OATT and any other
                                          Commission jurisdictional
                                          documents to include a cost
                                          allocation method or methods for
                                          interregional cost allocation
                                          consistent with the principles
                                          of this Final Rule.
----------------------------------------------------------------------------------------------------------------

Appendix B: Abbreviated Names of Commenters

    The following two tables contain the abbreviated names of 
initial and reply commenters that are used in this Final Rule.

                           Initial Commenters
------------------------------------------------------------------------
           Abbreviation                     Initial commenter(s)
------------------------------------------------------------------------
26 Public Interest Organizations..  Alliance for Clean Energy New York;
                                     Citizens Utility Board of
                                     Wisconsin; Climate and Energy
                                     Project; Conservation Law
                                     Foundation; Earthjustice;
                                     Environment Northeast;
                                     Environmental Defense Fund;
                                     Environmental Law & Policy Center;
                                     Fresh Energy; Great Plains
                                     Institute; Institute for Market
                                     Transformation; Iowa Environmental
                                     Council; Land Trust Alliance;
                                     National Audubon Society; Natural
                                     Resources Defense Council;
                                     Pennsylvania Land Trust Alliance;
                                     Nevada Wilderness Project; NW
                                     Energy Coalition; Pace Energy and
                                     Climate Center; Piedmont
                                     Environmental Council; Project for
                                     Sustainable FERC Energy Policy;
                                     Sierra Club; Southern Alliance for
                                     Clean Energy; The Wilderness
                                     Society; Union of Concerned
                                     Scientists; and Western Grid Group.
Ad Hoc Coalition of Southeastern    Central Electric Power Cooperative,
 Utilities.                          Inc.; 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.
Allegheny Energy Companies........  Monongahela Power Company; The
                                     Potomac Edison Company; West Penn
                                     Power Company; Trans-Allegheny
                                     Interstate Line Company; and
                                     Allegheny Energy Supply Company,
                                     LLC.
ALLETE............................  ALLETE, Inc.
Alliant Energy....................  Alliant Energy Corporate Services,
                                     Inc.
American Antitrust Institute......  American Antitrust Institute.
American Forest & Paper...........  American Forest & Paper Association.
American Transmission.............  American Transmission Company LLC.
Anbaric and PowerBridge...........  Anbaric Holding, LLC; PowerBridge,
                                     LLC.
APPA..............................  American Public Power Association.
Arizona Corporation Commission....  Arizona Corporation Commission.
Arizona Public Service Company....  Arizona Public Service Company.
Atlantic Grid.....................  Atlantic Grid Development, LLC on
                                     behalf of Atlantic Wind Connection.
Avista and Puget Sound............  Avista Corporation and Puget Sound
                                     Energy, Inc.
AWEA..............................  American Wind Energy Association;
                                     Wind on the Wires; Renewable
                                     Northwest Project; Mid-Atlantic
                                     Renewable Energy Coalition;
                                     Alliance for Clean Energy, Inc.;
                                     Interwest Energy Alliance; RENEW;
                                     the Wind Coalition; and Center for
                                     Energy Efficiency and Renewable
                                     Technologies.
Baltimore Gas & Electric..........  Baltimore Gas & Electric Company.
Bay Area Municipal Transmission     City of Santa Clara, California; the
 Group.                              City of Palo Alto, California; and
                                     the City of Alameda, California.
Bonneville Power..................  Bonneville Power Administration.
Boundless Energy and Sea Breeze...  Boundless Energy, LLC and Sea Breeze
                                     Pacific Regional Transmission
                                     System.
Brattle Group (The)...............  Peter Fox-Penner; Johannes
                                     Pfeifenberger; and Delphine Hou.
California Commissions............  California Public Utilities
                                     Commission and the Energy Resources
                                     Conservation and Development
                                     Commission of the State of
                                     California.
California ISO....................  California Independent System
                                     Operator Corporation.

[[Page 49966]]

 
California Municipal Utilities....  California Municipal Utilities
                                     Association (Cities of Alameda;
                                     Anaheim; Azusa; Banning; Burbank;
                                     Cerritos; Colton; Corona; Glendale;
                                     Gridley; Healdsburg; Hercules;
                                     Lodi; Lompoc; Moreno Valley;
                                     Needles; Palo Alto; Pasadena;
                                     Pittsburg; Rancho Cucamonga;
                                     Redding; Riverside; Roseville;
                                     Santa Clara; Shasta Lake; Ukiah;
                                     and Vernon; the Imperial; Merced;
                                     Modesto; Turlock Irrigation
                                     Districts; the Northern California
                                     Power Agency; Southern California
                                     Public Power Authority;
                                     Transmission Agency of Northern
                                     California; Lassen Municipal
                                     Utility District; Power and Water
                                     Resources Pooling Authority;
                                     Sacramento Municipal Utility
                                     District; the Trinity and Truckee
                                     Donner Public Utility Districts;
                                     the Metropolitan Water District of
                                     Southern California; and the City
                                     and County of San Francisco, and
                                     Hetch-Hetchy).
California Transmission Planning    Sacramento Municipal Utility
 Group.                              District; the Imperial Irrigation
                                     District; the Los Angeles
                                     Department of Water and Power; the
                                     Southern California Public Power
                                     Authority; the Transmission Agency
                                     of Northern California; the Turlock
                                     Irrigation District; the Southern
                                     California Edison Company; the
                                     Pacific Gas & Electric Company and
                                     the San Diego Gas & Electric
                                     Company.
California State Water Project....  California Department of Water
                                     Resources State Water Project.
CapX2020 Utilities................  Central Minnesota Municipal Power
                                     Agency; Dairyland Power
                                     Cooperative; Great River Energy;
                                     Minnesota Power; Minnkota Power
                                     Cooperative; Missouri River Energy
                                     Services; Otter Tail Power Company;
                                     Rochester Public Utilities;
                                     Southern Minnesota Municipal Power
                                     Agency; WPPI Energy; and Xcel
                                     Energy Inc.
Champlain Hudson..................  Champlain Hudson Power Express, Inc.
City and County of San Francisco..  City and County of San Francisco.
City of Los Angeles Department of   City of Los Angeles Department of
 Water and Power.                    Water and Power.
City of Santa Clara...............  City of Santa Clara, California.
Clean Energy Group................  Clean Energy Group.
Clean Line........................  Clean Line Energy Partners LLC.
Coalition for Fair Transmission     CMS Energy Corporation; Consolidated
 Policy.                             Edison; DTE Energy Company;
                                     Northeast Utilities; PPL
                                     Corporation; Progress Energy, Inc.;
                                     Public Service Enterprise Group;
                                     SCANA Corporation; Southern
                                     Company; United Illuminating
                                     Company.
Colorado Independent Energy         Colorado Independent Energy
 Association.                        Association.
ColumbiaGrid......................  ColumbiaGrid (Avista Corporation;
                                     Bonneville Power Administration;
                                     Public Utility District No. 1 of
                                     Chelan County, Washington; Public
                                     Utility District No. 1 of Snohomish
                                     County, Washington; Public Utility
                                     District No. 2 of Grant County,
                                     Washington; Puget Sound Energy,
                                     Inc.; City of Tacoma, Department of
                                     Public Utilities, Light Division;
                                     and the City of Seattle, by and
                                     through its City Light Department).
Connecticut & Rhode Island          Connecticut Department of Public
 Commissions.                        Utility Control and the Rhode
                                     Island Public Utilities Commission.
Conservation Law Foundation.......  Conservation Law Foundation.
Consolidated Edison and Orange &    Consolidated Edison Company of New
 Rockland.                           York, Inc. and Orange and Rockland
                                     Utilities, Inc.
Consumers Energy Company..........  Consumers Energy Company.
Dayton Power and Light............  Dayton Power and Light Company
                                     (The).
DC Energy.........................  DC Energy, LLC.
Delaware PSC......................  Delaware Public Service Commission.
Direct Energy.....................  Direct Energy Services, LLC; Direct
                                     Energy Business, LLC; and Energy
                                     America, LLC.
Dominion..........................  Dominion Resources Services, Inc.
Duke..............................  Duke Energy Corporation.
Duquesne Light Company............  Duquesne Light Company.
EARTHJUSTICE......................  EARTHJUSTICE.
East Texas Cooperatives...........  East Texas Electric Cooperative,
                                     Inc.; Northeast Texas Electric
                                     Cooperative, Inc.; Tex-La Electric
                                     Cooperative of Texas, Inc.; Sam
                                     Rayburn G&T Electric Cooperative.
Eastern Massachusetts Consumer-     Belmont Municipal Light Department;
 Owned System.                       Braintree Electric Light
                                     Department; Concord Municipal Light
                                     Plant; Hingham Municipal Lighting
                                     Plant; Reading Municipal Light
                                     Department; Taunton Municipal
                                     Lighting Plant; and Wellesley
                                     Municipal Light Plant.
Edison Electric Institute.........  Edison Electric Institute.
EIF Management....................  EIF Management, LLC.
Electricity Consumers Resource      Electricity Consumers Resource
 Council and the Associated          Council; American Chemistry
 Industrial Groups.                  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.
Enbridge..........................  Enbridge Inc.
Energy Consulting Group...........  Energy Consulting Group LLC
                                     (representing Central Georgia EMC;
                                     Cobb EMC; Diverse Power
                                     Incorporated; Pataula EMC; Snapping
                                     Shoals EMC; Upson EMC; and
                                     Washington EMC).
Energy Future Coalition Group.....  Energy Future Coalition; Alliance
                                     for Clean Energy New York, Inc.;
                                     American Wind Energy Association;
                                     BrightSource Energy, Center for
                                     American Progress, Conservation Law
                                     Foundation; Environmental
                                     Northeast; Fresh Energy; Interwest
                                     Energy Alliance; Invenergy Thermal
                                     Development, LLC; Invenergy Wind
                                     Development, LLC; ITC Holdings,
                                     Corp.; Mesa Power Group; Mid-
                                     Atlantic Renewable Energy
                                     Coalition; Natural Resources
                                     Defense Council; Renewable
                                     Northwest Project; Sierra Club;
                                     Solar Energy Industries
                                     Association; The FERC Project; The
                                     Stella Group, Ltd.; The Wilderness
                                     Society; Union of Concerned
                                     Scientists; Utility Workers Union
                                     of America; and Western Grid Group.

[[Page 49967]]

 
Environmental Defense Fund........  Environmental Defense Fund.
Environmental NGOs................  Environmental Non-Governmental
                                     Organizations (Environmental
                                     Integrity Project; Izaak Walton
                                     League of America; Clean Air
                                     Council; Michigan Environmental
                                     Council; Ohio Citizen Action;
                                     Natural Resources Defense Council;
                                     Fresh Energy; Citizens for
                                     Pennsylvania's Future; Sierra Club;
                                     and Earthjustice).
E.ON..............................  E.ON U.S. LLC.
E.ON Climate & Renewables North     E.ON Climate & Renewables North
 America.                            America, LLC.
Exelon............................  Exelon Corporation.
Federal Trade Commission..........  Federal Trade Commission.
First Wind........................  First Wind Energy, L.L.C.
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.
Four G&T Cooperatives.............  Associated Electric Cooperative;
                                     Basin Electric Power Cooperative;
                                     and Tri-State Generation and
                                     Transmission Association.
Gaelectric North America..........  Gaelectric North America.
Georgia Transmission Corporation..  Georgia Transmission Corporation.
Governors of Delaware and Maryland  Governors of Delaware and Maryland.
Grasslands........................  Grasslands Renewable Energy LLC.
Green Energy and 21st Century.....  Green Energy Express LLC and 21st
                                     Century Transmission Holdings, LLC.
Grid Solar........................  Grid Solar, LLC.
Horizon Wind Energy...............  Horizon Wind Energy LLC.
Iberdrola Renewables..............  Iberdrola Renewables, Inc.
Ignacio Perez-Arriaga.............  Ignacio J. Perez-Arriaga.
Illinios Commerce Commission......  Illinois Commerce Commission.
Imperial Irrigation District......  Imperial Irrigation District.
Independent Energy Producers        Independent Energy Producers
 Association.                        Association.
Indianapolis Power & Light........  Indianapolis Power & Light Company.
Indicated PJM Transmission Owners.  Monongahela Power Company; The
                                     Potomac Edison Company and West
                                     Penn Power Company; and Trans-
                                     Allegheny Interstate Line Company;
                                     Baltimore Gas and Electric Company;
                                     The Dayton Power and Light Company;
                                     Duquesne Light Company; American
                                     Transmission Systems, Incorporated;
                                     Jersey Central Power & Light
                                     Company; Metropolitan Edison
                                     Company; Pennsylvania Electric
                                     Company; Pepco Holdings, Inc.;
                                     Potomac Electric Power Company;
                                     Delmarva Power & Light Company;
                                     Atlantic City Electric Company; PPL
                                     Electric Utilities Corporation; PPL
                                     EnergyPlus, LLC; PPL Brunner
                                     Island, LLC; PPL Holtwood, LLC; PPL
                                     Martins Creek, LLC; PPL Montour,
                                     LLC; PPL Susquehanna, LLC; PPL
                                     University Park, LLC; Lower Mount
                                     Bethel Energy, LLC; Public Service
                                     Electric and Gas Company; PSEG
                                     Power LLC; PSEG Energy Resources &
                                     Trade LLC; UGI Utilities, Inc.; and
                                     Virginia Electric and Power
                                     Company.
Integrated Transmission Benefits    Maine PUC; Maine Office of the
 Model Proponents.                   Public Advocate; Maine Office of
                                     Energy Independence and Security;
                                     New Hampshire Public Utilities
                                     Commission; Environment Northeast;
                                     and Conservation Law Foundation.
Integrys..........................  Wisconsin Public Service
                                     Corporation; Upper Peninsula Power
                                     Company; and Integrys Energy
                                     Services, Inc.
Invenergy.........................  Invenergy Wind Development LLC.
ISO New England...................  ISO New England Inc.
ISO/RTO Council...................  California Independent System
                                     Operator; ISO New England, Inc.;
                                     Midwest Independent Transmission
                                     System Operator, Inc.; New York
                                     Independent System Operator, Inc.;
                                     PJM Interconnection, L.L.C.;
                                     Southwest Power Pool, Inc.
ITC Companies.....................  International Transmission Company;
                                     Michigan Electric Transmission
                                     Company, LLC; ITC Midwest LLC; ITC
                                     Great Plains, LLC; and Green Power
                                     Express LP.
Joint Commenters..................  American Chemistry Council; American
                                     Forest & Paper Association;
                                     American Public Power Association;
                                     California Municipal Utilities
                                     Association; California Public
                                     Utilities Commission; Electricity
                                     Consumers Resource Council; Indiana
                                     Utility Regulatory Commission;
                                     Modesto Irrigation District;
                                     Montana Public Service Commission;
                                     National Association of State
                                     Utility Consumer Advocates; New
                                     England Conference of Public
                                     Utility Commissioners; New
                                     Hampshire Office of Consumer
                                     Advocate; New Jersey Division of
                                     Rate Counsel; New York State Public
                                     Service Commission; Office of the
                                     Nevada Attorney General, Bureau of
                                     Consumer Protection; Old Dominion
                                     Electric Cooperative; Sacramento
                                     Municipal Utility District; South
                                     Dakota Public Utilities Commission;
                                     State of Maine, Office of the
                                     Public Advocate; Transmission
                                     Agency of Northern California;
                                     Utility Reform Network; Vermont
                                     Department of Public Service; and
                                     Vermont Public Service Board.
Kansas City Power & Light and       Kansas City Power & Light Company
 KCP&L Greater Missouri.             and KCP&L Greater Missouri
                                     Operations Company.
Kansas Corporation Commission.....  Kansas Corporation Commission.
Land Trust Alliance...............  Land Trust Alliance.

[[Page 49968]]

 
Large Public Power Council........  Austin Energy; Chelan County Public
                                     Utility District No. 1; Clark
                                     Public Utilities; Colorado Springs
                                     Utilities; CPS Energy (San
                                     Antonio); IID Energy, JEA
                                     (Jacksonville, FL), Long Island
                                     Power Authority; Los Angeles
                                     Department of 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.
Long Island Power Authority.......  Long Island Power Authority.
LS Power..........................  LS Power Transmission, LLC.
Maine PUC.........................  Maine Public Utility Commission.
Maine Utilities...................  Bangor Hydro Electric Company;
                                     Central Maine Power Company; and
                                     Maine Public Service.
Massachusetts Departments.........  Massachusetts Department of Public
                                     Utilities and Massachusetts
                                     Department of Energy Resources.
Massachusetts Municipal and New     Massachusetts Municipal Wholesale
 Hampshire Electric.                 Electric Company and New Hampshire
                                     Electric Cooperative, Inc.
Michigan Citizens Against Rate      Michigan Citizens Against Rate
 Excess.                             Excess.
MidAmerican.......................  MidAmerican Energy Holdings Company.
MISO..............................  Midwest Independent System
                                     Transmission Operator, Inc.
MISO Transmission Owners..........  Ameren Services Company (as agent
                                     for Union Electric Company, Central
                                     Illinois Public Service Company;
                                     Central Illinois Light Co., and
                                     Illinois Power Company); American
                                     Transmission Company LLC; 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
                                     (Minnesota and Wisconsin
                                     corporations); Northwestern
                                     Wisconsin Electric Company; Otter
                                     Tail Power Company; Southern
                                     Illinois Power Cooperative;
                                     Southern Indiana Gas & Electric
                                     Company; Southern Minnesota
                                     Municipal Power Agency; Wolverine
                                     Power Supply Cooperative, Inc.
Minnesota PUC and Minnesota Office  Minnesota Public Utilities
 of Energy Security.                 Commission and Minnesota Office of
                                     Energy Security.
Modesto Irrigation District.......  Modesto Irrigation District.
Multiparty Commenters.............  American Electric Power Corp.; AWEA,
                                     Energy Future Coalition; Iberdrola
                                     Renewables; ITC Holdings Corp.; LS
                                     Power Transmission LLC; Mesa Power
                                     Group, LLC; NextEra Energy, Inc.;
                                     and SEIA.
NARUC.............................  National Association of Regulatory
                                     Utility Commissioners.
National Audubon Society..........  National Audubon Society.
National Grid.....................  National Grid USA.
National Rural Electric Coops.....  National Rural Electric Cooperative
                                     Association.
Natural Resources Defense Council.  Natural Resources Defense Council.
Nebraska Public Power District....  Nebraska Public Power District.
NEPOOL............................  New England Power Pool Participants
                                     Committee.
Nevada Hydro......................  Nevada Hydro Company.
New England States Committee on     New England States Committee on
 Electricity.                        Electricity.
New England Transmission Owners...  Bangor Hydro Electric Company;
                                     Central Maine Power Company; NSTAR
                                     Electric Company; New England Power
                                     Company; Northeast Utilities
                                     Service Company on behalf of the
                                     Northeast utilities system
                                     operating companies; The United
                                     Illuminating Company; and Vermont
                                     Electric Transmission Company,
                                     Inc., on behalf of itself and its
                                     affiliate, Vermont Transco LLC.
New Jersey Board..................  New Jersey Board of Public
                                     Utilities.
New Jersey Division of Rate         New Jersey Division of Rate Counsel.
 Counsel.
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;
                                     Consolidated Edison Company of New
                                     York, Inc.; New York Power
                                     Authority; Long Island Power
                                     Authority; New York State Electric
                                     & Gas Corporation; 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.
Northeast Utilities...............  Northeast Utilities Service Company.
Northern California Power Agency..  Northern California Power Agency.
Northern Tier Transmission Group..  Northern Tier Transmission Group.
Northwest & Intermountain Power     Calpine Corporation; Capital Power
 Producers Coalition.                Operations; Constellation Energy
                                     Control & Dispatch; EverPower
                                     Renewables; Exergy Development
                                     Group; First Wind; Horizon Wind
                                     Energy; Invenergy; LS Power
                                     Associates; Ridgeline Energy; Shell
                                     Energy North America; TransAlta
                                     Marketing, Inc; and TransCanada.
NorthWestern Corporation (Montana)  NorthWestern Corporation (Montana).
NRG Companies.....................  NRG Companies.
NV Energy.........................  Nevada Power Company and Sierra
                                     Pacific Power Company.
Ohio Consumers' Counsel and West    Ohio Consumers' Counsel and West
 Virginia Consumer Advocate          Virginia Consumer Advocate
 Division.                           Division.

[[Page 49969]]

 
Oklahoma Corporation Commission...  Oklahoma Corporation Commission.
Oklahoma Gas and Electric Company.  Oklahoma Gas and Electric Company.
Old Dominion......................  Old Dominion Electric Cooperative.
Omaha Public Power District.......  Omaha Public Power District.
Organization of MISO States.......  Indiana Utility Regulatory
                                     Commission; Iowa Utilities Board;
                                     Michigan Public Service Commission;
                                     Minnesota Public Utilities
                                     Commission; Missouri Public Service
                                     Commission; Montana Public Service
                                     Commission; North Dakota Public
                                     Service Commission; South Dakota
                                     Public Utilities Commission;
                                     Wisconsin Public Service
                                     Commission.
Pacific Gas and Electric Pattern    Pacific Gas and Electric Company
 Transmission.                       Pattern Transmission LP.
Pennsylvania PUC..................  Pennsylvania Public Utility
                                     Commission.
PHI Companies.....................  Pepco Holdings, Inc.; Potomac
                                     Electric Power Company; Delmarva
                                     Power & Light Company; and Atlantic
                                     City Electric Company.
Pioneer Transmission..............  Pioneer Transmission, LLC.
PJM...............................  PJM Interconnection, L.L.C.
Powerex...........................  Powerex Corp.
PPL Companies.....................  PPL Electric Utilities Corporation;
                                     PPL EnergyPlus, LLC; PPL Brunner
                                     Island, LLC; PPL Holtwood, LLC; PPL
                                     Martins Creek, LLC; PPL Montour,
                                     LLC; PPL Susquehanna, LLC; PPL
                                     University Park, LLC; Lower Mount
                                     Bethel Energy, LLC; PPL New Jersey
                                     Solar, LLC; PPL New Jersey Biogas,
                                     LLC; PPL RenewableEnergy, LLC; PPL
                                     Montana, LLC; PPL Colstrip I, LLC;
                                     and PPL Colstrip II, LLC.
Primary Power.....................  Primary Power, LLC.
PSC of Wisconsin..................  Public Service Commission of
                                     Wisconsin.
PSEG Companies....................  Public Service Electric and Gas
                                     Company; PSEG Power LLC; and PSEG
                                     Energy Resources & Trade LLC.
Public Power Council..............  Public Power Council.
PUC of Nevada.....................  Public Utility Commission of Nevada.
PUC of Ohio.......................  Public Utility Commission of Ohio.
Sacramento Municipal Utility        Sacramento Municipal Utility
 District.                           District.
Salt River Project................  Salt River Project Agricultural
                                     Improvement and Power District.
San Diego Gas & Electric..........  San Diego Gas & Electric Company.
Six Cities........................  Cities of Anaheim, Azusa, Banning,
                                     Colton, Pasadena, and Riverside,
                                     CA.
Solar Energy Industries and Large-  Solar Energy Industries Association
 scale Solar.                        and Large-scale Solar Association.
Sonoran Institute.................  Sonoran Institute.
South Carolina Electric & Gas.....  South Carolina Electric & Gas
                                     Company.
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.
Southwest Area Transmission         Southwest Area Transmission
 Subregional Planning Group.         Subregional Planning Group.
SPP...............................  Southwest Power Pool, Inc.
Starwood..........................  Starwood Energy Group Global, L.L.C.
Sunflower and Mid-Kansas..........  Sunflower Electric Power Corporation
                                     and Mid-Kansas Electric Company,
                                     LLC.
Transmission Access Policy Study    Transmission Access Policy Study
 Group.                              Group.
Transmission Agency of Northern     Transmission Agency of Northern
 California.                         California.
Transmission Dependent Utility      Arkansas Electric Cooperative
 Systems.                            Corporation; Golden Spread Electric
                                     Cooperative, Inc.; Kansas Electric
                                     Power Cooperative, Inc.; North
                                     Carolina Electric Membership
                                     Corporation; and Seminole Electric
                                     Cooperative, Inc.
Tucson Electric...................  Tucson Electric Power Company.
U.S. Senators Dorgan and Reid.....  United States Senators Byron Dorgan
                                     and Harry Reid.
Vermont Electric..................  Vermont Electric Power Company, Inc.
Virginia State Corporation          Virginia State Corporation
 Commission.                         Commission.
Washington Utilities and            Washington Utilities and
 Transportation Commission.          Transportation Commission.
WECC..............................  Western Electricity Coordinating
                                     Council.
Westar............................  Westar Energy, Inc. and Kansas Gas
                                     and Electric Company.
WestConnect Planning Parties......  Arizona Public Service Company;
                                     Basin Electric Power Cooperative;
                                     Black Hills Corporation; El Paso
                                     Electric Company; Imperial
                                     Irrigation District; NV Energy;
                                     Public Service Company of New
                                     Mexico; Sacramento Municipal
                                     Utility District; Salt River
                                     Project Agricultural Improvement
                                     and Power District; Southwest
                                     Transmission Cooperative, Inc.;
                                     Transmission Agency of Northern
                                     California; Tri-State Generation
                                     and Transmission Association, Inc.;
                                     Tucson Electric Power Company; and
                                     Western Area Power Administration.
Western Area Power Administration.  Western Area Power Administration.
Western Grid Group................  Western Grid Group.
Western Independent Transmission    Western Independent Transmission
 Group.                              Group.
The Wilderness Society and Western  The Wilderness Society and Western
 Resource Advocates.                 Resource Advocates.
Wind Coalition (The)..............  Wind Coalition (The).
WIRES.............................  Working Group for Investment in
                                     Reliable and Economic Electric
                                     Systems.
Wisconsin Electric Power Company..  Wisconsin Electric Power Company.
Xcel..............................  Xcel Energy Services Inc.
------------------------------------------------------------------------

[[Page 49970]]

                            Reply Commenters
------------------------------------------------------------------------
           Abbreviation                      Reply commenter(s)
------------------------------------------------------------------------
26 Public Interest Organizations..  Citizens Utility Board of Wisconsin;
                                     Climate and Energy Project; CNT
                                     Energy; Conservation Law
                                     Foundation; Earth Justice; Energy
                                     Conservation Council of
                                     Pennsylvania; Energy Future
                                     Coalition; Environmental Northeast;
                                     Environmental Defense Fund;
                                     Environmental Law & Policy Center;
                                     Fresh Energy; Great Plains
                                     Institute; Institute for Market
                                     Transformation; Iowa Environmental
                                     Council; Land Trust Alliance;
                                     Midwest Energy Efficiency Alliance;
                                     National Audubon Society; Natural
                                     Resources Defense Council;
                                     Northeast Energy Efficiency
                                     Partnerships; NW Energy Coalition;
                                     Pace Energy and Climate Center;
                                     Pennsylvania Land Trust
                                     Association; Piedmont Environmental
                                     Council; Project for Sustainable
                                     FERC Energy Policy; Sierra Club;
                                     Southern Alliance for Clean Energy;
                                     The Wilderness Society; Union of
                                     Concerned Scientists; Western Grid
                                     Group; Western Resource Advocates;
                                     Wind on the Wires.*\588\
Ad Hoc Coalition of Southeastern    Central Electric Power Cooperative,
 Utilities.                          Inc.; Dalton Utilities; Georgia
                                     Transmission Corporation; JEA;
                                     Louisville Gas & Electric Company
                                     and Kentucky Utilities Company;
                                     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 Municipal Electric          Alabama Municipal Electric
 Authority.                          Authority.
APPA..............................  American Public Power Association.
Arizona Public Service Company....  Arizona Public Service Company.
Atlantic Grid.....................  Atlantic Grid Development, LLC, on
                                     behalf of Atlantic Wind Connection.
Baltimore Gas & Electric..........  Baltimore Gas and Electric Company.
Bay Area Municipal Transmission     City of Santa Clara, California; the
 Group.                              City of Palo Alto, California; the
                                     City of Alameda, California.
Bonneville Power..................  Bonneville Power Administration.
California ISO....................  California Independent System
                                     Operator Corporation.
California PUC....................  California Public Utilities
                                     Commission.
California Transmission Planning    Sacramento Municipal Utility
 Group.                              District; the Imperial Irrigation
                                     District; the City of Los Angeles
                                     Department of Water and Power; the
                                     Southern California Public Power
                                     Authority; the Transmission Agency
                                     of Northern California; the Turlock
                                     Irrigation District; the Southern
                                     California Edison Company; the
                                     Pacific Gas & Electric Company; San
                                     Diego Gas & Electric Company.
City of Santa Clara...............  City of Santa Clara, California.
Coalition for Fair Transmission     CMS Energy Corporation; Consolidated
 Policy.                             Edison; DTE Energy Company;
                                     Northeast Utilities; PPL
                                     Corporation; Progress Energy, Inc.;
                                     Public Service Enterprise Group;
                                     SCANA Corporation; Southern
                                     Company; United Illuminating
                                     Company.
Commissioner Nathan A. Skop of the  Commissioner Nathan A. Skop of the
 Florida PSC.                        Florida PSC.
Conservation Law Foundation.......  Conservation Law Foundation.
Consolidated Edison and Orange &    Consolidated Edison Company of New
 Rockland.                           York, Inc. and Orange and Rockland
                                     Utilities, Inc.
EarthJustice and Environmental      EARTHJUSTICE; Environmental
 Groups.                             Integrity Project; Natural
                                     Resources Defense Council;
                                     Environmental Law & Policy Center;
                                     Fresh Energy.
EarthJustice et al................  EARTHJUSTICE on behalf of Sierra
                                     Club; Natural Resources Defense
                                     Council; National Rural Electric
                                     Coops; Citizens for Pennsylvania's
                                     Future.
Eastern Environmental and           New Jersey Highlands Coalition; New
 Conservation Groups.                Jersey Chapter of the Sierra Club;
                                     Delaware Riverkeeper Network; New
                                     Jersey Conservation Foundation;
                                     Stop the Lines.
East Texas Cooperatives...........  East Texas Electric Cooperative,
                                     Inc.; Northeast Texas Electric
                                     Cooperative, Inc.; Tex-La Electric
                                     Cooperative of Texas, Inc.; Sam
                                     Rayburn G&T Electric Cooperative.
Edison Electric Institute.........  Edison Electric Institute.
EIF Management....................  EIF Management, LLC.
Entergy...........................  Entergy Services Inc., on behalf of
                                     the Entergy Operating Companies
                                     (Entergy Arkansas, Inc.; Entergy
                                     Gulf States Louisiana, LLC; Entergy
                                     Louisiana LLC; Entergy Mississippi,
                                     Inc.; Entergy New Orleans, Inc.;
                                     and Entergy Texas, Inc.
Environmental Defense Fund........  Environmental Defense Fund.
Exelon............................  Exelon Corporation.
First Wind........................  First Wind Energy, L.L.C.
Florida PSC.......................  Florida Public Service Commission.
Green Energy and 21st Century.....  Green Energy Express LLC and 21st
                                     Century Transmission Holdings, LLC.
H-P Energy Resources..............  H-P Energy Resources LLC.
Identified New England              Identified New England Transmission
 Transmission Owners.                Owners.
Illinois Commerce Commission......  Illinois Commerce Commission.
ISO New England...................  ISO New England Inc.
ISO/RTO Council...................  California Independent System
                                     Operator; ISO New England, Inc.;
                                     Midwest Independent Transmission
                                     System Operator, Inc.; New York
                                     Independent System Operator, Inc.;
                                     PJM Interconnection, L.L.C.;
                                     Southwest Power Pool, Inc.
ITC Companies.....................  International Transmission Company;
                                     Michigan Electric Transmission
                                     Company, LLC; ITC Midwest LLC; ITC
                                     Great Plains, LLC; and Green Power
                                     Express LP.

[[Page 49971]]

 
Large Public Power Council........  Austin Energy; Chelan County Public
                                     Utility District No. 1; Clark
                                     Public Utilities; Colorado Springs
                                     Utilities; CPS Energy (San
                                     Antonio); IID Energy, 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; Tacoma
                                     Public Utilities.
LS Power..........................  LS Power Transmission, LLC.
Maine Parties.....................  Maine Public Utilities Commission;
                                     Maine Office of the Public
                                     Advocate; Maine Governor's Office
                                     of Energy, Independence and
                                     Security.
MEAG Power........................  MEAG Power.
MISO Transmission Owners..........  Ameren Services Company (as agent
                                     for Union Electric Company, Central
                                     Illinois Public Service Company;
                                     Central Illinois Light Co., and
                                     Illinois Power Company); American
                                     Transmission Company LLC; 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
                                     (Minnesota and Wisconsin
                                     corporations); Northwestern
                                     Wisconsin Electric Company; Otter
                                     Tail Power Company; Southern
                                     Illinois Power Cooperative;
                                     Southern Indiana Gas & Electric
                                     Company; Southern Minnesota
                                     Municipal Power Agency; Wolverine
                                     Power Supply Cooperative, Inc.
Multiparty Commenters.............  American Electric Power Corp.; AWEA;
                                     Energy Future Coalition; Iberdrola
                                     Renewables; ITC Holdings Corp.; LS
                                     Power Transmission LLC; Mesa Power
                                     Group, LLC; NextEra Energy, Inc.;
                                     SEIA; and Western Grid Group.*
National Grid.....................  National Grid USA.
National Rural Electric Coops.....  National Rural Electric Cooperative
                                     Association.
New England States Committee on     New England States Committee on
 Electricity.                        Electricity.
New Jersey Board..................  New Jersey Board of Public
                                     Utilities.
New York Transmission Owners......  Central Hudson Gas & Electric;
                                     Consolidated Edison Company of New
                                     York, Inc.; New York Power
                                     Authority; Long Island Power
                                     Authority; New York State Electric
                                     & Gas Corporation; Niagara Mohawk
                                     Power Corporation; Orange and
                                     Rockland Utilities, Inc.; and
                                     Rochester Gas and Electric
                                     Corporation.
NextEra...........................  NextEra Energy, Inc.
North Dakota and South Dakota       North Dakota Public Service
 Commission.                         Commission and South Dakota Public
                                     Utilities Commission.
Ohio Consumers' Counsel...........  Office of the Ohio Consumers'
                                     Counsel.
Old Dominion......................  Old Dominion Electric Cooperative.
Organization of MISO States.......  Illinois Commerce Commission;
                                     Indiana Utility Regulatory
                                     Commission; Iowa Utilities Board;
                                     Michigan Public Service Commission;
                                     Minnesota Public Utilities
                                     Commission; Missouri Public Service
                                     Commission; Montana Public Service
                                     Commission; North Dakota Public
                                     Service Commission; Public
                                     Utilities Commission of Ohio;
                                     Pennsylvania Utility Commission;
                                     South Dakota Public Utilities
                                     Commission; Wisconsin Public
                                     Service Commission.*
Pacific Gas and Electric..........  Pacific Gas and Electric Company.
Pattern Transmission..............  Pattern Transmission LP.
PJM...............................  PJM Interconnection, L.L.C.
Powerex...........................  Powerex Corp.
PPL Companies.....................  PPL Electric Utilities Corporation;
                                     PPL EnergyPlus, LLC; PPL Brunner
                                     Island, LLC; PPL Holtwood, LLC; PPL
                                     Martins Creek, LLC; PPL Montour,
                                     LLC; PPL Susquehanna, LLC; PPL
                                     University Park, LLC; Lower Mount
                                     Bethel Energy, LLC; PPL New Jersey
                                     Solar, LLC; PPL New Jersey Biogas,
                                     LLC; PPL RenewableEnergy, LLC; PPL
                                     Montana, LLC; PPL Colstrip I, LLC;
                                     PPL Colstrip II, LLC; PPL Maine,
                                     LLC; PPL Wallingford Energy LLC.*
PSEG Companies....................  Public Service Electric and Gas
                                     Company; PSEG Power LLC; PSEG
                                     Energy Resources & Trade LLC.
Sacramento Municipal Utility        Sacramento Municipal Utility
 District.                           District.
San Diego Gas & Electric..........  San Diego Gas & Electric Company.
Sierra Club.......................  8,203 Sierra Club members,
                                     supporters, and electric system
                                     ratepayers.
Solar Energy Industries and Large-  Solar Energy Industries Association
 scale Solar.                        and Large-scale Solar Association.
South Carolina Office of            South Carolina Office of Regulatory
 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.
Southern New England States.......  Southern New England States.
Transmission Agency of Northern     Transmission Agency of Northern
 California.                         California.
Western Independent Transmission    Western Independent Transmission
 Group.                              Group.
WIRES.............................  Working Group for Investment in
                                     Reliable and Economic Electric
                                     Systems.
------------------------------------------------------------------------

[[Page 49972]]

Appendix C: 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.
---------------------------------------------------------------------------

    \588\ A ``*'' indicates that the composition of this group as 
altered in the reply comment filing.
---------------------------------------------------------------------------

    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.
    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 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;
    (vi) 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;
    (vii) Process for submission of data by merchant transmission 
developers that wish to participate in the transmission planning 
process;
    (viii) The dispute resolution process;
    (ix) The study procedures for economic upgrades to address 
congestion or the integration of new resources;
    (x) The procedures and mechanisms for considering transmission 
needs driven by Public Policy Requirements, consistent with Order 
No. 1000; and
    (xi) 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 
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 e-mail 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.

MOELLER, Commissioner, dissenting in part:
    While I offer substantial praise for this final rule, the 
Commission should have taken a different approach to several important 
issues. But before addressing these issues, we must recognize that all 
of the nation's difficulties in building needed transmission will not 
be resolved by this rule. Rather, this rule largely addresses planning 
for long-distance transmission lines, which is only a subset of the 
critical issues that are inhibiting needed investment.

[[Page 49973]]

    This rule cannot address issues like the delays caused by other 
federal agencies in the siting of important projects, as this 
Commission lacks the legal authority to require other federal agencies 
to act.\589\ And this rule also cannot address issues of state law, 
regardless of the reliability needs that are served by a new 
transmission line. Moreover, and as described further below, this rule 
did not address whether a transmission provider can thwart competitive 
options by refusing to upgrade its transmission system. For these 
reasons, this rule will not resolve all of the difficult issues that 
discourage this nation from constructing needed transmission lines.
---------------------------------------------------------------------------

    \589\ See the comments of PJM at 17, which state that, ``[t]he 
PJM Board approved the Susquehanna-Roseland 500 kV line in 2007. The 
Susquehanna-Roseland line was approved by the state regulatory 
commissions in Pennsylvania and New Jersey for 2012. The line is 
currently delayed by the National Parks Service [sic] and is not 
expected to be in service until 2014 at the earliest.''
---------------------------------------------------------------------------

    Regarding the issues that the final rule does address, I believe 
that the owner of a transmission network should have been provided with 
greater flexibility to ensure the reliability of its own network. 
Moreover, the rule should have clarified that a right of first refusal 
is not a right of ``forever'' refusal. That is, a right to ``forever'' 
block a needed transmission project could prevent the lowest-cost power 
from reaching consumers.
    To encourage needed transmission investment, the final rule permits 
incumbent transmission owners to maintain their existing rights of 
first refusal for: (1) local projects where the incumbent does not seek 
to share the costs of those projects; (2) upgrades to existing assets; 
and (3) projects on existing right of way.\590\ However, notably absent 
from these categories of projects is the right of a utility to build a 
project within its franchised service territory in order to maintain 
the reliability of its existing network--regardless of whether the cost 
of that project is allocated on a regional basis.
---------------------------------------------------------------------------

    \590\ Section III.B.3.d of the final rule, at PP 318-319.
---------------------------------------------------------------------------

    In my view, transmission providers should have been entitled under 
the final rule to maintain their rights of first refusal to build a new 
transmission facility that is: (1) located entirely within the 
provider's franchised service territory; and (2) identified by the 
provider as needed to satisfy NERC reliability standards--even if that 
facility is selected in a regional transmission plan for purposes of 
cost allocation. And because a transmission provider would have 
retained its authority to address reliability issues in its franchised 
service territory, the final rule would not have needed its blanket 
waiver of penalties in the event that a competitor fails to fix a 
reliability issue.\591\
---------------------------------------------------------------------------

    \591\ For a description of the blanket waiver, see section 
III.B.4.b of the final rule, at P 344 (``Provided the public utility 
transmission provider follows the NERC approved mitigation plan, the 
Commission will not subject that public utility transmission 
provider to enforcement action for the specific NERC reliability 
standard violation(s) caused by a nonincumbent transmission 
developer's decision to abandon a transmission facility.'')
---------------------------------------------------------------------------

    Had we allowed all reliability projects within a franchised service 
territory to retain a right of first refusal, this Commission would 
have emphasized its commitment to reliability. An incumbent 
transmission provider should be responsible for reliability needs in 
its franchised territory without regard to cost allocation. And by 
granting a blanket waiver of penalties, the final rule could be placing 
the Commission in a difficult position if a blackout results in 
widespread loss of power, and we are unable to assess a penalty.
    My approach also would have encouraged transmission owners to seek 
regional cost allocation for their own local projects as a way of 
balancing regional costs. Such a balancing of projects could help 
ensure that all the parts of a region receive benefits that are at 
least roughly equivalent. Yet under the final rule, local projects that 
have their costs assigned regionally generally cannot maintain a right 
of first refusal, thus discouraging transmission owners from seeking 
regional cost allocation for their local projects. For this reason, 
instead of encouraging more regional cooperation, the rule could 
ultimately discourage such cooperation by encouraging more local 
transmission projects.
    In addition to my concerns regarding reliability, this Commission 
should have clarified that it was willing to protect the energy markets 
against misuse of the right of first refusal. That is, the Commission 
should have emphasized that a right of first refusal in a Commission-
jurisdictional tariff is not license to effectively block, or endlessly 
delay building, a project that would efficiently and cost effectively 
provide significant benefits to a transmission network. While an 
incumbent utility with a right of first refusal is entitled to have the 
ability to exercise its initial right to develop a project, if it 
decides not to construct, the opportunity to construct the project and 
thus improve the power grid should be available to a non-incumbent 
developer.
    A review of the transmission projects that have been adopted in 
various regional plans indicates that most projects will be allowed to 
retain the right of first refusal under the final rule, as most 
projects involve upgrades to existing assets, or they are built on an 
existing right of way, or their costs are not allocated to other 
transmission providers.\592\ Thus, given the extensive number of 
projects that will be allowed to retain a right of first refusal, the 
Commission should have emphasized that a transmission provider cannot 
use a Commission-jurisdictional \593\ tariff to prevent the lowest-cost 
power from reaching consumers.
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    \592\ For a list of transmission projects that have been 
approved in PJM, see the various plans for PJM, and a comprehensive 
list available at: http://www.pjm.com/planning/rtep-upgrades-status/construct-status.aspx. And see Chapter 8 of CAISO's transmission 
plan for 2010-2011 dated May 18, 2011, available at: http://www.caiso.com/Documents/Board-approvedISO2010-2011TransmissionPlan.pdf.
    \593\ Consistent with the remainder of the rule, any time 
limitation on a right of first refusal under my approach would be 
subject to relevant state and other law concerning property rights, 
contracts, utility franchises, zoning, siting, permitting, 
easements, or rights of way. See section III.B.2.c of the final 
rule, at P 287.
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    Recognizing that no party to this proceeding asserted that a right 
of first refusal grants its holder a right to refuse building a project 
forever, I believe that a federal right of first refusal must be 
exercised within a reasonable time frame. The record in this case 
suggests that 90 days is a reasonable time frame for management to make 
a decision on whether to exercise its right to build a project.\594\ 
While adoption of a 90-day time frame for transmission providers need 
not have been mandated, the Commission should have encouraged every 
region to adopt a time frame that

[[Page 49974]]

best reflects the needs and circumstances of that region.\595\
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    \594\ Comments of Southwest Power Pool at 14-27; AEP Comments at 
3, 19; Comments of Edison Electric Institute at 46-47, Comments of 
Iberdrola Renewables at 23-24; Comments of Indianapolis Power & 
Light at 32; MidAmerican Comments at 24; Comments of MISO 
Transmission Owners at 73; Comments of Oklahoma Gas and Electric 
Co., at 1, 12, 25; SCE Comments at 41-43; PSEG Reply Comments at 12; 
Westar Comments at 6; Comments of ITC Companies at 4, 22; Comments 
of CapX2020 Utilities at 11, where the CapX2020 Utilities consist of 
Central Minnesota Municipal Power Agency, Dairyland Power 
Cooperative, Great River Energy, Minnesota Power, Minnkota Power 
Cooperative, Missouri River Energy Services, Otter Tail Power Co., 
Rochester Public Utilities, Southern Minnesota Municipal Power 
Agency, WPPI Energy, and Xcel Energy Inc. In contrast to these 
comments on a 90-day time limit, LS Power and NextEra object to any 
right of first refusal and state that a 90-day limitation does not 
resolve their objections. LS Power Comments at 14-18 and fn. 20; LS 
Power Reply Comments at 10, 34-35; and NextEra Comments at 16.
    \595\ For example, in the case of the SPP region, the regional 
transmission organization will designate another company to build a 
project if the incumbent decides not to build within 90 days. 
Comments of Southwest Power Pool at 14-27.
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    In conclusion, new transmission lines can sometimes be the lowest-
cost way to improve the delivery of electricity. By building needed 
transmission, our nation's transmission network can be maintained at 
reliability levels that are the envy of the world, while simultaneously 
improving consumer access to lower-cost power generation. Plus, a well-
designed transmission network can allow efficient and cost-effective 
renewable resources to compete on an equal basis with traditional 
sources of power. While this rule moves us forward to achieve those 
goals, a different approach would have been better on the issues 
described above.
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Philip D. Moeller

Commissioner

[FR Doc. 2011-19084 Filed 8-10-11; 8:45 am]
BILLING CODE 6717-01-P