136 FERC ¶ 61,051 

UNITED STATES OF AMERICA 

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 

(Issued July 21, 2011) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule 

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: (1) requires that each public utility 

transmission provider participate in a regional transmission planning process that 

produces a regional transmission plan; (2) 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; (3) removes from Commission-approved tariffs and 

agreements a federal right of first refusal for certain new transmission facilities; and (4) 

improves coordination between neighboring transmission planning regions for new 
Docket No. RM10-23-000 - 2 - 

interregional transmission facilities. Also, this Final Rule requires that each public utility 

transmission provider must participate in a regional transmission planning process that 

has: (1) a regional cost allocation method for the cost of new transmission facilities 

selected in a regional transmission plan for purposes of cost allocation; and (2) an 

interregional cost allocation method for the cost of 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. 

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:
136 FERC ¶ 61,051 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Marc Spitzer, Philip D. Moeller, 

 John R. Norris, and Cheryl A. LaFleur. 

Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities 

Docket No. RM10-23-000 

ORDER NO. 1000 

FINAL RULE 

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction ............................................................................................................................1.

A. Order Nos. 888 and 890 ...................................................................................................15.

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

Planning and Cost Allocation ................................................................................................22.

C. Additional Developments Since Issuance of Order No. 890 ..........................................25.

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 Planning..................................70.

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.
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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 Public Policy Requirements...........166.

a. Commission Proposal...............................................................................................166.

b. Comments.................................................................................................................169.

c. Commission Determination......................................................................................203.

B. Nonincumbent Transmission Developers ........................................................................225.

1. Need for Reform Concerning Nonincumbent Transmission Developers.....................228.

a. Commission Proposal...............................................................................................228.

b. Comments ................................................................................................................231.

c. Commission Determination......................................................................................253.

2. Legal Authority To Remove a Federal Right of First Refusal .....................................270.

a. Commission Proposal ..............................................................................................270.

b. Comments Regarding the Commission’s Authority To Implement the 

Proposal.........................................................................................................................271.

c. Commission Determination .....................................................................................284.

3. Removal of a Federal Right of First Refusal from Commission-Jurisdictional 

Tariffs and Agreements .....................................................................................................293.

a. Commission Proposal ..............................................................................................293.

b. Comments Regarding Developer Qualification and Project Identification ............296.

c. Comments Regarding Project Evaluation and Selection .........................................302.

d. Commission Determination ....................................................................................313.

i. Qualification Criteria to Submit a Transmission Project for Selection in the 

Regional Transmission Plan for Purposes of Cost Allocation .................................323.

ii. Submission of Proposals for Selection in the Regional Transmission Plan 

for Purposes of Cost Allocation................................................................................325.

iii. Evaluation of Proposals for Selection in the Regional Transmission Plan 

for Purposes of Cost Allocation................................................................................328.

iv. Cost Allocation for Projects Selected in the Regional Transmission Plan 

for Purposes of Cost Allocation................................................................................332.

v. Rights to Construct and Ongoing Sponsorship....................................................338.

4. Reliability Compliance Obligations of Transmission Developers ...............................341.

a. Comments Regarding Reliability Obligations .........................................................341.

b. Commission Determination .....................................................................................342.

C. Interregional Transmission Coordination.........................................................................345.

1. Need for Interregional Transmission Coordination Reform ........................................347.

a. Commission Proposal...............................................................................................347.
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b. Comments.................................................................................................................351.

c. Commission Determination......................................................................................368.

2. Interregional Transmission Coordination Requirements..............................................374.

a. Interregional Transmission Coordination Procedures..............................................374.

i. Commission Proposal ...........................................................................................374.

ii. Comments............................................................................................................377.

iii. Commission Determination................................................................................393.

b. Geographic Scope of Interregional Transmission Coordination..............................405.

i. Commission Proposal ...........................................................................................405.

ii. Comments............................................................................................................406.

iii. Commission Determination................................................................................415.

3. Implementation of the Interregional Transmission Coordination Requirements.........422.

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 Interregional Transmission 

Coordination..................................................................................................................468.

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 Facilities........................................550.
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1. Commission Proposal ...................................................................................................550.

2. Comments on Cost Allocation Method in Regional Transmission Planning...............553.

3. Commission Determination..........................................................................................558.

D. Cost Allocation Method for Interregional Transmission Facilities ................................566.

1. Commission Proposal ...................................................................................................566.

2. Comments on Interregional Cost Allocation Reforms.................................................568.

3. Commission Determination..........................................................................................578.

E. Principles for Regional and Interregional Cost Allocation ..............................................585.

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 way that is roughly 

commensurate with benefits ..............................................................................................612.

a. Comments ................................................................................................................612.

b. Commission Determination .....................................................................................622.

3. Cost Allocation Principle 2—no involuntary allocation of costs to nonbeneficiaries.......................................................................................................................630.

a. Comments ................................................................................................................630.

b. Commission Determination .....................................................................................637.

4. Cost Allocation Principle 3—benefit to cost threshold ratio........................................642.

a. Comments ................................................................................................................642.

b. Commission Determination .....................................................................................646.

5. Cost Allocation Principle 4—allocation to be solely within transmission 

planning region(s) unless those outside voluntarily assume costs ....................................651.

a. Comments ................................................................................................................651.

b. Commission Determination .....................................................................................657.

6. Cost Allocation Principle 5—transparent method for determining benefits and 

identifying beneficiaries ....................................................................................................665.

a. Comments ................................................................................................................665.

b. Commission Determination .....................................................................................668.

7. Cost Allocation Principle 6—different methods for different types of facilities.........673.

a. Comments ................................................................................................................673.

b. Commission Determination .....................................................................................685.

8. Whether To Establish Other Cost Allocation Principles..............................................694.

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 for Extra-High Voltage 
Docket No. RM10-23-000 - 5 -

Facilities.............................................................................................................................707.

a. Commission Proposal...............................................................................................707.

b. Comments on Cost Allocation for Extra-High Voltage Facilities...........................708.

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 Allocation Methods May Differ................730.

a. Commission Proposal...............................................................................................730.

b. Comments.................................................................................................................731.

c. Commission Determination......................................................................................733.

4. Recommendations for Additional Commission Guidance on the Application of 

the Transmission Cost Allocation Principles.....................................................................736.

a. Comments ................................................................................................................737.

b. Commission Determination .....................................................................................745.

G. Cost Allocation Matters Related to Other Commission Rules, Joint Ownership, and 

Non-Transmission Alternatives .............................................................................................751.

1. Whether To Reform Cost Allocation for Generator Interconnections.........................752.

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 on Variable Energy 

Resources...........................................................................................................................772.

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.
Docket No. RM10-23-000 - 6 -

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 
Docket No. RM10-23-000 - 7 -

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 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 Commissionjurisdictional service are just and reasonable in light of changing conditions in the 

 

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). 
Docket No. RM10-23-000 - 8 -

 

industry. In addition, the Commission believes that these reforms address opportunities 

for undue discrimination by public utility transmission providers. 

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 

Rulemaking3

 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 

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). 
Docket No. RM10-23-000 - 9 -

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. 

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 
Docket No. RM10-23-000 - 10 -

 

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 

4 See infra P 63. 
Docket No. RM10-23-000 - 11 -

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. 

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 Public Policy 
Docket No. RM10-23-000 - 12 -

 

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 costeffective 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 

5 See infra P 313. 
Docket No. RM10-23-000 - 13 -

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. 

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. 
Docket No. RM10-23-000 - 14 -

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 
Docket No. RM10-23-000 - 15 -

 

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. 

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 costeffectively, the regional transmission plan must reflect a fair consideration of 

transmission facilities proposed by nonincumbents, as well as interregional transmission 

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. 
Docket No. RM10-23-000 - 16 -

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 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 
Docket No. RM10-23-000 - 17 -

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 

 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 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). 
Docket No. RM10-23-000 - 18 -

 

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. 

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

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

8

 Order No. 888, FERC Stats. & Regs. at 31,682. 

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. 
Docket No. RM10-23-000 - 19 -

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 
Docket No. RM10-23-000 - 20 -

 

planning studies; and (9) cost allocation for new projects.12 

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 

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

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. 
Docket No. RM10-23-000 - 21 -

 

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. 

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 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. 

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 

15 A small number of public utility transmission providers were granted 

extensions. 
Docket No. RM10-23-000 - 22 -

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. 

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 

 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. 
Docket No. RM10-23-000 - 23 -

 

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 

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). 
Docket No. RM10-23-000 - 24 -

Commission received 107 initial comments and 45 reply comments. 

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 longterm 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 
Docket No. RM10-23-000 - 25 -

 

resources.18 

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. 

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 

(continued...) 

18 Department of Energy, Recovery Act- Resource Assessment and 

Interconnection-Level Transmission Analysis and Planning Funding Opportunity 

Announcement, at 5-6 (June 15, 2009). 

19 Id. at 4-8. 

20 Department of Energy, “DOE Initiative Regarding Interconnection-Level 

Transmission Analysis and Planning;” presented at the NGA Transmission Roundtable 
Docket No. RM10-23-000 - 26 -

 

stakeholders need to be involved in 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. 

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 

by David Meyer of DOE’s Office of Electricity Delivery and Energy Reliability, January 

25, 2011. 

21 Id.

22 Department of Energy, 20% Wind Energy by 2030, at 93 (July 2008). 

23 NERC 2010 Assessment at 22. 
Docket No. RM10-23-000 - 27 -

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 nonbinding 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. 

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 

 24 Id. at 24. 
Docket No. RM10-23-000 - 28 -

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 
Docket No. RM10-23-000 - 29 -

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 

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 

 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. 
Docket No. RM10-23-000 - 30 -

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 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 
Docket No. RM10-23-000 - 31 -

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 
Docket No. RM10-23-000 - 32 -

 

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 outof-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. 

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 

27 Brattle Group, Attachment at 5. 
Docket No. RM10-23-000 - 33 -

 

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 

assertions29 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 

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 (D.C. Cir. 2006) (National Fuel)); Large Public Power Council (citing 

Associated Gas Distrib. v. FERC, 824 F.2d 981 (D.C. 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)). 
Docket No. RM10-23-000 - 34 -

 

that the Commission offers no evidence that the reforms of the type proposed are a 

necessary or satisfactory solution to the perceived problem. 

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 

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. 
Docket No. RM10-23-000 - 35 -

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. 

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 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 

 32 E.g., PSEG Companies and Salt River Project. 
Docket No. RM10-23-000 - 36 -

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 
Docket No. RM10-23-000 - 37 -

 

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 

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. 
Docket No. RM10-23-000 - 38 -

 

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 

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 

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_Indust

ry.pdf. 

37 NERC 2010 Long-Term Reliability Assessment at 25. 
Docket No. RM10-23-000 - 39 -

 

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 

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 

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. 
Docket No. RM10-23-000 - 40 -

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 costeffective 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 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 
Docket No. RM10-23-000 - 41 -

 

that the reforms adopted in this Final Rule are necessary to ensure that Commissionjurisdictional 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. 

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 

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.
Docket No. RM10-23-000 - 42 -

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 
Docket No. RM10-23-000 - 43 -

 

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 

45 National Fuel, 468 F.3d 831 at 839. 
Docket No. RM10-23-000 - 44 -

 

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

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 

46 Id. at 841. 

47 Id. at 844. 
Docket No. RM10-23-000 - 45 -

 

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 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 industrywide 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 

48 Associated Gas Distributors, 824 F.2d 981 at 1013. 

49 Id. at 1018-19. 
Docket No. RM10-23-000 - 46 -

 

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 

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. 

50 Id. at 1019. 

51 Id. at 1018-19. 
Docket No. RM10-23-000 - 47 -

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 
Docket No. RM10-23-000 - 48 -

 

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. 

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 

52 TAPS v. FERC, 225 F.3d 667 at 688; National Fuel, 468 F.3d 831. 

53 824 F.2d 981 at 1008. 
Docket No. RM10-23-000 - 49 -

 

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 

authority54 today to ensure that rates are not unjust and unreasonable and to limit the 

remaining opportunities for undue discrimination. 

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 casespecific 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 

(continued...) 

54 Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153, 159 (D.C. Cir. 1967). 

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., 
Docket No. RM10-23-000 - 50 -

 

rulemaking, not case-by-case adjudications, is the most efficient approach to take to 

resolve the industry wide problems facing us. 

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 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. 

79 FERC ¶ 61,274, at 62,183 (1997). 
Docket No. RM10-23-000 - 51 -

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 costeffective 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 
Docket No. RM10-23-000 - 52 -

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 
Docket No. RM10-23-000 - 53 -

 

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. 

66. Finally, nothing in this Final Rule should be read as the Commission granting 

56 We note that existing planning processes already include specific points at 

which a project will no longer be subject to reevaluation. 
Docket No. RM10-23-000 - 54 -

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 
Docket No. RM10-23-000 - 55 -

 

transmission plan and complies with existing Order No. 890 transmission planning 

principles. Second, this Final Rule adopts reforms under which 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 costeffective solutions for the region. Each of these reforms is discussed more fully below. 

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 

(continued...) 

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. 

58 Because the legal authority concerns raised by commenters with regard to our 
Docket No. RM10-23-000 - 56 -

(3) regional transmission plan and Order No. 890 transmission planning principles; and 

(4) consideration of transmission needs driven by Public Policy Requirements. 

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 

 

regional transmission planning reforms and our interregional transmission coordination 

reforms are so closely related, we address these concerns together. 

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). 
Docket No. RM10-23-000 - 57 -

 

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 principles61 and that produces a regional transmission plan. 

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 

61 These transmission planning principles are: (1) coordination; (2) openness; 

(3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; and 

(7) economic planning. 

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. 
Docket No. RM10-23-000 - 58 -

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. 

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 

 63 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 55-57 & n.76. 

64 Id. P 63. 
Docket No. RM10-23-000 - 59 -

 

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. 

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 reform. They argue that the regional transmission 

planning concerns expressed in the Proposed Rule are not present in the Southeast. 

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. 

66 E.g., Ad Hoc Coalition of Southeastern Utilities; Avista and Puget Sound; 

Bonneville Power; ColumbiaGrid; Indianapolis Power & Light; Southern Companies; 

and WestConnect. 
Docket No. RM10-23-000 - 60 -

 

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. 

 

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 

67 E.g., California Transmission Planning Group; Sacramento Municipal Utility 

District; and WestConnect. 
Docket No. RM10-23-000 - 61 -

 

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. 

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. 

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. 
Docket No. RM10-23-000 - 62 -

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 
Docket No. RM10-23-000 - 63 -

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. 26 

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 
Docket No. RM10-23-000 - 64 -

 

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 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 

(continued...) 

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 
Docket No. RM10-23-000 - 65 -

al 

 

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 potenti

impact such investments could have on rates for Commission-jurisdictional service, we 

California ISO transmission planning process and stating “we find that CAISO 

reasonably concluded that PG&E's project is ultimately the most prudent and costeffective 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.”). 

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. 
Docket No. RM10-23-000 - 66 -

conclude it is necessary to act at this time to enhance the transmission planning-related 

requirements imposed in Order No. 890. 

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 
Docket No. RM10-23-000 - 67 -

 

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. 

83. As the Commission explained in the Proposed Rule, consideration of Public Policy 

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. 
Docket No. RM10-23-000 - 68 -

ven 

re 

ervices are just and 

 

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 dri

by Public Policy Requirements could facilitate the more efficient and cost-effective 

achievement of those requirements, we conclude the reforms adopted herein a

necessary to ensure that rates for Commission-jurisdictional s

reasonable. 

84. Turning to the commenters opposed to these reforms, we are not persuaded by 

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. 
Docket No. RM10-23-000 - 69 -

re 

 the 

st-

, we 

s, terms 

, 

not intend our reforms to preclude the ability of states to actively plan at the local 

level. 

 

those who argue that any problems with existing transmission planning are local in natu

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 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

pro forma OATT are inadequate to ensure the development of more efficient or co

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

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 rate

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 

75 See discussion supra section II.C. 
Docket No. RM10-23-000 - 70 -

2. Legal Authority for Transmission Planning Reforms76

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 

b. Comments

86. Several commenters argue that the Commission has adequate statutory authority to

 76 As noted above, because the legal authority concerns raised by commenters

regard to both our regional transmission p

 with 

lanning reforms and our interregional 

transm ss these concerns 

together in this section of the Final Rule. 

ission coordination reforms are so closely related, we addre

77 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 1-2. 
Docket No. RM10-23-000 - 71 -

0. 

’s 

al 

r 

in the 

rements 

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. 89

In response to comments arguing that the Proposed Rule oversteps the Commission

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 leg

authority to implement its proposals, citing the Commission’s plenary authority ove

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 with

Commission’s plenary authority, and they believe that the Proposed Rule properly 

identifies deficiencies in transmission planning and cost allocation, and that requi

for transmission planning and cost allocation are necessary for fully competitive

wholesale markets and thus fall squarely within the Commission’s jurisdiction. 

87. In response to those asserting that the Commission cannot require interregional 

 78 E.g., Iberdrola Renewables; 26 Public Interest Organizations; Exelon; ITC 

Companies; LS Power; and Multiparty Commenters. 

79 535 U.S. 1 (2002). 
Docket No. RM10-23-000 - 72 -

did 

) does not 

s 

ate jurisdiction 

s the 

 that 

courts have consistently recognized the Commission’s need to adjust its regulation under 

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 

not run afoul of section 202(a). ITC Companies also assert that section 202(a

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 Companie

and Multiparty Commenters argue that the proposals do not preempt st

over siting decisions. 26 Public Interest Organizations argue that the FPA require

Commission to address identified transmission planning deficiencies. 

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

 80 272 F.3d 607 (D.C. Cir. 2001). 
Docket No. RM10-23-000 - 73 -

ls but 

h 

bstantial 

ht 

 

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 goa

rather to ensure that transmission service is offered at just and reasonable rates. 

EarthJustice argues that, contrary to commenters challenging the Proposed Rule wit

respect to the consideration of public policy requirements, the Commission did not 

propose to infringe on state jurisdiction. EarthJustice argues that there is su

evidence to support the Commission’s conclusions in the Proposed Rule.82

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 lig

of the voluntary nature of coordination under FPA section 202(a), the Commission’s 

Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), and Public Util. Dist. No. 1 

of Snohomish Cty v. FERC, 272 F.3d 607 (D.C. Cir. 2001). 

81 Exelon (citing New York v. FERC, 535 U.S. 1 (2002)), Transmission Access 

82 EarthJustice (citing Louisiana Pub. Serv. Comm’n v. FERC, 551 F.3d 1042, 

1045 (D.C. Cir. 2008)). 

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 (D.C. Cir. 1979) (Central Iowa). 
Docket No. RM10-23-000 - 74 -

to require modifications 

h 

he 

gulatory 

of 

e 

 

authority under FPA section 206 does not include the authority 

to an otherwise just and reasonable tariff or jurisdictional agreement simply because the 

Commission has concluded that alternative terms and conditions would better promote 

the interconnection and coordination of transmission facilities. 

90. Several commenters state that the Commission’s statutory authority is limited wit

respect to transmission siting decisions.85 North Carolina Agencies assert that, with t

exception of the Commission’s limited backstop authority under FPA section 216, 

transmission planning and expansion fall strictly within the purview of state re

agencies and the Proposed Rule takes into account neither the Commission’s lack 

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 

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 th

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 

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. 

87 E.g., Ad Hoc Coalition of Southeastern Utilities; National Rural Electric Coops; 

Transmission Access Policy Study Group; and APPA. 
Docket No. RM10-23-000 - 75 -

ing 

 inconsistent with section 217, which 

d 

ith 

vice obligations. 

disregard the needs of renewable power producers or other generators. 

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-serv

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

they state recognizes the primacy of a franchised utility’s obligation to do what is neede

to fulfill its obligation to service, including the implementation of state-authorized plans 

for transmission construction.89 

92. In response, ITC Companies contend that the Proposed Rule is compatible w

section 217 regarding the needs of load-serving entities to fulfill their ser

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 

 88 Additionally, National Rural Electric Coops request that the Commission to 

confirm that transmission planning, even with any reforms the Commission adopts in this 

rulema

sion Access Policy Study Group makes a similar request. 

ublic 

king, will continue to be driven in the first instance by the needs of load-serving 

entities. Transmis

89 E.g., Edison Electric Institute; Large Public Power Council; Nebraska P

Power; and Xcel. 
Docket No. RM10-23-000 - 76 -

ider 

 

on 

. FERC,

93 where the court held that the Commission was not empowered to remove 

mpanies 

93. Some commenters argue that the Commission lacks statutory authority to cons

broad public policies.90 Several commenters cite to NAACP v. FPC91 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 secti

206 authority is not unbounded, citing to California Independent System Operator Corp.

v

members of CAISO’s board of directors under section 206. Further, PSEG Co

argue that there is no evidence to support the Commission’s claims of undue 

 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 (D.C. Cir. 2004) (CAISO v. FERC). 
Docket No. RM10-23-000 - 77 -

g 

 on it, 

ans, or in what manner such policies should be reflected; and (3) what rate 

echanism the Commission would employ to allocate costs incurred by nonincumbent 

 

discrimination under section 206. 

94. Some commenters state that the Commission has not provided enough reasonin

or adequate detail for the Proposed Rule so that parties can comment meaningfully

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 pl

m

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 (D.C. Cir. 1988), Connecticut Light and 

Power Co. v. NRC, 673 F.2d 525, 530 (D.C. Cir. 1982)); Large Public Power Council; 

Salt River Project Comments (citing United Mine Workers or America v. MSHA, 407 

F.3d 1250, 1259 (D.C. Cir. 2005)). 

95 E.g., Large Public Power Council and Nebraska Public Power District. 
Docket No. RM10-23-000 - 78 -

l 

ion’s 

] 

ria, qualifies as being prudently 

he 

PA 

g 

d 

e 

 

95. In addition, Electricity Consumers Resource Council and the Associated Industria

Groups argue that the Proposed Rule may represent a departure from the Commiss

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 crite

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 t

Due Process Clause’s “fair notice” requirement. 

96. Indianapolis Power & Light questions whether the Commission has satisfied F

section 206 requirements, arguing that the Commission has not yet found that existin

transmission planning (and cost allocation) provisions are unjust and unreasonable an

that it has not “fixed” the rate or practice that it finds to be unjust and unreasonable.97

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 th

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 

96 18 CFR 35.35(i)(ii). 

97 Indianapolis Power & Light (citing Electrical Dist. No. 1 v. FERC, 774 F.2d 

490, 492-93 (D.C. Cir. 1985)). 
Docket No. RM10-23-000 - 79 -

1 of the 

City 

ue 

lic power systems in transmission planning and cost 

nd 

 them specified or unanticipated liability; 

and/or (2) ma r interregional transmission 

st 

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 14

Internal Revenue Code of 1986, or any successor statute or regulation.” Large Public 

Power Council makes a similar comment. In its reply comments, APPA states that 

of Los Angeles Department of Water and Power raises a practical and legal iss

regarding the participation of pub

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 a

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

y include an obligation to defer to regional o

plans that could, in Nebraska Public Power District’s judgment, interfere with what mu

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 
Docket No. RM10-23-000 - 80 -

e 

e 

t 

e 

l 

ost 

r 

ons that are just and reasonable and not unduly 

n here. 

 

reforms on transmission planning in this Final Rule. These reforms are intended to 

correct deficiencies in transmission planning and cost allocation processes so that th

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 w

explained in Order No. 890, we found that the existing pro forma OATT was insufficien

to eliminate opportunities for undue discrimination, including such opportunities in th

context of transmission planning. We conclude that the reforms adopted in this Fina

Rule are necessary to address remaining deficiencies in transmission planning and c

allocation processes so that the transmission grid can better support wholesale powe

markets and thereby ensure that Commission-jurisdictional transmission services are 

provided at rates, terms and conditi

98

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 upo

98 See, e.g., Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 422. 
Docket No. RM10-23-000 - 81 -

100. We dis pting the 

transmission 202(a) reads, in 

relevant part, 

hout the United States with the greatest possible 

economy and with regard to the proper utilization and 

empowered and directed to divide the country into regional 

facilities for the generation, transmission, and sale of electric 

terconnection and coordination, i.e., the coordinated 

ng 

oes not 

s, the Commission is in no way 

tion 

202(a) refers to the coordinated operation of facilities. 

 

agree that section 202(a) of the FPA precludes us from ado

planning reforms contained in this Final Rule. Section 

as follows: 

For the purpose of assuring an abundant supply of electric 

energy throug

conservation of natural resources, the Commission is 

districts for the voluntary interconnection and coordination of 

energy. . . .99

Section 202(a) requires that the in

operation, of facilities be voluntary. That section does not mention planning, and nothi

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 d

create any obligations to interconnect or operate in a certain way. Thus, when 

establishing transmission planning process requirement

mandating or otherwise impinging upon matters that section 202(a) leaves to the 

voluntary action of public utility transmission providers. As we discuss herein, sec

 

99 16 U.S.C. 824(a). 
Docket No. RM10-23-000 - 82 -

central dispatch.”101 The court held that given 

vant to 

er 

cific 

 

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 

“the expressly voluntary nature of coordination under section 202(a),” the Commission 

was not authorized to grant that request.102

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 rele

the problem at issue in Central Iowa because the operation of the system through pow

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 spe

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 

100 E.g., ColumbiaGrid; Sacramento Municipal Utility District; and California ISO. 

101 Central Iowa, 606 F. 2d 1156 at 1166. 

102 Id. at 1168. 
Docket No. RM10-23-000 - 83 -

ardless of the nature of the 

lead utilities to engage voluntarily in 

power plannin so.”103 The 

language from

 to cooperate with the commission and with 

each other in bringing about the economies which can alone 

been advocated by the most able and progressive thinkers on 

to address the transmission planning process that is the subject of this proceeding. There 

 

general principles within the transmission planning process reg

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 

g arrangements, and it was not willing to mandate that they do

 the legislative history is as follows: 

The committee is confident that enlightened self-interest will 

lead the utilities

be secured through the planned coordination which has long 

this subject.104

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 

 

103 Id. 

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). 
Docket No. RM10-23-000 - 84 -

ss that is 

at 

s for 

this 

hat occur before the operational activities that are the underlying 

 mandate 

 

is thus no basis to resort to legislative 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 proce

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 th

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 proces

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, 

Final Rule deals with the planning process for transmission facilities, a separate and 

distinct set of activities t

focus of section 202(a). 

106. Similarly, section 202(a) has no bearing on whether the Commission can

 (1992) 

(“[I]n interpreting a statute a court should always turn first to one, cardinal canon before 

105 See, e.g., Connecticut Nat'l Bank v. Germain, 503 U.S. 249, 253-54

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)). 
Docket No. RM10-23-000 - 85 -

quirement in section 

ng, 

 of 

ed 

ial 

ce planning, or authority over such transmission facilities. For 

108. We disagree with the commenters who argue that this Final Rule is inconsistent 

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 re

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 siti

permitting, and construction. However, nothing in this Final Rule involves an exercise

siting, permitting, and construction authority. The transmission planning and cost 

allocation requirements of this Final Rule, like those of Order No. 890, are associat

with the processes used to identify and evaluate transmission system needs and potent

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 resour

this reason, we see no reason why this Final Rule should create conflicts between state 

and federal requirements. 
Docket No. RM10-23-000 - 86 -

A.106 

 we 

ell 

 

 in a 

pproach can address the needs of load-serving entities in 

with or precluded by, or legally deficient for failing to rely on, section 217 of the FP

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,

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 w

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

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 a

 

th

106 Section 217(b)(4) of the FPA specifies that: “The Commission shall exercise 

g 

and expansion of transmission facilities to meet the reasonable needs of load-serving 

e authority of the Commission under this Act in a manner that facilitates the plannin

entities to satisfy the service obligations of the load-serving entities, and enables loadserving 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). 
Docket No. RM10-23-000 - 87 -

ent of 

n 

e considered for that reason. Such requirements may modify the need for and 

e 

cess and the resulting transmission plans would be deficient if 

that 

er 

 

the Southeast and elsewhere. 

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 fulfillm

those requirements. Instead, the Commission is acknowledging that the requirements i

question are facts that may affect the need for transmission services and these needs must 

b

configuration of prospective transmission facility development and construction. Th

transmission planning pro

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 

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 und

those statutes as creating “a broad license to promote general public welfare.”107 

107 NAACP v. FERC, 425 U.S. 662 at 668. 
Docket No. RM10-23-000 - 88 -

st 

merely because the statutes pertain to matters affected with a public interest.108 

eeds 

anning 

e considered 

rms 

ven by Public Policy 

 

Specifically, the Court found that the Commission’s duty to promote the public intere

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 

The Commission is doing nothing analogous when specifying that transmission n

driven by Public Policy Requirements be taken into account in the transmission pl

process. 

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 b

in individual local and regional transmission planning processes.109 This further confi

that, in requiring that the transmission planning process include the evaluation of 

potential solutions to identified transmission needs dri

108 Id. at 670. 

109 See infra section III.A.4. 
Docket No. RM10-23-000 - 89 -

e 

er 

se 

 facilities 

 

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. 

112. Other commenters cite CAISO v. FERC for the proposition that the Proposed Rul

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 und

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 sen

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

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 

110 CAISO v. FERC, 372 F.3d 395 at 403. 

111 Id.
Docket No. RM10-23-000 - 90 -

nning process are therefore squarely within our 

eet 

b)(3) of the 

ose 

e held 

precise 

n 

 disputes arise as to the construction of 

 

governing the transmission pla

jurisdiction, whether the particular transmission facilities in question are planned to m

reliability needs, address economic considerations, or meet transmission needs driven by

a Public Policy Requirement. 

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(

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 purp

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 hav

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 

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 i

future orders by the Commission should

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)). 
Docket No. RM10-23-000 - 91 -

d 

As 

f the 

e 

 

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. 

114. We disagree with Southern Companies’ argument that the Proposed Rule violate

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. 

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 o

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 th

applicant had not satisfied its interpretation of minority control as de facto or “actual” 

115 211 F.3d 618, 628 (D.C. Cir. 2000) (Trinity Broadcasting). 
Docket No. RM10-23-000 - 92 -

lve a 

ssue 

ion 

violating it?”116 A rulemaking such as the present 

mption 

t 

ed 

 

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 invo

rulemaking proceeding, as is the case here, but rather an adjudication that raised the i

of “[w]hat constitutes sufficiently fair notice of an agency’s interpretation of a regulat

to justify punishing someone for 

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. 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 presu

that a transmission project that has received construction approvals from relevant state 

regulatory agencies satisfies Order No. 679’s117 requirement that the transmission projec

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-bas

116 Trinity Broadcasting, 211 F.3d 618 at 619. 

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). 
Docket No. RM10-23-000 - 93 -

t 

ion deals with matters that 

has 

ses are 

ic 

ing 

fied 

al 

rate treatments for investment in transmission infrastructure. The Proposed Rule does no

“represent a departure” from this provision because the provis

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. 

116. With respect to Indianapolis Power & Light’s assertion that the Commission 

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 proces

unjust and unreasonable or unduly discriminatory or preferential. Specifically, we 

conclude that the record shows that, for the pro forma OATT (and, consequently, publ

utility transmission providers’ OATTs) to be just and reasonable and not unduly 

discriminatory or preferential, it must be revised in the context of transmission plann

to include the requirement that regional transmission planning processes result in the 

production of a regional transmission plan using a process that satisfies the speci

Order No. 890 transmission planning 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 leg
Docket No. RM10-23-000 - 94 -

is 

 nonjurisd join a regional 

transmission planni choose to do so, they may advocate 

issues associated with public power participation in the regional transmission planning 

processes, we make the following observations. First, as discussed in the section of th

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,

ictional entities, unlike public utilities, may choose whether to 

ng process and, to the extent they

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

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 transmiss

planning principle. More specifically, the Commission would require that each region

transmission planning process consider and evaluate transmission facilities and oth

 provider 

ion 

al 

er 

non-transmission solutions that may be proposed and develop a regional transmission 
Docket No. RM10-23-000 - 95 -

s the transmission facilities that more efficiently or cost-effectively 

r 

 be 

ich 

gh 

merchant transm not be prohibited from participating—and, 

.

120

plan that identifie

meet the needs of public utility transmission providers, their customers and other 

stakeholders.118

119. The Proposed Rule also would provide that a merchant transmission develope

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

located.119 To reiterate, merchant transmission projects are defined as those for wh

the costs of constructing the proposed transmission facilities will be recovered throu

negotiated rates instead of cost-based rates. The Proposed Rule states that such a 

ission developer would 

indeed, is encouraged to participate—in the regional transmission planning process

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 

 118 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 51. 

119 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at n.23. 

120 Id. P 99. 
Docket No. RM10-23-000 - 96 -

orts 

 in 

ent 

e 

port 

dopt 

complies with the Order No. 890 transmission planning principles. NextEra supp

the Commission’s proposal provided that a regional transmission planning process 

produces a regional transmission plan with identified transmission facilities to be built

the near-term. Iberdrola Renewables contends that the current piecemeal, generationdriven 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 differ

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 renewabl

121

resources, and suggests that the Commission consider eliminating this distinction. 

121. Most commenters addressing the proposed transmission planning reforms sup

the Commission’s proposal to require public utility transmission providers to a

several of the Order No. 890 transmission planning principles for the regional 

 121 E.g., Anabaric and PowerBridge; AWEA; City and County of San Francisco; 

ss Society and Western Resource Advocates; and Wisconsin Electric 

Power

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; Wilderne

 Company. 
Docket No. RM10-23-000 - 97 -

t 

e to 

4

 

stems state that transmission owners must comply 

ing 

 the 

 

transmission planning process.122 Some commenters ask the Commission to clarify tha

the existing Order No. 890 transmission planning principles would remain applicabl

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.12

Transmission Dependent Utility Sy

with Order No. 890 transmission planning principles even if they are planning local 

transmission projects in an RTO. 

122. Several supporting the Proposed Rule stress that fair process, transparency, and 

robust stakeholder participation are important components of the transmission plann

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

Commission to require that historical and real-time data be made available to interested 

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. 

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. 
Docket No. RM10-23-000 - 98 -

velopment. 

the 

 all 

owerBridge suggest consideration of 

luding 

s 

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 de

Independent Energy Producers Association urges the Commission to emphasize that 

openness, transparency, and inclusiveness criteria of Order No. 890 should apply to

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 P

internal procedures to treat transmission project information as confidential, inc

protections to ensure that transmission projects that are not selected in the regional 

transmission plan will remain confidential. 

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 i

needed to ensure that the dispute resolution process is useful, suggesting that use of
Docket No. RM10-23-000 - 99 -

on Access Policy Study Group suggests that 

cess to 

rify 

p, through 

 

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. Transmissi

the Commission establish a backstop dispute resolution or expedited complaint pro

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 cla

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 develo

their stakeholder processes and in consultation with state regulatory commissions, 

126 E.g., Kansas City Power & Light and KCP&L Greater Missouri; Edison 

Electric Institute; and WIRES. 
Docket No. RM10-23-000 - 100 -

posed 

ld not modify or interfere with progress being made 

ke 

 providers 

 

strategies and metrics to achieve region-appropriate compliance with the Final Rule. 

125. Many entities that support the Proposed Rule believe that the regional 

transmission planning process in which they participate already satisfies the pro

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 shou

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. 

126. On the other hand, Iberdrola Renewables states that the Commission should ma

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

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. 
Docket No. RM10-23-000 - 101 -

e mechanism for sharing costs consistent 

ing 

ower & 

m 

esses 

nce 

eet 

public policy requirements established by state or federal laws or regulations. 

128. Se nd RTOs 

in the region have a governance structure for undertaking the regional and interregional 

transmission planning obligations and a workabl

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 plann

region” as it relates to the requirements of the Proposed Rule.128 Indianapolis P

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 fro

the Commission for its members to determine if current transmission planning proc

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 complia

filings, the scope of the self-selected planning regions does not create inadvertent 

planning seams that inhibit the development of transmission projects needed to m

veral commenters urge the Commission to clarify that existing ISOs a

 128 E.g., NextEra; Clean Line; California Municipal Utilities; American 

Transmission; and Arizona Corporation Commission. 
Docket No. RM10-23-000 - 102 -

g 

m a 

nning 

arket 

” 

o 

 

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 developin

and running energy markets, it might be difficult for RTOs to plan transmission fro

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 pla

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 m

could form a single region for transmission planning and cost allocation purposes. 

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 t

form transmission regional planning areas with each other or participate in regional 

Indianapolis Power & Light; and NextEra. 

129 E.g., ISO/RTO Council; California ISO; MISO Transmission Owners; 
Docket No. RM10-23-000 - 103 -

to 

 as the 

e determined by factors such as the level of 

 

transmission planning with an adjacent RTO. Some commenters ask the Commission 

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

smaller of a state or one of NERC’s Regional Entities. NextEra suggests that, in nonRTO areas, geographic scope should b

interconnections between utilities, power flows, boundaries of existing NERC regions, 

and historical coordination practices. 

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 

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

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. 
Docket No. RM10-23-000 - 104 -

th 

arolina 

nd 

omes part of a multistate region, then it is unclear what role the Florida PSC 

h 

process.133 26 Public Interest Organizations and Dayton Power and Light assert that 

that the South Carolina Regional Transmission Planning (SCRTP) process complies wi

Order No. 890, and as such is a “regional transmission planning process,” South C

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, a

Florida bec

would retain, if any, over the transmission planning and cost allocation processes in 

Florida.132

131. Many commenters recommend that transmission providers should evaluate bot

transmission and non-transmission solutions during the regional transmission planning 

 132 Additionally, Florida PSC and Commissioner Skop express concern about th

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

e 

-based utility. Florida PSC and Commissioner Skop ask the 

Comm

aha Public 

(continued...) 

ission to take the lack of Florida-specific points of view into account when it 

considers its proposals. 

133 E.g., AWEA; California Commissions; Wisconsin Electric; Om
Docket No. RM10-23-000 - 105 -

eeded to 

f 

 of 

y 

 so 

ission suggest that resource planning 

in 

n 

 

consideration of non-transmission solutions with all other resource options is n

determine the most cost-effective way to meet grid needs. 26 Public Interest 

Organizations ask the Commission to establish minimum requirements for: what types o

resources should be assessed; how assessments should be conducted; and what types

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 efficienc

on baseline forecasts. MISO supports the consideration of non-traditional solutions

long as this process does not interfere with state authority over integrated resource 

planning. Western Grid Group and Pattern Transm

and transmission planning should be reintegrated. 

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 

the Southeast. It explains that non-transmission solutions are typically considered i

integrated resource planning and request for proposal processes during the current 

“bottom-up” transmission planning process. It states that including a generation resource

Environmental NGOs; NRG; Vermont Electric; EarthJustice; and SPP. 

Power District; Dayton Power and Light; Eastern Environmental Law Center; 
Docket No. RM10-23-000 - 106 -

y a right 

f Southeastern Utilities, in responding to comments by Western Grid 

g 

n 

tions 

g processes. 

t 

as an alternative during the regional transmission planning process would conve

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 o

Group and Pattern Transmission, argues that transmission planning and resource plannin

in the Southeast have not diverged and that further reforms are unnecessary. Souther

Companies agree. 

133. MISO Transmission Owners ask the Commission to provide additional guidance

regarding the meaning of “non-transmission solutions” and which of these solu

transmission providers are required to include in their transmission plannin

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 consisten
Docket No. RM10-23-000 - 107 -

t 

 card” 

ts 

ere 

ion Access Policy Study Group states that the Final Rule should 

ent 

 facility is likely 

cess 

transmission planning cycles, stakeholder procedures, action timelines, and criteria for 

evaluating project proposals. Transmission Access Policy Study Group also suggests tha

the Commission require regular updating of regional transmission plans, and require

jurisdictional transmission providers to file, for public comment, a “planning report

identifying the projects proposed during the transmission planning process, the projec

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 w

rejected. Transmiss

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. 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 complem

the long-term plan). AEP argues that the useful life of any transmission

to exceed 40 years and, consequently, the most efficient transmission planning pro

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. 
Docket No. RM10-23-000 - 108 -

lly 

tely 

s to 

. 

his 

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 economica

supportable results in terms of which transmission facilities are built and who ultima

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 solution

congestion for all transmission customers and load-serving entities across the region

Transmission Dependent Utility Systems recommend that the Commission clarify t

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
Docket No. RM10-23-000 - 109 -

uld 

ext of the 

 proceedings. Additionally, it states that all proposed transmission 

blic 

mission 

ents 

r 

a single set of procedures and that the transmission planning process need not serve every

planning purpose. Arizona Corporation Commission seeks clarification on who wo

determine whether a transmission project is a reliability project within the cont

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

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 pu

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 trans

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 requirem

in its Final Rule: regional and interregional transmission planning processes should be 

sufficiently flexible to accommodate the real-time requirements of a transmission owne
Docket No. RM10-23-000 - 110 -

ad customers; and the transmission planning process should 

ny 

ves 

tly 

n 

 an existing plan should not be subject to bumping in a 

 the 

ow 

t, 

se 

and operator’s native lo

recognize that the obligation to serve still exists in a number of jurisdictions and that a

regional plan or process needs to allow for the fact that it is that obligation that dri

transmission planning. 

139. Others are concerned about the applicability of the Proposed Rule to curren

pending transmission projects. Atlantic Wind Connection seeks clarification that 

sponsored projects with a pending request for inclusion in a regional transmission pla

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

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

transmission planning process. 

140. Some commenters ask the Commission to establish a funding mechanism to all

interested parties that are not market participants to fully participate in the regional 

transmission planning process. 26 Public Interest Organizations assert that an essential 

element of robust and broadly supported regional planning is the participation of nonmarket participants and that this requires ongoing provider assistance. They state tha

because non-market stakeholders have neither the financial resources nor staff experti
Docket No. RM10-23-000 - 111 -

le 

s 

ul 

regional transmission planning process, arguing that non-

 Group, 

 in 

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 reasonab

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 offer

suggestions as to how a funding mechanism could be implemented. Additionally, 

EarthJustice and Environmental Groups urge the Commission to encourage meaningf

public participation in the 

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

support a requirement that there be an obligation to construct projects identified

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’ 
Docket No. RM10-23-000 - 112 -

on 

 (1) 

transmission providers (or others) to build the transmission 

 others 

m. 

 Large Public Power Council points 

obligation to build. It suggests requiring development of a process to obtain constructi

commitments, with accountability for those commitments. Transmission Access Policy 

Study Group states that the Final Rule should include a timely post-plan process for:

securing commitments by 

facilities identified in the regional plan; and (2) holding transmission providers and

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 the

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.

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 
Docket No. RM10-23-000 - 113 -

 if 

are not 

pports 

of 

ission developers that did not participate in the regional transmission planning 

n 

grid. 

transmission developers to participate 

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,

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 

required to participate if they do not wish to do so. New York ISO states that it su

the proposal to not require transmission developers that do not seek to take advantage 

a regional transmission cost allocation mechanism to participate in the regional 

transmission planning process. LS Power states that it understands that merchant 

transm

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 transmissio

144. However, others support requiring merchant 

 134 E.g., Allegheny Energy Companies; Champlain Hudson; Clean Line; H-P 

Energy Resources; LS Power; and New York ISO. 
Docket No. RM10-23-000 - 114 -

e 

us 

n 

 is 

d ad hoc

t 

e significant reliability, operational, and 

in the regional transmission planning process.135 APPA states that the reasons for 

engaging in coordinated planning extend well beyond eligibility for inclusion in th

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 vario

transmission alternatives to ascertain the impact of existing and proposed projects o

other regional transmission facilities. Transmission Access Policy Study Group

concerned that exempting merchant transmission developers from the regional 

transmission planning process could cause the mandatory process to plan aroun

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 tha

viable merchant transmission projects must be included in the regional transmission 

planning process, because such projects may hav

economic impacts on the transmission system. 

 

Hampshire Electric; MISO Transmission Owners; National Rural Electric Coops; 

Tier Transmission Group; Ohio Consumers Counsel and West Virginia Consumer 

135 E.g., APPA; Large Public Power Council; Massachusetts Municipal and New 

Nebraska Public Power District; New England States Committee on Electricity; Northern 

Advocate Division; Old Dominion Electric Cooperative; Six Cities; Transmission 

Agency of Northern California; Transmission Access Policy Study Group; and 

Transmission Dependent Utility Systems. 
Docket No. RM10-23-000 - 115 -

t 

on 

hat 

hould be strongly encouraged to the extent feasible with 

regard to planni mments, Powerex notes that 

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 tha

seek cost recovery via rolled-in rates should participate fully in the regional transmissi

planning process but believes that participation by merchant transmission developers t

do not seek such cost recovery s

ng, but not to cost recovery. In its reply co

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 part

in a regional transmission planning process that produces a regional transmission pl

and that complies with the transmission planning principles of Order No. 890 identified 

below. We determine that such t

icipate 

an 

ransmission planning will expand opportunities for more 

 and 

t unduly 

discriminatory or preferential. 

147. Order No. 890 required public utility transm coordinate at the 

efficient and cost-effective transmission solutions for public utility transmission 

providers and stakeholders. This will, in turn, help ensure that the rates, terms

conditions of Commission-jurisdictional services are just and reasonable and no

ission providers to 
Docket No. RM10-23-000 - 116 -

der 

o 

ocal 

 that 

ional 

y 

ngle transmission plan for the region that reflects their 

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 Or

No. 890 permit regional transmission planning processes to be used as a forum merely t

confirm the simultaneous feasibility of transmission facilities contained in their l

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

could reduce congestion or integrate new resources or loads on an aggregated or reg

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 b

stakeholders. There is also no obligation for public utility transmission providers within 

the region to develop a si

determination of the set of transmission facilities that more efficiently or cost-effectively

 136 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 523. 

137 Id. 
Docket No. RM10-23-000 - 117 -

s, as 

sultation 

r 

ransmission facilities in one or more local transmission plans, then 

the transmission facilities associated with that more efficient or cost-effective 

meet the region’s needs. 

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 Requirement

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 con

with stakeholders, determine that an alternative transmission solution is more efficient o

cost-effective than t

transmission solution can be selected in the regional transmission plan for purposes of 
Docket No. RM10-23-000 - 118 -

dy 

on 

ify in 

, 

ntly 

cost allocation.138 

149. We acknowledge that public utility transmission providers in some regions alrea

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 transmissi

providers that, as some commenters note, are not currently undertaking sufficient 

transmission planning activities at the regional level. We decline, however, to spec

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 efficie

 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. 

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. 
Docket No. RM10-23-000 - 119 -

ance, using as our 

, 

ave 

egional 

ssed 

 

or cost-effectively. We will review such mechanisms on compli

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

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 h

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 r

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 addre

in a more efficient or cost-effective manner. Greater access to information and 

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. 
Docket No. RM10-23-000 - 120 -

ortant in light of our reforms that require that each public 

mission 

2) 

 public 

requirements with respect to the process used to produce a regional transmission plan. 

anning 

 

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 imp

utility transmission provider have a cost allocation method or methods for trans

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; (

openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute 

resolution; and (7) economic planning.141 In Order No. 890, we required that each

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 

We conclude that it is appropriate to do so to ensure that regional transmission pl

 

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 facilitie

selected in a regional transmission plan for purposes of cost allocation elsewhere in this 

Final Rule. 

s 
Docket No. RM10-23-000 - 121 -

ublic 

smission planning processes, consistent with these 

nsmission 

gional 

n projects could satisfy local and regional 

ansmission 

 

processes are coordinated, open, and transparent.142 Accordingly, we require p

utility transmission providers to develop, in consultation with stakeholders,143

enhancements to their regional tran

transmission planning principles. 

152. We conclude that, without the requirement to meet the Order No. 890 tra

planning principles, a regional transmission planning process will not have the 

information needed to assess the impact of proposed transmission projects on the re

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 transmissio

needs more efficiently or cost-effectively. 

153. A number of commenters specifically address the treatment of non-tr

alternatives in the regional transmission planning process. Order No. 890’s 

r to 

comply with the requirements of Order No. 890 may require only modest changes to fully 

comply

n 

. 890. See, e.g., Southern Co. Svcs., Inc., 127 FERC ¶ 61,282, at P 14-16 

(2009)

142 Although the explicit requirement for a public utility transmission provide

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 

 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 i

Order No

. 
Docket No. RM10-23-000 - 122 -

ty 

opted 

in Order No. 890, the 

cal 

fore, when 

 

comparability transmission planning principle requires that the interests of public utili

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 ad

here do not address or dictate which transmission facilities should be either in the 

regional transmission plan or actually constructed.145 As also noted 

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 

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 lo

resource planning and that transmission often is planned as a last resort. There

local transmission plans are brought together in a regional transmission planning process

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. 
Docket No. RM10-23-000 - 123 -

 of 

etter meet the needs of the region, the same could be true for 

ning 

ay 

r 

-

st 

as well as in orders addressing related compliance filings, we have provided guidance 

regardi

to determine if a regional solution can better meet the needs of the region than the sum

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 b

regional non-transmission alternatives. However, the regional transmission plan

process is not the vehicle by which integrated resource planning is conducted; that m

be a separate obligation imposed on many public utility transmission providers and unde

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 again

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,

ng the requirements of the Order No. 890 comparability transmission planning 

 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.” 
Docket No. RM10-23-000 - 124 -

rs are required to identify 

90 

e of 

principle.148 Specifically, public utility transmission provide

how they will evaluate and select from competing solutions and resources such that all 

types of resources are considered on a comparable basis.149

156. We disagree with concerns raised by certain commenters that the Order No. 8

comparability transmission planning principle may interfere with integrated resource

planning.150 As discussed above, this Final Rule in no way involves an exercis

authority over those specific substantive matters traditionally reserved to the states, 

including integrated resource planning, or authority over siting, permitting, or 

 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

 

 at P 15, n.25; New York Indep. Sys. Operator, Inc., 129 FERC ¶ 61,044 at P 35, 

n.26. 

outheastern Utilities. 

 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

150 E.g., Ad Hoc Coalition of S
Docket No. RM10-23-000 - 125 -

o. 

n planning processes that provide for the evaluation of proposed solutions on 

der 

manner in 

n 

construction of transmission solutions.151 In addition, on compliance with Order N

890, each public utility transmission provider already has put into place regional 

transmissio

a comparable basis.152 In this Final Rule, the Commission is applying to regional 

transmission planning the comparability transmission planning principle stated in Or

Nos. 890 and 890-A.153 

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 

which public utility transmission providers must fulfill the requirements of complying 

with the regional transmission planning principles. We allow public utility transmissio

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

 151 See supra section III.A.2. 

152 See, e.g., Entergy OATT, Attachment K at § 3.12; Florida Power and Light 

OATT, Appendix 1 to Attachment K, §§ H and I; ISO New England OATT, Attachment 

K at § 4.2; Puget Sound Energy OATT, Attachment K at § 2; SPP OATT, Attachment O 

at § III.8. 

153 See, e.g., supra notes 148-49. 
Docket No. RM10-23-000 - 126 -

r 

 reject Anbaric 

roject 

cture 

ent 

al 

ity transmission provider 

eeds 

detail consistent planning cycles, impose stakeholder procedures, establish timelines fo

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

and PowerBridge’s suggestion that procedures be developed to treat transmission p

information as confidential, outside of the Commission’s Critical Energy Infrastru

Information (CEII) requirements and regulations, as this runs counter to the requirem

that regional transmission planning processes be open and transparent. 

158. Additionally, we note that a public utility transmission provider’s region

transmission planning process may utilize a “top down” approach, a “bottom up” 

approach, or some other approach so long as the public util

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 n

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 
Docket No. RM10-23-000 - 127 -

at 

d to 

ansmission plans, including posting appropriate status information on its website, 

n 

al 

te 

te 

 

requested by some commenters. The package of transmission planning and cost 

allocation reforms adopted in this Final Rule is designed to increase the likelihood th

transmission facilities in regional transmission plans will move from the planning stage to 

construction. In addition, public utility transmission providers already are require

make available information regarding the status of transmission upgrades identified in 

tr

consistent with the Commission’s CEII requirements and regulations.154 To the extent a

entity has undertaken a commitment to build a transmission facility in a region

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 adequa

without placing further obligations on public utility transmission providers. 

160. The Commission also acknowledges the importance of identifying the appropria

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 

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. 
Docket No. RM10-23-000 - 128 -

the 

ticular 

lanning region. We believe that these existing regional processes should provide some 

ses of complying with this Final Rule. However, to the extent 

y 

0 or 

 

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 

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 par

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 

p

guidance to public utility transmission providers in formulating transmission planning 

regions for purpo

necessary, we clarify that an individual public utility transmission provider cannot, b

itself, satisfy the regional transmission planning requirements of either Order No. 89

this Final Rule. 

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 

156 See, e.g., Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 527. 
Docket No. RM10-23-000 - 129 -

processes that public utility transmission 

f 

meet 

cilities. 

sting 

 a funding 

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 

seven transmission planning principles, is not intended to appropriate, supplant, or 

impede any local transmission planning

providers undertake. The objective of this Final Rule is to amend the requirements o

Order No. 890 so that regional transmission planning processes not only continue to 

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 fa

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 reque

that the Commission mandate that public utility transmission providers include

mechanism to facilitate the participation of in the regional transmission planning process 
Docket No. RM10-23-000 - 130 -

ncies 

se 

her 

ote that, to 

ipation of state consumer advocates or other 

le 

ject 

developer to participate in a regional transmission planning process for purposes of 

 

associated with participation in the transmission planning process. There, the 

Commission acknowledged concerns regarding “how state regulators and other age

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 tho

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 ot

stakeholder interests, as requested by certain commenters. However, we also n

the extent that public utility transmission providers choose to include a funding 

mechanism to facilitate the partic

stakeholders in the regional transmission planning process, nothing in this Final Ru

precludes them from doing so. 

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 pro

and constructing the proposed transmission facilities, it is unnecessary to require such a 

157 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at n.339 and P 586. 

158 Id. n.339. 
Docket No. RM10-23-000 - 131 -

or 

st 

ne system can affect 

pacts 

to 

 

identifying the beneficiaries of its transmission project that would otherwise be the basis 

for securing eligibility to use a regional cost allocation method or methods.159 However, 

we acknowledge the concern of some commenters that a transmission project proposed 

developed by a merchant transmission developer has broader impacts than simply co

recovery. Because all electric systems within an integrated network are electrically 

connected, the addition or cancellation of a transmission project in o

the nature of power flows within one system or on other systems. 

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 im

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 

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 

159 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 99. 
Docket No. RM10-23-000 - 132 -

or 

ge 

rk upgrades 

caused by the interconnection of its project with the transmission grid.160 

subject to the evaluation and selection processes that apply to transmission facilities f

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 encoura

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 netwo

 160 We note that, to the extent a merchant transmission developer becomes subje

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 regis

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 

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 o

reh’g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC Stats. & Regs. ¶ 31,21

(2006). Concerns regarding when NERC re

ct 

ter 

of 

n 

2 

gistration would be triggered should be 

addressed in a NERC registration process. 
Docket No. RM10-23-000 - 133 -

4. Consideration of Transmission Needs Driven by Public Policy 

Requirements161

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 

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

162 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 64. 

163 Id.
Docket No. RM10-23-000 - 134 -

 

Rule would require that the public utility transmission provider must make that 

demonstration in its compliance filing.164

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. 

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 

164 Id. P 66. 

165 Id. P 65. 
Docket No. RM10-23-000 - 135 -

disruptions in long-term transmission planning.166

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, 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 

 166 Id. P 70. 

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. 
Docket No. RM10-23-000 - 136 -

 

transmission planning processes, a number seek clarification or request that the 

Commission provide additional guidance. 

170. With regard to what constitutes a public policy requirement, some commenters 

seek to limit the definition to state and federal laws and regulations168 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. 
Docket No. RM10-23-000 - 137 -

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 
Docket No. RM10-23-000 - 138 -

 

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. 

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 

169 E.g., Connecticut & Rhode Island Commissions; Massachusetts Departments; 

PUC of Nevada; and New England States Committee on Electricity. 
Docket No. RM10-23-000 - 139 -

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 
Docket No. RM10-23-000 - 140 -

 

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 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 

170 E.g., New Jersey Division of Rate Counsel and Integrys. 
Docket No. RM10-23-000 - 141 -

 

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. 

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. 26 

Public Interest Organizations state that comparable consideration of all resource options 

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. 
Docket No. RM10-23-000 - 142 -

 

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. 

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 

173 E.g., Iberdrola Renewables. 
Docket No. RM10-23-000 - 143 -

 

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. 

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. 

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 

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. 

175 E.g., ISO/RTO Council; ISO New England; PJM; New York ISO; SPP; MISO; 

New York Transmission Owners; NEPOOL; and MISO Transmission Owners. 
Docket No. RM10-23-000 - 144 -

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/loadserving 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. 

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; 
Docket No. RM10-23-000 - 145 -

(5) the full cost of resources must be transparent and considered in the transmission 

planning process, based on 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 
Docket No. RM10-23-000 - 146 -

 

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. 

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 

176 E.g., Pattern Transmission; Transmission Agency of Northern California; and 

Transmission Access Policy Study Group. 
Docket No. RM10-23-000 - 147 -

 

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. 
Docket No. RM10-23-000 - 148 -

 

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 

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. 
Docket No. RM10-23-000 - 149 -

 

compliance filings to remove the language allegedly prohibiting such consideration. 

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

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 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 

180 E.g., NV Energy; Long Island Power Authority; and Bonneville Power. 
Docket No. RM10-23-000 - 150 -

 

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 nondiscriminatory 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 

(continued...) 

181 E.g., PSEG Companies; First Energy Service Company; Ad Hoc Coalition of 
Docket No. RM10-23-000 - 151 -

 

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. 

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 

Southeastern Utilities; National Rural Electric Coops; Southern Companies; Large Public 

Power Council; Nebraska Public Power District; and Long Island Power Authority. 
Docket No. RM10-23-000 - 152 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 153 -

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, 
Docket No. RM10-23-000 - 154 -

 

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 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. 

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 

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. 
Docket No. RM10-23-000 - 155 -

 

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 

184 E.g., City and County of San Francisco; LS Power; New Jersey Division of 

Rate Counsel; and Western Independent Transmission Group. 
Docket No. RM10-23-000 - 156 -

criterion. 

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 
Docket No. RM10-23-000 - 157 -

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 

 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. 
Docket No. RM10-23-000 - 158 -

 

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 

(continued...) 

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 
Docket No. RM10-23-000 - 159 -

 

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 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. 

205. In response to commenters seeking greater clarity as to how transmission needs 

Agency of Northern California; Western Grid Group; and Wind Coalition. 

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. 
Docket No. RM10-23-000 - 160 -

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 
Docket No. RM10-23-000 - 161 -

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 
Docket No. RM10-23-000 - 162 -

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 
Docket No. RM10-23-000 - 163 -

 

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 websites 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 implemented by public utility transmission providers. 

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 

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. 
Docket No. RM10-23-000 - 164 -

 

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 costeffectively. 190 As noted in our discussion of regional transmission planning in section 

(continued...) 

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 
Docket No. RM10-23-000 - 165 -

 

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 costeffective solution to meet local or regional needs.

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 

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. 
Docket No. RM10-23-000 - 166 -

 

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. 

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 

192 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 574. 
Docket No. RM10-23-000 - 167 -

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. 
Docket No. RM10-23-000 - 168 -

 

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 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 

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. 
Docket No. RM10-23-000 - 169 -

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. 

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 
Docket No. RM10-23-000 - 170 -

 

 

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. 

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 

194 See discussion infra section IV. 

195 See discussion infra section IV.E.2. 
Docket No. RM10-23-000 - 171 -

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 
Docket No. RM10-23-000 - 172 -

 

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, 

196 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 66. 
Docket No. RM10-23-000 - 173 -

 

we decline here to prejudge any compliance filings or predetermine whether any public 

utility transmission provider may already be in compliance. 

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. 

224. Hence, we will permit public utility transmission providers to include within their 

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. 
Docket No. RM10-23-000 - 174 -

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 
Docket No. RM10-23-000 - 175 -

 

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 

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 costeffective 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 

199 See Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at n.23. 
Docket No. RM10-23-000 - 176 -

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. 
Docket No. RM10-23-000 - 177 -

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 Notice200 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 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. 

229. Based on the comments received, the Commission determined that if a regional 

 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). 
Docket No. RM10-23-000 - 178 -

 

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. 

230. To address these issues, the Commission proposed to reform provisions in public 

201 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 87-88. 
Docket No. RM10-23-000 - 179 -

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 

 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 ConsumerOwned 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. 
Docket No. RM10-23-000 - 180 -

 

playing field for incumbent and nonincumbent transmission developers.203 

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 

203 E.g., Arizona Corporation Commission; Connecticut & Rhode Island 

Commissions; New England States Committee on Electricity; New Jersey Board; 

Massachusetts Departments; Ohio Consumers Counsel; Pennsylvania PUC; and West 

Virginia Consumer Advocate. 
Docket No. RM10-23-000 - 181 -

 

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 

204 E.g., Eastern Massachusetts Consumer-Owned System; Northern California 

Power Agency; Transmission Agency of Northern California; and Transmission 

Dependent Utility Systems. 
Docket No. RM10-23-000 - 182 -

 

municipal utility participation in transmission ownership on a larger scale.

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 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 

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). 
Docket No. RM10-23-000 - 183 -

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. 

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 
Docket No. RM10-23-000 - 184 -

 

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. 

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 

207 Primary Power cites to Transmission Access Policy Study Group v. FERC, 

225 F.3d 667, 688 (D.C. Cir. 2000). 

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. 
Docket No. RM10-23-000 - 185 -

 

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. 

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 

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

MidAmerican. 
Docket No. RM10-23-000 - 186 -

 

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. 

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 nonincumbent transmission 

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. 
Docket No. RM10-23-000 - 187 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 188 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 189 -

 

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. 

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.

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 

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. 
Docket No. RM10-23-000 - 190 -

 

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. 

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 

215 E.g., Dominion; PSEG Companies; North Dakota & South Dakota 

Commissions; and Oklahoma Gas & Electric Company. 
Docket No. RM10-23-000 - 191 -

 

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 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 

216 E.g., California ISO; Indianapolis Power & Light; Oklahoma Gas & Electric 

Company; and Pacific Gas & Electric. 
Docket No. RM10-23-000 - 192 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 193 -

 

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. 

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. 

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 

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. 
Docket No. RM10-23-000 - 194 -

 

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 

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. 
Docket No. RM10-23-000 - 195 -

 

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. 

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 

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. 

224 E.g., MISO; MISO Transmission Owners; Edison Electric Institute; Alliant 

Energy; MidAmerican; and Indianapolis Power & Light. 
Docket No. RM10-23-000 - 196 -

 

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. 

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 

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). 
Docket No. RM10-23-000 - 197 -

 

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

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 

(continued...) 

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). 

228 E.g., California PUC; Transmission Dependent Utility Systems; SPP; AEP; 
Docket No. RM10-23-000 - 198 -

 

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 timelimited 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 

Iberdrola Renewables; Indianapolis Power & Light; ITC Companies; MidAmerican; 

Oklahoma Gas & Electric; Southern California Edison; Westar; Xcel; CapX2020 

Utilities; and SPP. 
Docket No. RM10-23-000 - 199 -

perpetuate the entry barrier.229

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.

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 

 

(continued...) 

229 E.g,, American Antitrust Institute; Anbaric and PowerBridge; LS Power; 

NextEra; Pattern Transmission; and Western Independent Transmission Group. 

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

231 As explained in more detail in section III.B.3below, 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 
Docket No. RM10-23-000 - 200 -

 

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. 

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 

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 Commissionapproved tariffs or agreements. 

232 Order No. 888, FERC Stats. & Regs. at 31,682; Order No. 890, FERC Stats. 

& Regs. ¶ 31,241 at P 524. 
Docket No. RM10-23-000 - 201 -

 

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 regionwide benefits, as opposed to pursuing transmission expansion on a piecemeal basis.”234

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 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 

233 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 524. 

234 Id.

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. 
Docket No. RM10-23-000 - 202 -

 

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 

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 Commissionjurisdictional 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 

237 See, e.g., Large Public Power Council Initial Comments describing bottom up 

planning. 

238 See, e.g., Entergy OATT, Attachment K at § 3.12; Florida Power and Light 

OATT, Appendix 1 to Attachment K, §§ H and I; ISO New England OATT, Attachment 

K at § 4.2; Puget Sound Energy OATT, Attachment K at § 2; SPP OATT, Attachment O 

at § 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). 
Docket No. RM10-23-000 - 203 -

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 
Docket No. RM10-23-000 - 204 -

 

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. 

240 See definition supra section II.D of this Final Rule. 
Docket No. RM10-23-000 - 205 -

 

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 

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 

241 Similarly, the Commission believes that concerns regarding the costeffectiveness 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. 
Docket No. RM10-23-000 - 206 -

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 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 
Docket No. RM10-23-000 - 207 -

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 
Docket No. RM10-23-000 - 208 -

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 
Docket No. RM10-23-000 - 209 -

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 
Docket No. RM10-23-000 - 210 -

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 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 
Docket No. RM10-23-000 - 211 -

 

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 bulkpower 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. 

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 

242 18 CFR Part 39.2(a) (2011). 
Docket No. RM10-23-000 - 212 -

 

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 

243 Wisconsin Gas Company v. FERC, 770 F.2d 1144, 1158 (D.C. Cir. 1985) 

(citing FCC v. RCA Communications, Inc., 346 U.S. 86, 96 (1953)). 
Docket No. RM10-23-000 - 213 -

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. 

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 

 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). 
Docket No. RM10-23-000 - 214 -

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.” 

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 

 245 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 87-88. 

246 E.g., Iberdrola Renewables; 26 Public Interest Organizations; Exelon; ITC 

Companies; LS Power; Multiparty Commenters; and Primary Power. 
Docket No. RM10-23-000 - 215 -

Commission’s proposal to eliminate federal rights of first refusal from Commissionjurisdictional 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 argues 

that rights of first refusal are creatures of regulated services that are subject to federallyregulated tariffs and, therefore, proponents of rights of first refusal must find some 

independent legal basis for the property rights they seek to protect. 

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 
Docket No. RM10-23-000 - 216 -

 

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. 

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 Commissionjurisdictional 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 

(continued...) 

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

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 

(D.C. Cir. 2000)). 

249 Ad Hoc Coalition of Southeastern Utilities cites to Brunswick Corp. v. Pueblo 
Docket No. RM10-23-000 - 217 -

 

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. 

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. 

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). 
Docket No. RM10-23-000 - 218 -

 

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. FERC251 noted that section 205 provisions focus on the fair treatment of 

customers. Similarly, Nebraska Public Power District states Public Service Commission 

of Indiana252 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. 

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 

(continued...) 

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 (D.C. Cir. 1984), Sacramento Mun. Util. Dist. v FERC, 474 

F.3d 797, 802 (D.C. Cir. 2007), City of Vernon v. FERC, 845 F.2d 1042, 1046 (D.C. Cir. 

1988), Ohio Power Co. v. FERC, 744 F.2d 162, 165 n.3 (D.C. Cir. 1984), and 

“Complex” Consol. Edison Co. v. FERC, 165 F.3d 992, 1012 (D.C. 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). 

253 E.g., Ad Hoc Coalition of Southeastern Utilities; Nebraska Public Power 
Docket No. RM10-23-000 - 219 -

 

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 

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. 

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 (D.C. Cir. 1996). 

254 E.g., PPL Companies and PSEG Companies. 

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). 
Docket No. RM10-23-000 - 220 -

 

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 Oklahoma Gas 

& Electric Company cites to National Association of Regulatory Utility Commissioners v. 

FERC, 475 F.3d 395, 401 (D.C. 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. 

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 

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 (D.C. Cir. 2009); Mississippi Indus. v. FERC, 808 

F.2d 1525, 1542-43 (D.C. Cir. 1987)). 
Docket No. RM10-23-000 - 221 -

 

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

280. Other commenters similarly agree that not every provision of a Commissionjurisdictional 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 

257 295 F.3d 1 (D.C. Cir. 2002) (Atlantic City). 

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 (D.C. Cir. 2004)).
Docket No. RM10-23-000 - 222 -

 

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 

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 

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. 

261 Indicated PJM Transmission Owners (citing Town of Norwood v. FERC, 80 

F.3d 526, 531 (D.C. Cir. 1996)). 
Docket No. RM10-23-000 - 223 -

 

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 

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 

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. 

263 Office of Consumers’ Counsel v. FERC, 655 F.2d 1132, 1148 (D.C. Cir. 1980). 
Docket No. RM10-23-000 - 224 -

openness must be redefined to include a new sponsorship model. 

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 
Docket No. RM10-23-000 - 225 -

 

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. 

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, 

264 Associated Gas Distributors, 824 F.2d 981, 1008 (D.C. Cir. 1985). 
Docket No. RM10-23-000 - 226 -

 

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. 

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 

265 CAISO v. FERC, 372 F.3d 395 at 403. 
Docket No. RM10-23-000 - 227 -

 

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. 

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, 

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). 
Docket No. RM10-23-000 - 228 -

 

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 

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 

268 372 F.3d 395 at 399. 

269 CAISO v. FERC, 372 F.3d 395 at 398.

270 Id. at 403.
Docket No. RM10-23-000 - 229 -

 

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 made. In removing a federal right of first refusal from Commissionjurisdictional tariffs and agreements, the Commission is drawing no conclusion regarding 

271 See Mo. ex. rel. Southwestern Bell Tel. Co. v. Pub. Serv. Comm’n, 262 U.S. 

276, 289 (1923). 
Docket No. RM10-23-000 - 230 -

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. 

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 
Docket No. RM10-23-000 - 231 -

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. 

3. Removal of a Federal Right of First Refusal from CommissionJurisdictional 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 

 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.” 
Docket No. RM10-23-000 - 232 -

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 
Docket No. RM10-23-000 - 233 -

transmission project developers to recover the cost of a transmission facility through a 

regional cost allocation method.273 

294. Under this framework, the Commission proposed that neither incumbent nor 

nonincumbent transmission facility developers should, as a result of a Commissionapproved 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 

 273 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 90-96. 
Docket No. RM10-23-000 - 234 -

 

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 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. 

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 

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. 
Docket No. RM10-23-000 - 235 -

 

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. 

298. While many commenters endorse requiring project developers to meet 

qualification criteria showing their financing and technical capabilities, some argue that 

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. 
Docket No. RM10-23-000 - 236 -

 

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. 

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 

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. 

279 E.g., PPL Companies; Indianapolis Power & Light; and Pacific Gas & Electric. 
Docket No. RM10-23-000 - 237 -

 

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. 

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 

280 E.g., California ISO; Edison Electric Institute; LS Power; and Transmission 

Agency of Northern California. 
Docket No. RM10-23-000 - 238 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 239 -

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. 

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 

 

(continued...) 

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.

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 
Docket No. RM10-23-000 - 240 -

 

transmission planning processes already evaluate proposed projects through an open 

process described in the relevant public utility transmission providers’ OATTs. 

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. 

Power Agency; Pattern Transmission; American Transmission; California State Water 

Project; Anbaric and PowerBridge; PPL Companies; Green Energy and 21st Century; 

Duke; and Old Dominion. 

285 E.g., Connecticut & Rhode Island Commissions; National Grid; New England 

States Committee on Electricity; KCP&L; Edison Electric Institute; and WIRES.
Docket No. RM10-23-000 - 241 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 242 -

 

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 

287 E.g., Anbaric and PowerBridge; California Municipal Utilities; Edison Electric 

Institute; Exelon; Imperial Irrigation District; LS Power; PJM; and Southern California 

Edison. 
Docket No. RM10-23-000 - 243 -

 

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. 

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 nonincumbent transmission developer’s project. Xcel and others289 contend that selection 

(continued...) 

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 
Docket No. RM10-23-000 - 244 -

 

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 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. 

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 

Dakota Commissions. 

290 E.g., Transmission Access Policy Study Group; Pattern Transmission; and 

Indianapolis Power & Light. 
Docket No. RM10-23-000 - 245 -

 

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. 

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 

291 E.g., Connecticut & Rhode Island Commissions; Indianapolis Power & Light; 

Indicated PJM Transmission Owners; Massachusetts Departments; National Rural 

Electric Coops; and Oklahoma Gas & Electric. 
Docket No. RM10-23-000 - 246 -

 

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. 

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 

292 E.g., New York Transmission Owners; Edison Electric Institute; MISO 

Transmission Owners; Southern Companies; and Transmission Agency of Northern 

California. 
Docket No. RM10-23-000 - 247 -

 

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. 

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 

293 E.g., Ad Hoc Coalition of Southeastern Utilities; FirstEnergy Service 

Company; MISO Transmission Owners; New York ISO; Old Dominion; and SPP. 
Docket No. RM10-23-000 - 248 -

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. 

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 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 
Docket No. RM10-23-000 - 249 -

 

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 

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 

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. 

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. 
Docket No. RM10-23-000 - 250 -

 

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.

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 

297 Id.
Docket No. RM10-23-000 - 251 -

 

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 

298 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 93. 
Docket No. RM10-23-000 - 252 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 253 -

 

herein.300 . 

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 

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. 

300 See definition supra section II.D of this Final Rule. 

301 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 97. 
Docket No. RM10-23-000 - 254 -

 

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 

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. 
Docket No. RM10-23-000 - 255 -

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. 

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. 
Docket No. RM10-23-000 - 256 -

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 
Docket No. RM10-23-000 - 257 -

 

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 

(continued...) 

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 
Docket No. RM10-23-000 - 258 -

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 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 

 

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. 
Docket No. RM10-23-000 - 259 -

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 timebased 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 
Docket No. RM10-23-000 - 260 -

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 
Docket No. RM10-23-000 - 261 -

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 
Docket No. RM10-23-000 - 262 -

 

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. 

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 

305 See supra P 256 
Docket No. RM10-23-000 - 263 -

 

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 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.

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, 

(continued...) 

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. 

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 
Docket No. RM10-23-000 - 264 -

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. 

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 

 

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. 
Docket No. RM10-23-000 - 265 -

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 
Docket No. RM10-23-000 - 266 -

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 
Docket No. RM10-23-000 - 267 -

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 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 
Docket No. RM10-23-000 - 268 -

 

but that is not selected.308 The Commission declines to adopt these aspects of the 

Proposed Rule. 

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 

308 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 95. 
Docket No. RM10-23-000 - 269 -

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 
Docket No. RM10-23-000 - 270 -

developers are subject to and have to meet the same reliability standards.309 

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 

 309 E.g., City of Santa Clara; Federal Trade Commission; NextEra; Northern 

California Power Agency; Pattern Transmission; and Western Independent Transmission 

Group. 
Docket No. RM10-23-000 - 271 -

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 Coordination310

345. This section of the Final Rule adopts several reforms to improve coordination 

 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. 
Docket No. RM10-23-000 - 272 -

 

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 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 

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.” 
Docket No. RM10-23-000 - 273 -

 

foregoing requirements, the Commission requires public utility transmission providers, 

either individually or through their transmission planning region, to maintain a website or 

e-mail list for the communication of information related to interregional transmission 

coordination. 

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

(continued...) 

312 We discuss the filing requirements for the same language to be included in each 
Docket No. RM10-23-000 - 274 -

1. Need for Interregional Transmission Coordination Reform313

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 

 

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. 

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. 

314 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 524. 
Docket No. RM10-23-000 - 275 -

 

region.315

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

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. 

315 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 226. 

316 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 103. 
Docket No. RM10-23-000 - 276 -

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

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 

 

(continued...) 

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. 

319 E.g., AEP; Allegheny Energy Companies; AWEA; CapX2020 Utilities; Clean 

Line; Duke; East Texas Cooperatives; Edison Electric Institute; Energy Future Coalition; 
Docket No. RM10-23-000 - 277 -

 

opportunities for enhancement of existing interregional transmission coordination efforts. 

Several commenters state that a more defined and coordinated interregional transmission 

planning process is 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. 

352. Other commenters argue that there is no coordinated process between regions with 

respect to evaluating interregional transmission projects.320 AEP and MidAmerican 

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 MidKansas; Transmission Access Policy Study Group; Vermont Electric; Westar; Wilderness 

Society and Western Resource Advocates; WIRES; and Wisconsin Electric Power 

Company. 

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. 
Docket No. RM10-23-000 - 278 -

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. 

353. Some other commenters state that improved interregional transmission 
Docket No. RM10-23-000 - 279 -

 

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. 

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 

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

322 E.g., Edison Electric Institute; AWEA; Clean Line; American Transmission; 

and Solar Energy Industries and Large-scale Solar. 
Docket No. RM10-23-000 - 280 -

 

planning. 

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, 

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. 
Docket No. RM10-23-000 - 281 -

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. 

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 
Docket No. RM10-23-000 - 282 -

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 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 
Docket No. RM10-23-000 - 283 -

 

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. 
Docket No. RM10-23-000 - 284 -

 

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 ARRAfunded 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. 

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 SubRegional Planning Group encourages the Commission to support existing planning 

activities, postponing the proposal for additional requirements until after the ARRA326 E.g., SPP; Minnesota PUC and Minnesota Office of Energy Security; AEP; and 

Transmission Dependent Utility Systems. 

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

Xcel. 
Docket No. RM10-23-000 - 285 -

 

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.

363. Other commenters oppose the Commission’s proposed interregional transmission 

planning requirements, arguing they are unnecessary328 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 

(continued...) 

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 
Docket No. RM10-23-000 - 286 -

 

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. 

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 and thorough inventory of existing planning processes and 

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. 
Docket No. RM10-23-000 - 287 -

 

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. 

366. Similarly, several commenters contend that interregional coordination should be 

331 E.g., Washington Utilities and Transportation Commission; Georgia 

Transmission Corporation; and Xcel. 
Docket No. RM10-23-000 - 288 -

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 
Docket No. RM10-23-000 - 289 -

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 
Docket No. RM10-23-000 - 290 -

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. 
Docket No. RM10-23-000 - 291 -

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 ARRAfunded 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 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 
Docket No. RM10-23-000 - 292 -

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 costeffectively. We thus see no need to adopt a case-by-case approach to our requirements. 
Docket No. RM10-23-000 - 293 -

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 

 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. 
Docket No. RM10-23-000 - 294 -

agreement. 

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 website 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 
Docket No. RM10-23-000 - 295 -

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 
Docket No. RM10-23-000 - 296 -

 

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-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

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 

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.
Docket No. RM10-23-000 - 297 -

 

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 

335 E.g., East Texas Cooperatives; ITC Companies; Old Dominion; Transmission 

Access Policy Study Group; and Transmission Dependent Utility Systems. 
Docket No. RM10-23-000 - 298 -

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. 

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 
Docket No. RM10-23-000 - 299 -

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, 
Docket No. RM10-23-000 - 300 -

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. 
Docket No. RM10-23-000 - 301 -

 

389. North Carolina Agencies state that coordination among regions, as well as within a 

broadly defined region, should complement, rather than 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 

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 

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

England. 
Docket No. RM10-23-000 - 302 -

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. 

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 

 337 E.g., Energy Future Coalition; Organization of MISO States; Transmission 

Dependent Utility Systems; and AWEA. 
Docket No. RM10-23-000 - 303 -

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 
Docket No. RM10-23-000 - 304 -

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 costeffectively 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 
Docket No. RM10-23-000 - 305 -

 

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. 

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 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 

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. 
Docket No. RM10-23-000 - 306 -

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 
Docket No. RM10-23-000 - 307 -

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 costeffective 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 
Docket No. RM10-23-000 - 308 -

 

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 

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. 
Docket No. RM10-23-000 - 309 -

 

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. 

401. Moreover, in response to commenters, this Final Rule neither requires nor 

precludes longer-term interregional transmission planning, including the identification of 

341 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 202. 
Docket No. RM10-23-000 - 310 -

 

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 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. 

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 

342 See California Commission. 

343 See MidAmerican. 

344 See Energy Consulting Group. 
Docket No. RM10-23-000 - 311 -

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 
Docket No. RM10-23-000 - 312 -

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 

 345 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 114-15. 
Docket No. RM10-23-000 - 313 -

transmission needs more efficiently than separate intraregional transmission facilities.346

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. 

 346 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 116. 

347 E.g., Integrys; Transmission Dependent Utility Systems; and MISO 

Transmission Owners. 

348 E.g., Integrys and National Grid. 
Docket No. RM10-23-000 - 314 -

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 
Docket No. RM10-23-000 - 315 -

 

Commission to consider extending its proposed interregional transmission planning 

requirements beyond adjacent planning regions to provide a process 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 

349 E.g., Indianapolis Power & Light; Transmission Access Policy Study Group; 

MISO Transmission Owners; New York ISO; and Organization of MISO States. 
Docket No. RM10-23-000 - 316 -

complex and risk frustrating the ARRA-funded interconnectionwide transmission 

planning initiatives. 

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 
Docket No. RM10-23-000 - 317 -

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 
Docket No. RM10-23-000 - 318 -

 

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

417. While the Commission declines to require multilateral or interconnectionwide 

coordination in this Final Rule, we continue to encourage public utility transmission 

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. 
Docket No. RM10-23-000 - 319 -

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 ARRAfunded 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. 

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 
Docket No. RM10-23-000 - 320 -

 

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 

352 See supra section III.A.3 of this Final Rule. 
Docket No. RM10-23-000 - 321 -

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 

 353 E.g., American Transmission; New York Transmission Owners; Northeast 

Utilities; and Transmission Dependent Utility Systems. 
Docket No. RM10-23-000 - 322 -

 

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. 

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. 

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 

354 E.g., PUC of Nevada; New York ISO; and Dayton Power and Light. 
Docket No. RM10-23-000 - 323 -

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 
Docket No. RM10-23-000 - 324 -

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 

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 
Docket No. RM10-23-000 - 325 -

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 
Docket No. RM10-23-000 - 326 -

 

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

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 

355 E.g., California Commissions; Dayton Power and Light; and NARUC. 

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. 
Docket No. RM10-23-000 - 327 -

 

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. 

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 

357 E.g., Indianapolis Power & Light; California ISO; Organization of MISO 

States; and Solar Energy Industries and Large-scale Solar. 
Docket No. RM10-23-000 - 328 -

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. 

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 
Docket No. RM10-23-000 - 329 -

 

transmission plan to be subject to the interregional cost allocation method.358 Duke 

supports the proposed requirement 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. 

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 

358 E.g., New York ISO; New York Transmission Owners; and Transmission 

Dependent Utility Systems. 
Docket No. RM10-23-000 - 330 -

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 
Docket No. RM10-23-000 - 331 -

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 
Docket No. RM10-23-000 - 332 -

 

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

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 

359 See discussion supra section III.B.3.d.ii. 
Docket No. RM10-23-000 - 333 -

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 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 “outof-cycle” review, nor does it prohibit a region or a pair of regions from doing so, for 
Docket No. RM10-23-000 - 334 -

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 
Docket No. RM10-23-000 - 335 -

 

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 

360 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 438. 
Docket No. RM10-23-000 - 336 -

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. 

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. 
Docket No. RM10-23-000 - 337 -

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 
Docket No. RM10-23-000 - 338 -

 

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 

448. Furthermore, as urged by PUC of Nevada, we are cognizant of existing 

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 

361 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 117. 
Docket No. RM10-23-000 - 339 -

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 
Docket No. RM10-23-000 - 340 -

 

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 

362 E.g., Minnesota PUC and Minnesota Office of Energy Security; NextEra; and 

Organization of MISO States. 
Docket No. RM10-23-000 - 341 -

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. 

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 
Docket No. RM10-23-000 - 342 -

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 will 

accommodate each pair of region’s planning cycles. 
Docket No. RM10-23-000 - 343 -

c. Transparency

i. Comments

456. Pennsylvania PUC supports the proposed requirement that interregional 

transmission planning agreements include a commitment to maintain a website 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 

website or regional transmission planning website. 

457. In addition, MISO Transmission Owners suggest that all transmission providers 

offering transmission service or interconnection service under a tariff (including a nonjurisdictional 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 website 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 
Docket No. RM10-23-000 - 344 -

provider’s website or a regional transmission planning website. 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 
Docket No. RM10-23-000 - 345 -

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 
Docket No. RM10-23-000 - 346 -

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. 
Docket No. RM10-23-000 - 347 -

 

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 

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 

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 

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 150. 

365 This information must be made available subject to appropriate confidentiality 

protections and CEII requirements. 
Docket No. RM10-23-000 - 348 -

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 section366 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. 

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

 366 See discussion supra section III.A.3. 

367 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 114. 
Docket No. RM10-23-000 - 349 -

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. 

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. 

471. Some commenters suggest that interregional coordination procedures should be 

 368 E.g., National Grid; New York Transmission Owners; and Edison Electric 

Institute. 

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

Transmission Owners. 
Docket No. RM10-23-000 - 350 -

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 
Docket No. RM10-23-000 - 351 -

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 
Docket No. RM10-23-000 - 352 -

protection against violating state law and that its authority to enter into binding 

agreements is limited consistent with state sovereignty.370 

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, 

 370 Comments addressing specific statutory provisions that may limit nonjurisdictional 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. 
Docket No. RM10-23-000 - 353 -

 

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

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 

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 website 

where the processes to coordinate information and planning efforts [between several 

regional planning groups] are discussed”). 
Docket No. RM10-23-000 - 354 -

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 
Docket No. RM10-23-000 - 355 -

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 
Docket No. RM10-23-000 - 356 -

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

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 and costeffectively (“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 

 373 See discussion infra section V.B. 
Docket No. RM10-23-000 - 357 -

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. 

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 

 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. 
Docket No. RM10-23-000 - 358 -

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 
Docket No. RM10-23-000 - 359 -

 

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 

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. 
Docket No. RM10-23-000 - 360 -

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. 

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. 

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 

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

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. 
Docket No. RM10-23-000 - 361 -

ethod 

at 

ity 

ers 

nment. 

 

energy and environmental goals, and create an intelligent, secure, and reliable 

transmission network. Clean Line argues that implementation of a cost allocation m

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 th

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 author

to alleviate impediments to building new transmission lines for renewable energy and 

other system needs to promote a robust competitive market that will benefit consum

and the enviro

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 

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. 
Docket No. RM10-23-000 - 362 -

 

cost allocation process. 

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. 

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. 

379 E.g., SPP; AEP; MISO Transmission Owners; Organization of MISO States; 

California PUC; and Pacific Gas & Electric. 
Docket No. RM10-23-000 - 363 -

 

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 

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. 
Docket No. RM10-23-000 - 364 -

projects that meet the various regional requirements are constructed and their costs 

recovered as part of tariff rates. 

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 
Docket No. RM10-23-000 - 365 -

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. 

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 

 382 Sacramento Municipal Utility District (citing Farmers Union Central Exchange 

v. FERC, 734 F.2d 1486, 1508 (D.C. Cir. 1984)). 

383 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 557. 
Docket No. RM10-23-000 - 366 -

 

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 

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. 

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 

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). 
Docket No. RM10-23-000 - 367 -

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 
Docket No. RM10-23-000 - 368 -

 

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. 

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 

387 See discussion supra sections III.A and III.C. 
Docket No. RM10-23-000 - 369 -

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 
Docket No. RM10-23-000 - 370 -

 or 

 the 

 

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

state committees to be involved. Additionally, as required by this Final Rule, through

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 

503. In response to Northern Tier Transmission Group’s concern that applying the new 

cost allocation requirements to existing transmission projects covered by existing tariffbased and contract-based cost allocation procedures will shift costs and create 

unnecessary burdens, we clarify that the cost allocation requirements of this Final Rule 

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). 
Docket No. RM10-23-000 - 371 -

apply only to new transmission facilities390 selected in regional transmission plans for 

purposes of cost allocation.

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 D.C. 

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 D.C. Circuit has 

explained that cost causation “does not require exacting precision in a ratemaking 

agency’s allocation decisions.”393

505. The Commission explained that, while costs generally have been allocated through 

 390 See discussion supra P 161. 

391 K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. 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. 
Docket No. RM10-23-000 - 372 -

 

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 

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). 
Docket No. RM10-23-000 - 373 -

 

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. 

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

508. The Commission noted that courts have accepted the application of the cost 

396 Id.; see also Southern California Edison Co., 70 FERC ¶ 61,087, at 61,241-42 

(1995). 

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). 
Docket No. RM10-23-000 - 374 -

causation principle in this way. For example, the D.C. 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 

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 

 399 MISO Transmission Owners, 373 F.3d 1361. The D.C. 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. 

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). 
Docket No. RM10-23-000 - 375 -

“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. 

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 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 
Docket No. RM10-23-000 - 376 -

 

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

(continued...) 

403 In reply, PPL Companies assert that Illinois Commerce Commission overstates 
Docket No. RM10-23-000 - 377 -

 

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 

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. 

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. 
Docket No. RM10-23-000 - 378 -

 

contract for their portion of the benefits. 

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 proposal406 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 

514. Sacramento Municipal Utility District asserts that there is a distinction between 

allocating costs among a public utility transmission provider’s customers without their 

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)). 
Docket No. RM10-23-000 - 379 -

 

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 cases409 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. 

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 

(continued...) 

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). 

410 Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,084; 
Docket No. RM10-23-000 - 380 -

cost 

 

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 

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. 

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 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 

Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ¶ 61,168; Midwest Indep. 

Transmission Sys. Operator, Inc., 113 FERC ¶ 61,194. 
Docket No. RM10-23-000 - 381 -

 

MISO Transmission Owners derived from that delivery.411 

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

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 

411 See also Southern Companies and ColumbiaGrid. 

412 Sacramento Municipal Utility District cites to Ft. Pierce Utilities Comm’n v. 

FERC, 730 F.2d 778 (D. C. Cir. 1984) (Fort Pierce); Richmond Power & Light v. FERC, 

574 F.2d 610 (D.C. 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 (D. C. 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). 
Docket No. RM10-23-000 - 382 -

 

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. 

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 

(continued...) 

413 ColumbiaGrid cites to Exxon Mobil Corp. v. FERC, 430 F.3d 1166 (D.C. Cir. 

2005) (Exxon Mobil Corp.). 

414 E.g., Southern Companies; California Municipal Utilities; Transmission 
Docket No. RM10-23-000 - 383 -

 

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. 

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 

Agency of Northern California; and Columbia Grid. 

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

District. 
Docket No. RM10-23-000 - 384 -

disproportionate costs. 

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. 
Docket No. RM10-23-000 - 385 -

 

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 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. 

527. Southern Companies assert that where vertically integrated transmission providers 

416 ColumbiaGrid bases this claim on Atlantic City Electric Co. v. FERC, 295 F.3d 

1 (D.C. 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. 
Docket No. RM10-23-000 - 386 -

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, nonpancaked rates where transmission systems are integrated. Sacramento Municipal Utility 

District argues in response that the Commission cannot require joint rates unless two 
Docket No. RM10-23-000 - 387 -

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 
Docket No. RM10-23-000 - 388 -

 

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 

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 

418 Ad Hoc Coalition of Southeastern Utilities Comments at 60-61 (emphasis in 

original). 

419 Id. at 60 (emphasis supplied). 
Docket No. RM10-23-000 - 389 -

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 
Docket No. RM10-23-000 - 390 -

 

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 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 

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 

420 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 561. 
Docket No. RM10-23-000 - 391 -

 

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. 

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 

421 MISO Transmission Owners, 373 F.3d 1361, at 1368 (internal citations 

omitted). 

422 KN Energy, 968 F.2d 1295 at 1302. 

423 Id. 
Docket No. RM10-23-000 - 392 -

 

the expectation of its contributions the facilities might not have been built, 

or might have been delayed.424

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 

(continued...) 

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

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 
Docket No. RM10-23-000 - 393 -

 

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. 

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 

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 crossborder 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. 
Docket No. RM10-23-000 - 394 -

 

commenters are supporting participant funding as a regional cost allocation method, we 

address those comments below.428

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 

428 See discussion infra section IV.F.2. 
Docket No. RM10-23-000 - 395 -

 

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 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. 

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 

429 See Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ¶ 61,168; 

Alliance Cos., 100 FERC ¶ 61,137. 

430 See Exxon Mobil Corp., 430 F.3d 1166, 1176-77 (D.C. Cir. 2005). 
Docket No. RM10-23-000 - 396 -

allocation do not “impose” any new service on beneficiaries. 

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 
Docket No. RM10-23-000 - 397 -

 

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. 

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 

431 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 164. 

432 Id. P 174. 

433 Id.
Docket No. RM10-23-000 - 398 -

 

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

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 

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. 

436 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 4. 
Docket No. RM10-23-000 - 399 -

 

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 

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 section 205 to make filings. The Commission 

regularly establishes standards for filings under section 205, and doing so does not negate 

437 See discussion supra section III.A.4. 

438 Atlantic City, 295 F.3d 16, at 21 (D.C. Cir. 2002). 
Docket No. RM10-23-000 - 400 -

any rights under that section. 

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. 
Docket No. RM10-23-000 - 401 -

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 
Docket No. RM10-23-000 - 402 -

methods among transmission planning regions.439

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

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 

 439 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 165. 

440 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 169. 

441 E.g., MidAmerican; American Transmission; Clean Line; Dominion; East 

Texas Cooperatives; MISO; National Grid; NEPOOL; New York ISO; Multiparty 

Commenters; and WIRES. 
Docket No. RM10-23-000 - 403 -

 

allocation method generally applicable to new transmission facilities, citing SPP’s 

highway/byway mechanism as a model.442 

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. 

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 IV.E.8. 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). 

443 E.g., Bonneville Power Administration; California Commissions; Eastern 

Massachusetts Consumer-Owned System; Xcel; and Western Area Power 

Administration. 
Docket No. RM10-23-000 - 404 -

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 through state commissions for facilities that 

the incumbent utilities have not built and for which the incumbent utilities may be unable 
Docket No. RM10-23-000 - 405 -

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 
Docket No. RM10-23-000 - 406 -

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 
Docket No. RM10-23-000 - 407 -

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 
Docket No. RM10-23-000 - 408 -

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, 
Docket No. RM10-23-000 - 409 -

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 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 
Docket No. RM10-23-000 - 410 -

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 

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 

 444 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 175. 
Docket No. RM10-23-000 - 411 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 412 -

 

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. 

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 

446 E.g., New York ISO; Coalition for Fair Transmission Policy; California ISO; 

and National Grid. 
Docket No. RM10-23-000 - 413 -

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-bycase 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 
Docket No. RM10-23-000 - 414 -

 

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 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. 

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 

447 See also, e.g., Connecticut & Rhode Island Commissions. 
Docket No. RM10-23-000 - 415 -

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 

 

(continued...) 

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 
Docket No. RM10-23-000 - 416 -

 

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. 

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 

interregional transmission facility. However, the Commission does not require such 

multiregional provisions among more than two neighboring transmission planning 

regions. 
Docket No. RM10-23-000 - 417 -

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 
Docket No. RM10-23-000 - 418 -

 

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 

449 See discussion supra section III.C. 

450 See discussion supra section III.C. 
Docket No. RM10-23-000 - 419 -

 

located and 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. 

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 

451 See discussion infra section IV.E.5. 

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. 
Docket No. RM10-23-000 - 420 -

satisfied by reference to tariff sheets on file with the Commission. 

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 
Docket No. RM10-23-000 - 421 -

 

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

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. 
Docket No. RM10-23-000 - 422 -

 

(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 

(continued...) 

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. 
Docket No. RM10-23-000 - 423 -

 

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. 

(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

Operator, Inc., 129 FERC ¶ 61,102. As noted above, we adopt this finding in this Final 

Rule. 

456 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 164. 
Docket No. RM10-23-000 - 424 -

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 

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 
Docket No. RM10-23-000 - 425 -

 

facility.457 

(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 

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. 
Docket No. RM10-23-000 - 426 -

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.
Docket No. RM10-23-000 - 427 -

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.

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 

 458 E.g., DC Energy; WIRES; Dominion; and Dayton Power and Light. 

459 See discussion supra section II. 

460 E.g., Large Public Power Council; Kansas Corporation Commission; and 

Nebraska Public Power District. 
Docket No. RM10-23-000 - 428 -

 

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.

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 

461 E.g., Anbaric and PowerBridge; AWEA; MidAmerican; Multiparty 

Commenters; and Southern Companies. 
Docket No. RM10-23-000 - 429 -

 

of time for regions to reach agreement on a proposed interregional cost allocation 

method. 

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 

462 E.g., American Transmission; AWEA; NextEra; and Wind Coalition. 
Docket No. RM10-23-000 - 430 -

 

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 allocation with a proactive regional or interregional plan is important 

for justifying regional cost sharing. 

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 

463 E.g., APPA and PSEG Companies. 
Docket No. RM10-23-000 - 431 -

espect 

 

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.

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 r

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. 
Docket No. RM10-23-000 - 432 -

 integration. 

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

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 
Docket No. RM10-23-000 - 433 -

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 
Docket No. RM10-23-000 - 434 -

 

in good faith to resolve a project from those who only oppose transmission for selfinterested 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. 

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 

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, upfront 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. 
Docket No. RM10-23-000 - 435 -

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, multijurisdictional 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 
Docket No. RM10-23-000 - 436 -

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 
Docket No. RM10-23-000 - 437 -

 

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. 

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 

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. 
Docket No. RM10-23-000 - 438 -

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. 
Docket No. RM10-23-000 - 439 -

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 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. 
Docket No. RM10-23-000 - 440 -

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 benefits468

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 

 468 For the full text of this principle, see P 586 for regional cost allocation and 

P 587 for interregional cost allocation. 
Docket No. RM10-23-000 - 441 -

 

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. 

613. Several commenters, however, support a broader definition of benefits and 

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. 
Docket No. RM10-23-000 - 442 -

 

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 

471 E.g., NextEra; AWEA; EarthJustice; and Atlantic Grid. 
Docket No. RM10-23-000 - 443 -

that the pro-competitive benefits of transmission be recognized. 

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 crosssubsidization. 

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,” arguing that regional planners should not be prognosticators and that 
Docket No. RM10-23-000 - 444 -

 

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. 

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 

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

473 E.g., California Municipal Utilities; Northern Tier Transmission Group; Omaha 

Public Power District; Gaelectric; and Atlantic Grid. 
Docket No. RM10-23-000 - 445 -

 

the Commission articulate more clearly the definitions, presumptions, and methods 

associated with the beneficiary pays approach. 

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. 
Docket No. RM10-23-000 - 446 -

 

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 

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. 
Docket No. RM10-23-000 - 447 -

nning do not 

fully define t

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 pla

he range of beneficiaries. 

b. Commission Determination

622. The Commission adopts the following Cost Allocation Principle 1 for both 

regional and i

g 

 the 

 to, 

nd congestion relief, and/or meeting Public 

Policy Requirements.478

nterregional cost allocation: 

Regional Cost Allocation Principle 1: The cost of transmission 

facilities must be allocated to those within the transmission plannin

region that benefit from those facilities in a manner that is at least 

roughly commensurate with estimated benefits. In determining

beneficiaries of transmission facilities, a regional transmission 

planning process may consider benefits including, but not limited

the extent to which transmission facilities, individually or in the 

aggregate, provide for maintaining reliability and sharing reserves, 

production cost savings a

 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 2 of this Final Rule, we use “Public Policy 

(continued...) 
Docket No. RM10-23-000 - 448 -

and 

Interregional Cost Allocation Principle 1: The costs of a new 

interregional transmission facility must be allocated to each 

transmission planning region in which that transmission facility is 

located in a manner that is at least roughly commensurate with the 

estimated benefits of that transmission facility in each of the 

transmission planning regions. In determining the beneficiaries of 

interregional transmission facilities, transmission planning regions 

may consider benefits including, but not limited to, those associated 

with maintaining reliability and sharing reserves, production cost 

savings and congestion relief, and meeting Public Policy 

Requirements.479

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 

 

Requirements” in Regional Cost Allocation Principle 1 and throughout our discussion of 

the Cost Allocation Principles. 

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. 

480 See discussion supra P 495 and section V.B. 
Docket No. RM10-23-000 - 449 -

ly 

e 

 those that cause costs to be incurred or that benefit from a 

nefits” 

r 

 recognize that 

” 

fits 

 

that it weighs when considering a dispute over cost allocation is whether a proposal fair

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 principl

that includes as beneficiaries

new transmission facility. 

624. However, the Commission is not prescribing a particular definition of “be

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 bette

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

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 bene

will be addressed in the first instance during the process of public utility transmission 

481 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 559. 
Docket No. RM10-23-000 - 450 -

 the 

s 

efit. 

ilities in 

ge that other benefits may accrue to an 

ost 

ition 

 that achieves appropriate results in their respective 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

potential difficulties in quantifying benefits. We note in response to Transmission 

Access Policy Study Group, that any benefit used by public utility transmission provider

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 ben

Western Area Power Administration takes the position that beneficiaries should be 

limited to those that it describes as making direct use of the transmission fac

question, but this fails to acknowled

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 c

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 pos

to apply it in a way
Docket No. RM10-23-000 - 451 -

lanning regions. 

cation 

g for new transmission facilities. We are not ruling on that 

llocated 

transmission planning region without reaching an agreement with those beneficiaries. 

p

627. In response to Dayton Power & Light, the provisions of Regional Cost Allo

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 sharin

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 a

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 
Docket No. RM10-23-000 - 452 -

nning 

 transmission 

provider is responsi

3. Cost Allocation Principle 2—no involuntary allocation of costs to 

.

482

 

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 pla

process to be a beneficiary of certain transmission facilities selected in the regional 

transmission plan for purposes of cost allocation, that non-public utility

ble for the costs associated with such benefits. 

non-beneficiaries483

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 Commiss

mandate regional or even interconnectio

ion to 

nwide cost sharing, but the Commission’s 

decision to decline to do so is sensible. 

631. Some commenters who express general support also express some concerns. For 

 482 See discussion infra section IV.E.5. 

483 For the full text of this principle, see P 586 for regional cost allocation and 

P 587 for interregional cost allocation. 

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. 
Docket No. RM10-23-000 - 453 -

ciple 

efit from the transmission facility, including an economic, reliability, or public 

of 

mission 

o 

t 

d 

ere 

 

example, MISO Transmission Owners urge the Commission to ensure that this prin

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 ben

policy benefit, particularly at or above certain voltage levels, over a reasonable period 

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 trans

customer.485 East Texas Cooperatives argue that by protecting only those that receive n

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 tha

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 allocate

costs. Other commenters, such as E.ON and Public Power Council, are worried that th

will be stranded costs if a planning process exaggerates the benefits resulting from a 

485 E.g., Transmission Dependent Utility Systems and East Texas Cooperatives. 
Docket No. RM10-23-000 - 454 -

es the Commission should permit cost 

ven as it 

g region, and therefore it is 

or transmission projects to those 

 within 

rinciple 

particular project. Public Power Council believ

allocations that mitigate the risk of stranded costs and give due consideration to the 

impact on ratepayers prior to allocating costs. 

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 e

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 plannin

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 f

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”

the context of this principle. It asks whether the Commission intended that the p

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 
Docket No. RM10-23-000 - 455 -

 will 

t the evaluation of benefits and costs 

ithin the context of a cost allocation determination could reasonably include the 

cumulative i

etermination

evaluations should be done on a holistic basis, noting that some individual projects

benefit certain entities more than others but tha

w

mpact of a collection of projects. 

b. Commission D

637. The C

regional and i

efit 

er at present or in a likely future 

scenario, must not be involuntarily allocated any of the costs of 

and 

region, either at present or in a likely 

 

ommission adopts the following Cost Allocation Principle 2 for both 

nterregional cost allocation: 

Regional Cost Allocation Principle 2: Those that receive no ben

from transmission facilities, eith

those transmission facilities.486

Interregional Cost Allocation Principle 2: A transmission planning

region that receives no benefit from an interregional transmission 

facility that is located in that 

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. 
Docket No. RM10-23-000 - 456 -

that transmission facility. 

riately in practice. In response to NextEra, we decline to establish a threshold 

nal 

hat 

te 

future scenario, must not be involuntarily allocated any of the costs 

of 

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 

approp

voltage level to define which benefits would be ineligible for cost allocation in this Fi

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 t

receive no benefits or benefits that are trivial in relation to the costs to be borne. We no

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 
Docket No. RM10-23-000 - 457 -

 of the cost 

rivial, 

t 

tion 

he 

 of 

to the costs to be borne. Any beneficiaries that believe that the application

allocation method or methods would assign to them costs for benefits, which are t

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 op

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 Alloca

Principle 2 apply the allocation of costs to all new transmission facilities selected in t

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

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 
Docket No. RM10-23-000 - 458 -

smission 

up of 

transm

transmission ly commensurate with aggregate benefits. 

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 tran

facilities provides benefits to every beneficiary allocated a share of costs of that gro

ission facilities. However, it is required that the aggregate cost of these 

 facilities be allocated rough

4. Cost Allocation Principle 3—benefit to cost threshold ratio487

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 projects. For example, ITC Companies states that the Commission’s 

recommended cost threshold ratio is a necessary specification to prevent measures suc

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 efficie

488

h 

ncy projects. American Transmission 

 487 For the full text of this principle, see P 586 for regional cost allocation and 

P 587 for interregional cost allocation. 

488 E.g., ITC Companies; American Transmission; Omaha Public Power District; 

PSEG Companies; and Six Cities. 
Docket No. RM10-23-000 - 459 -

ould 

 to 

e 

s 

.

489 A 

gue 

believes that the Commission’s proposal seems like a reasonable threshold that w

likely result in projects actually being constructed.

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

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 supersed

the ratio for a region’s regional cost allocation. Transmission Dependent Utility System

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

number of them stress the difficulties in quantifying benefits.490 Some commenters ar

that the Commission should focus on regional circumstances.491 Northern Tier 

 489 E.g., Northeast Utilities; Connecticut & Rhode Island Commissions; and 

Michig

d Massachusetts 

(continued...) 

an Citizens Against Rate Excess. 

490 E.g., Xcel and Northern Tier Transmission Group. 

491 E.g., Michigan Citizens Against Rate Excess; Xcel; an
Docket No. RM10-23-000 - 460 -

t 

ng 

nt should cover only economic benefits identified with the project, and not 

is 

ion 

ower responds to AWEA’s 

argument for posal would unfairly shift to 

 

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 se

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 planni

stage that would have otherwise been approved. NextEra requests that benefits for this

assessme

reliability or public policy benefits, as those benefits cannot be quantified in a similar 

manner. 

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 

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 Commiss

adopts the proposed threshold, it should be applied as a ceiling to ensure fair treatment 

for projects that have broad benefits over time. MEAG P

 a lower threshold, arguing that AWEA’s pro

 

Departments. 
Docket No. RM10-23-000 - 461 -

customers all risks associated with project development. 

b. Commission Determination

646. The Commission adopts the following Cost Allocation Principle 3 for both 

regional and i

se 

t 

ssion 

or 

 the calculation of benefits and costs. If adopted, such 

a threshold may not include a ratio of benefits to costs that exceeds 

 

nterregional 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 purpo

of cost allocation,492 it must not be so high that transmission 

facilities with significant positive net benefits are excluded from cos

allocation. A public utility transmission provider in a transmi

planning region may choose to use such a threshold to account f

uncertainty in

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. 
Docket No. RM10-23-000 - 462 -

and 

tio is used to determine whether an interregional transmission 

hoose to use such a 

ld, 

shold to one that is not so high as to block inclusion of many 

 

Interregional Cost Allocation Principle 3: If a benefit-cost threshold 

ra

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 c

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. 

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 thresho

the principle limits the thre

worthwhile transmission projects in the regional transmission plan. Further, it allows

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. 
Docket No. RM10-23-000 - 463 -

on 

ay 

osts. 

 the 

itive net benefits that would otherwise be 

sitive 

d 

that a 

io 

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 Commissi

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 m

want to use such a ratio to account for uncertainty in the calculation of benefits and c

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

Commission approves, a greater ratio, will ensure that the ratio is not so high that 

transmission facilities with significant pos

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 po

ratio. The Commission therefore rejects requests to adopt a higher or lower threshol

ratio, as advocated by some commenters. 

649. In response to specific comments on this principle, the Commission agrees 

benefit to cost ratio should not be set so high as to preclude certain beneficial 

transmission projects from 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 rat
Docket No. RM10-23-000 - 464 -

, 

ntified in this Final Rule applies 

ermore, in response to MISO Transmission Owners, if the issue of whether 

any be ersede 

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 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 ide

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. Furth

nefit to cost ratio threshold for an interregional transmission facility may sup

that filing. 

5. Cost Allocation Principle 4—allocation to be solely within 

transmission planning region(s) unless those outside voluntarily 

assume costs494

a. Comments 

651. Nearly all entities that commented on proposed Cost Allocation Principle 4 

 

494 For the full text of this principle, see P 586 for regional cost allocation and 

P 587 for interregional cost allocation. 
Docket No. RM10-23-000 - 465 -

ng 

g the 

iate to allow more expansive voluntary cost allocation arrangements, 

ut would be premature and unrealistic to require all regions to adopt specific cost 

ns 

es 

o 

on 

land concludes that development of such 

support it.495 For example, NEPOOL states that it particularly supports Principle 4, citi

New England’s successful history of voluntarily planning, developing and allocatin

costs of interregional projects with its neighbors. New York ISO agrees, stating that it 

would be appropr

b

allocation methodologies on an ex ante basis that would be applicable to future situatio

as yet unknown. 

652. However, some commenters raise specific concerns. East Texas Cooperativ

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 t

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 allocati

method must not transfer costs to New England ratepayers to support development of

facilities outside New England unless New Eng

facilities are the most cost-effective. Northeast Utilities states that it supports the 

 

ISO; New York PSC; Northern California Power Agency; and New York Transmis

495 E.g., ISO New England; Nebraska Public Power District; NEPOOL; New York 

sion 

Owners. 
Docket No. RM10-23-000 - 466 -

e other. 

O 

al cost allocation method. As an alternative, PJM suggests providing for the 

nsfer 

n 

 

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 th

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-MIS

interregion

cost allocation of transmission to all system users that benefit from the increased tra

capability that the new facility provides, thereby moving the decision from controversies 

surrounding particular generation sources to the future characteristics of the transmissio

496 See, e.g., NextEra; MISO; and MISO Transmission Owners. 
Docket No. RM10-23-000 - 467 -

ore regions may mutually 

ners, argues that projects located entirely in one region may 

rovide benefits to entities in the neighboring region. 

it to 

bers 

ng 

n the 

Proposed Ru costs to be allocated to a 

t to 

ion Principle 4 states that costs cannot be 

allocated to a

region where

system, which is a subject that is more clearly within the Commission’s authority and 

expertise.

654. Similarly, MISO seeks clarification that two or m

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 Ow

p

655. Large Public Power Council states that its members cannot at this time comm

entering into interregional agreements regarding cost allocation. It notes that its mem

are creatures of state and municipal governments, and their authority to enter into bindi

arrangements is restricted. 

656. Finally, the Coalition for Fair Transmission Policy sees an ambiguity i

le. It states that the Proposed Rule allows for

beneficiary even when the beneficiary has not entered into a voluntary arrangemen

pay those costs, but proposed Cost Allocat

n entity or region outside of the geographic boundaries of the planning

 the project is being constructed, absent a voluntary agreement. 
Docket No. RM10-23-000 - 468 -

b. Commission Determination

mmission adopts the following Cost Allocation Principle 

nterregional cost allocation:

Regional Cost Allocation Principle 4: The allocation method for the

cost of a transmission facility selected in a regional transmission 

plan must allocate costs solely within that transmission planning 

region unless another entity outside the region or another 

transmission planning region voluntarily agrees to assume a portion

of those costs. However, the transmission planning process in t

original region must identify consequences for other transm

657. The Co 4 for both 

regional and i

he 

ission 

planning regions, such as upgrades that may be required in another 

ith 

 

497

region and, if the original region agrees to bear costs associated w

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 63-65 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. 
Docket No. RM10-23-000 - 469 -

and 

 is 

iders in the regions in which the 

the beneficiaries in the transmission planning regions in which the 

Interregional Cost Allocation Principle 4: Costs allocated for an 

interregional transmission facility must be assigned only to 

transmission planning regions in which the transmission facility

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 prov

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 

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 

provid and 

ansmission facility” was changed to “upgrade” in each instance in this 

(continued...) 

es benefits to another transmission planning region. For example, if regions A

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 “Tr
Docket No. RM10-23-000 - 470 -

other 

s may, 

ded to 

n 

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 an

transmission planning region without reaching an agreement with those beneficiaries. 

The public utility transmission providers in such transmission planning region

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 inten

export electric energy from one such transmission planning region to the other 

transmission planning region, this Final Rule requires that the public utility transmissio

providers in each pair of transmission planning regions have an interregional cost 

allocation method or methods for sharing the cost of such transmission facilities. 

 

4. The end of the last sentence is revised to be consistent with Regional Cost Allocatio

sentence to make it consistent with the last sentence in regional cost allocation Principle 

n 

Principle 4. 
Docket No. RM10-23-000 - 471 -

lanning regions to assign the cost of the 

ere 

ent 

ted. 

onal cost 

gh 

e 

n, 

e 

on 

 

However, Interregional Cost Allocation Principle 4 does not permit the cost allocation 

method or methods for those two transmission p

transmission facility to beneficiaries in a third transmission planning region except wh

the beneficiaries in the third transmission planning region voluntarily reach an agreem

with the two transmission planning regions in which the transmission line is loca

They also may satisfy the requirements of this Final Rule by having an interregi

allocation method or methods for more than two transmission planning regions, althou

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 th

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 allocatio

both of which involve the identification of beneficiaries. In light of that closer link, w

find that allowing one region to allocate costs unilaterally to entities in another regi

501 See discussion supra section IV.D. 
Docket No. RM10-23-000 - 472 -

transmission 

. 

. 

s 

MISO and PJM developed their 

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 

would impose too heavy a burden on stakeholders to actively monitor 

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. 

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 doe

not cross the border between their two regions. Because 

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 
Docket No. RM10-23-000 - 473 -

nsure that the 

re is 

to be allocated to a beneficiary when the 

benefi ile also 

providing in Cost Allocation Principle 4 that the costs of transmission facilities in a 

6. Cost Allocation Principle 5—transparent method for 

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 e

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. 

664. We disagree with Coalition for Fair Transmission Policy’s argument that the

an ambiguity in our reforms that allows for costs 

ciary has not entered into a voluntary arrangement to pay those costs, wh

regional transmission plan cannot be allocated to an entity in another transmission 

planning region, absent a voluntary agreement. 

determining benefits and identifying beneficiaries503

a. Comments 

665. Nearly all commenters that address this proposed principle supported it.504 PSEG 

 

le, see P 586 for regional cost allocation and 

P 587 

ssion Access Policy Study Group; and Transmission 

(continued...) 

502 See discussion infra section V.B. 

503 For the full text of this princip

for interregional cost allocation. 

504 E.g., SPP; Transmi
Docket No. RM10-23-000 - 474 -

tomers 

, 

ethods be pragmatic. DC Energy raises concerns about the use of biased assessments, 

its be considered in economic studies since they 

 

roposed principle. 

Transmission sion to recognize that 

 

Companies agree that there is a need for transparent cost allocation and that cus

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. 

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 

m

and it suggests that one method for improving the reliability of cost-benefit analyses is to 

require that only direct costs and benef

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. 

667. Several commenters raise specific issues with respect to the p

 Dependent Utility Systems urge the Commis

Dependent Utility Systems. 

505 E.g., NextEra and Sunflower and Mid-Kansas. 
Docket No. RM10-23-000 - 475 -

oad serving entity involvement in the planning 

and developm ners 

argue that cur

transparency alone is insufficient without l

ent of the cost allocation method. Finally, MISO Transmission Ow

rent RTO processes provide significant transparency. 

b. Commission Determination

mmission adopts the following Cost Allocation Principle 5 for bo

nterregional cost allocation: 

668. The Co th 

regional and i

Regional Cost Allocation Principle 5: The cost allocation method 

ith 

and 

rmining benefits and 

and data requirements for determining benefits and identifying

beneficiaries for a transmission facility must be transparent w

adequate documentation to allow a stakeholder to determine how 

they were applied to a proposed transmission facility. 

Interregional Cost Allocation Principle 5: The cost allocation 

method and data requirements for dete

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 
Docket No. RM10-23-000 - 476 -

or 

erential. 

the 

ay 

are 

ose benefits, and the relative benefits that accrue to various beneficiaries can 

t 

 

interregional transmission facility.506 

669. Requiring cost allocation methods and their corresponding data requirements f

determining benefits and beneficiaries to be open and transparent ensures that such 

methods are just and reasonable and not unduly discriminatory or pref

Furthermore, greater stakeholder access to cost allocation information will help aid in 

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 m

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 

receiving th

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 cos

allocation. 

671. We acknowledge the concerns that the method or methods for determining 

 the 

sentence to be precise. 

506 “Interregional” has been added before “transmission facility” at the end of
Docket No. RM10-23-000 - 477 -

ds 

rticipate in the development of such 

, 

rgy, that only direct costs and benefits should 

e considered in economic studies. We will not, however, opine on such suggestions at 

this ti

method or methods are filed on compliance. 

of a compliance filing by any RTO or ISO. 

benefits and beneficiaries must balance being pragmatic and implementable with being 

accurate and unbiased. Cost Allocation Principle 5 requires that the method or metho

be known and transparent. As stakeholders pa

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 Ene

b

me. Rather, the Commission will review such matters once the cost allocation 

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 
Docket No. RM10-23-000 - 478 -

7. Cost Allocation Principle 6—different methods for different 

types of facilities507

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. Four G&T 

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 

508

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 

suggests that a cost allocation method be able to accommodate different types of facilities 

 507 For the full text of this principle, see P 586 for regional cost allocation and

P 587 for interregional cost allocation. 

508 E.g., Indianapolis Power & Light; NEPOOL; Public Powe

 

r Council; Northeast 

Utilities; New Jersey Board; E.ON; American Transmission; Dayton Power and Light; 

Companies. 

Delaware PSC; Dominion; New England States Committee on Electricity; and PSEG 
Docket No. RM10-23-000 - 479 -

f project involved. 

y 

ted 

e 

of 

 process. 

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 o

New Jersey Board also supports flexibility and states that further analysis must be 

completed to determine how best to allocate costs for transmission driven primarily b

public policy requirements because the beneficiaries may differ markedly from the 

beneficiaries of transmission facilities built for reliability purposes.

674. PSEG Companies request that reliability and non-reliability projects be trea

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 b

responsible for paying for them. National Grid, however, is concerned about the use 

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

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 
Docket No. RM10-23-000 - 480 -

licy projects. Economic and 

uirements and accept the allocation of costs associated with those 

rojects. PJM further suggests a “safe harbor” to prevent states from having to absorb 

is a 

ropriate. Northeast Utilities contends that the existing cost 

ents 

economic projects and a separately stated method for projects intended to meet public 

policy requirements. 

allocation related to economic, reliability, and public po

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 req

p

costs for public policy projects undertaken in other states. 

676. Large Public Power Council believes that the interregional allocation of costs 

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 app

allocation rules in the ISO-New England OATT would meet the proposed requirem

for regional cost allocation with the addition of a clearer cost allocation method for 
Docket No. RM10-23-000 - 481 -

y 

s 

rce of 

arguing 

 it does not oppose the concept of using different cost 

llocation mechanisms for projects with different drivers, it believes that an excessive 

 the 

to ensure that, regardless of the initial driver, projects are ultimately scoped 

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 ma

provide general reliability and other benefits to the transmission system; (2) the benefit

of a given project may vary over time; and (3) such designations have been the sou

substantial delays and conflict as planning participants spend time and resources 

over a project’s designation. 

679. Xcel states that while

a

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

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 

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 

 509 E.g., ITC Companies; Multiparty Commenters; NextEra; and Wind Coalition. 
Docket No. RM10-23-000 - 482 -

f cost 

y 

ey state that including load 

le 

each initial project driver. 

680. Multiparty Commenters express concern that there could be a proliferation o

allocation designs if the Commission allows different cost allocation methods for 

different types of facilities and for interregional and regional planning processes. The

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. Th

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 ru
Docket No. RM10-23-000 - 483 -

g that public policy projects be constructed. New York ISO states that such cost 

ing 

f 

nd 

s 

bly eliminate, an entity’s ability to incur costs for its own renewable 

generation o Authority therefore believes 

osts 

satisfying their own lawful public policy 

goals.

684. Allian rms 

“region” and re is a 

CommissionTransmission the 

opportunity for discrimination and unintended consequences if the Commission 

or ISO footprint. It states that cost allocation policies within an RTO or ISO footprint 

requirin

allocation methods can and should be determined on a project-specific basis depend

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 o

transmission that facilitates the interconnection of renewable energy generation a

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 rate

that reduce, or possi

r energy efficiency goals. Long Island Power

the Final Rule should not direct project costs to non-beneficiaries and not impose c

that prevent non-jurisdictional entities from

t Energy seeks clarification that for purposes of Principle 6 the te

“regional” cover the entire RTO or ISO footprint in the case where the

approved planning region within an RTO or ISO, such as American 

 within MISO. Alliant Energy contends that Principle 6 invites

determines that a region could constitute a single transmission provider within the RTO 
Docket No. RM10-23-000 - 484 -

must be consi

nation

stent. 

b. Commission Determi

The Commission adopts the following Cost Allocation Principle 6 for both 

regional and i

ssion 

n 

for this rule. 

regions may choose to use a different cost allocation method for 

ssion facilities needed for reliability, congestion relief, or to 

685.

nterregional cost allocation: 

Regional Cost Allocation Principle 6: A transmission planning 

region may choose to use a different cost allocation method for 

different types of transmission facilities in the regional transmi

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 i

the compliance filing 

and 

Interregional Cost Allocation Principle 6: The public utility 

transmission providers located in neighboring transmission planning 

different types of interregional transmission facilities, such as 

transmi

 510 “Public Policy Requirements” replaces “public policy requirements establi

by State or Federal laws or regulations that may drive transmission needs” as defined

2 of this Final Rule. 

shed 

 in P 
Docket No. RM10-23-000 - 485 -

hod 

t require the public utilities in a transmission 

 only 

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

686. We agree with the Pennsylvania PUC and others that transmission planning 

regions should be afforded the opportunity to develop a different cost allocation met

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 no

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

 

 “Public Policy Requirements” replaces “public policy requirem

by State or Federal laws or regulations that may drive

511 ents established 

 transmission needs” as defined in P 

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 

allocat

2 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. 

e costs differently for each type. 
Docket No. RM10-23-000 - 486 -

al 

istinct 

smission 

itical 

r transmission needs driven by Public Policy Requirements, 

one cost allocation method 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 region

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 d

regional or interregional cost allocation method applicable solely to transmission 

facilities for Public Policy Requirements and that are selected in a regional tran

plan for purposes of cost allocation, but we allow it. 

688. Moreover, as the Commission recognized in Order No. 890, states have a cr

role with respect to transmission planning.514 That role may be particularly important 

with respect to planning fo

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 

 514 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 574. 
Docket No. RM10-23-000 - 487 -

g a 

ropriate 

ost 

lic Policy 

dered in the regional 

s 

 in a 

es of 

Requirements. States could pursue such agreements in various forms, includin

committee of state regulators or through a compact among states that receives app

approval from Congress. 

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 c

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 Pub

Requirements, all of which would be required to be consi

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 procedure

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

transmission planning region to distinguish or not distinguish among these three typ

transmission facilities, as long as each of the three types is considered in the regional 
Docket No. RM10-23-000 - 488 -

 a 

t 

 that 

n for 

response to New York ISO and Long Island Power 

tion and 

n 

smission needs driven by a Public 

n 

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

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 cos

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

type of transmission facility from being selected in a regional transmission pla

purposes of cost allocation. In 

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 alloca

must not be designated as a type of transmission facility for which the cost allocatio

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 tran

Policy Requirement, who is responsible for complying with that Public Policy 

Requirement, and who benefits from the transmission facility. If a regional transmissio

plan determines that a transmission facility serves several functions, as many commenters
Docket No. RM10-23-000 - 489 -

 any existing processes 

on planning process meets 

Regio lities 

driven by a P it evidence in support of this position 

 multiple functions 

nd benefits and beneficiaries may vary over time. This concern should be addressed in 

each region’ ess. However, we note that many regional 

etween 

693. , the Commission addressed this concern 

in the r

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

satisfy Cost Allocation Principle 6 in the regional and interregional context. For 

example, if a region believes that its regional transmissi

nal Cost Allocation Principle 6 for all facilities, including transmission faci

ublic Policy Requirement, it may subm

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

a

s transmission planning proc

transmission planning processes currently have mechanisms for distinguishing b

types of transmission facilities, and there is no reason to believe that transmission 

facilities designation necessarily results in a substantial delay. 

In response to Alliant Energy’s comment

egional transmission planning section above.515

 515 See discussion supra section III.A. 
Docket No. RM10-23-000 - 490 -

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

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. 

696. ELCON and Associated Industrial Groups urge the Commission to adopt two 

 516 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 178. 

517 E.g., California Commissions; California Municipal Utilities; City of Santa 

rnia 

se-Powerlink project as one that is a clear 

examp

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 Califo

Municipal Utilities’ inclusion of the Sunri

le that cost overruns are endemic. 
Docket No. RM10-23-000 - 491 -

adjustment of cost allocation to reflect changes in power flows.518 

lic 

ed approvals before they are allocated costs for new transmission 

lanning 

at 

cost 

 

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 

However, ITC Companies do not support periodic adjustments of cost allocation and 

describe it as disruptive and potentially risky. 

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-pub

utilities to seek requir

projects, and that participation in the regional transmission planning process by nonpublic utilities remain voluntary. Similarly, Transmission Dependent Utility Systems

state that if a particular customer is not allowed to participate fully in a regional p

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 th

span multiple balancing authority areas and for which a voluntarily negotiated 

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 

 

518 See also East Texas Cooperatives and Maine Parties. 
Docket No. RM10-23-000 - 492 -

 to adopt reciprocal cost 

n 

er 

 rate continuity, minimizes customer impact and undue cost shifts, and 

e 

/distribution of benefits that are 

encouragement for non-jurisdictional governmental agencies

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 nontransmission projects, and that no state or region should shoulder the cost alone whe

benefits accrue to others as well, namely for reliability projects only. 

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 custom

understanding 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 rang

of benefits that must be accounted for when justifying a project.520 They state that 

project costs should be allocated consistent with the range

 519 See also Electricity Consumers Resource Council and the Associated Industrial 

Groups and Public Power Council. 

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. 
Docket No. RM10-23-000 - 493 -

 include 

 any beneficiaries-pay cost allocation policy be 

defined to in l outcomes described above, as 

w costn and 

t 

g those receiving 

likely to accrue in both the near- and long-term, that the benefits of projects must

carbon emissions reductions and the attainment of other state and federal policy 

imperatives, and that beneficiaries under

clude consideration of the myriad of beneficia

well as other benefits likely to accrue to transmission system users over the life of the

grid investment. 

702. American Antitrust Institute states that the Commission should consider ho

benefit tests for cost allocation and recovery can be designed to promote competitio

encourages the Commission to carefully scrutinize cost allocation approaches based on 

voting rules that give incumbent utility transmission providers the ability to vote agains

economic transmission projects that benefit ratepayers. 

703. Energy Consulting Group suggests that beneficiaries, includin

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 
Docket No. RM10-23-000 - 494 -

re 

d 

 Final 

inal Rule, would limit the flexibility we provide in this Final Rule for 

 cost allocation method or 

it each transmission 

lanning region or pair of transmission planning regions to propose cost allocation 

metho

specific needs of that transmission planning region or transmission planning regions 

on compliance, along with an explanation of how they comply with the requirements of 

this Final Rule. 

beneficiaries. While we understand and agree that those receiving a cost allocation a

appropriately concerned that the level of the cost being allocated should be controlle

accordingly, we do not believe that a new principle or corollary requirement in this

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 F

public utility transmission providers to propose the appropriate

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 perm

p

ds that satisfy additional requirements that they deem necessary to meet the 

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 
Docket No. RM10-23-000 - 495 -

F. Application of the Cost Allocation Principles

706. The Proposed Rule addressed several potential applications of the cost allocation 

principles, se

principles and how they should be applied to the costs of new regional and interregional 

transmission facilities that are eligible for cost allocation. 

1. Whether To Have Broad Regional Cost Allocation for Extraeking general comment on the appropriateness of these six cost allocation

521

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

vide 

 

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, pro

 

521 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 178. 
Docket No. RM10-23-000 - 496 -

 for 

n 

 forma transmission cost allocation method, and that 

d 

sts 

both regions, and AEP states that the costs of such facilities should be allocated across 

e supports allocating the costs for extra-high voltage lines across 

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

projects above 500 kV. NextEra suggests that those seeking to rebut this presumption i

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

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 an

the costs of such facilities should be allocated widely across a region. AEP also sugge

that extra-high voltage AC facilities that interconnect electrical regions and that are 

identified as needed under the applicable interregional coordination agreement benefit 

those regions. Clean Lin

the largest region possible. 

 522 Multiparty Commenters append an analysis performed by CRA Interna

that purports to show the widely dispersed benefits of extra-high voltage transmission 

facilities (CRA Study). 

tional 
Docket No. RM10-23-000 - 497 -

cts within RTOs. It 

, 

 be 

er 

710. Baltimore Gas & Electric submits that the Final Rule should apply 

highway/byway principles to projects that traverse RTOs and to proje

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

continued in PJM,523 regardless of the methods that are deemed appropriate for oth

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. 

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 

 

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 

523

method is preferable to the energy allocator method proposed in MISO. 

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. 
Docket No. RM10-23-000 - 498 -

es 

 is 

e 

ializing the 

d 

wn 

ion would result in higher costs to 

ies 

osal could result in unjust and 

unreasonable argues that the CRA Study 

its members derive no or only trivial benefits. Ad Hoc Coalition of Southeastern Utiliti

replies that there is no basis to presume that an extra-high voltage transmission overlay

beneficial to all customers, and that such a position is inconsistent with Illinois 

Commerce Commission. Ad Hoc Coalition of Southeastern Utilities emphasizes that th

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 soc

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 sprea

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 sho

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 reg

consumers than implementing non-extra-high voltage solutions. Southern Compan

also argue that such an approach would skew the evaluations of which transmission and

non-transmission alternatives are the least cost means to meet an identified need. MEAG

Power provides illustrations of how such a prop

 rates. Coalition for Fair Transmission Policy

filed by Multiparty Commenters is flawed because it neglects to mention that in some 
Docket No. RM10-23-000 - 499 -

hat 

r 

t 

lysis and fails to 

e 

cases extra-high voltage facilities impose costs on some parts of a region as well, and t

such impacts can be ascertained only by examining specific projects. MEAG Powe

similarly asserts that the CRA study is flawed for a number of reasons, including the fac

that it examines only the existing grid, omits several regions from its ana

estimate any dollar benefits accruing to any party. 

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 b

allocated roughly commensurate with benefits. 

c. Commission Determination

713. We are not persuaded to adopt a rebuttable presumption that the costs of ex

high voltage facilities, such as 345 kV and above, should be allocated widely across a 

transmission planning region. Such a presumption would be

tra-

 akin to a default cost 

allocation m ame reason, 

we do not ag

t 

 

ethod which, as discussed above,526 we do not adopt. For the s

ree that a pro forma cost allocation method is appropriate.

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 cos

526 See discussion supra section IV.E.1. 
Docket No. RM10-23-000 - 500 -

d 

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 allocate

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 Prop

Rule, the Commission discussed their application to participant funding as a regional or 

interregional cost allocation method for satisfying these principles. The Commission 

explained

osed 

 that in transmission planning regions outside of the RTO and ISO footprints, 

many of the der No. 890 

s 

is not a cost allocation method that would satisfy these principles. The Commission 

further participant funding 

cost allocation methods that the Commission accepted in the Or

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 entitie

that volunteer to bear those costs.527 The Commission proposed that participant funding

 noted that a cost allocation method that relies exclusively on a 

 527 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 121-28. 
Docket No. RM10-23-000 - 501 -

er, 

ments on Limiting 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. Howev

the Proposed Rule did not prohibit voluntary participant funding for those that choose to

use it. 

b. Com

hat 

ost 

 

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 t

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. 

717. Several commenters agree that the Commission should clarify what regional c

 

, AWEA; East Texas Cooperatives; Gaelectric; ITC Companies; Multiparty 

Commenters; NextEra; Transmission Access Policy Study Group; Transmission 

Depen

ectric; Multiparty Commenters; and Transmission 

Depen

528 E.g.

dent Utility Systems; and WIRES. 

529 E.g., AWEA; Gael

dent Utility Systems. 
Docket No. RM10-23-000 - 502 -

re cost 

ort 

ansmission additions that are “right sized” to meet the long-term needs of the system, 

, and 

w 

allocation approaches are not acceptable.530 AWEA states that to ensure that futu

allocation proposals do not serve as barriers to transmission expansion, and can supp

tr

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

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 ne

resources. 

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 

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

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. 
Docket No. RM10-23-000 - 503 -

s 

n. 

e 

s 

lows 

d that the participant funding 

 

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 a

transmission customers are required to access electricity from renewable generatio

Therefore, some commenters argue that the Commission first must present factual 

evidence that current cost allocation methods are unjust and unreasonable, or otherwis

unduly discriminatory, which it has not done. Ad Hoc Coalition of Southeastern Utilitie

and Arizona Corporation Commission argue that participant funding most closely fol

“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 conten

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 

532 E.g., Ad Hoc Coalition of Southeastern Utilities; Arizona Corporation 

Commission; City of Los Angeles Department of Water and Power; and Tucson Electric. 
Docket No. RM10-23-000 - 504 -

ing the 

 upon 

ing 

o customer-specific requests for service under the pro forma OATT. It 

e 

 in 

process. Entergy notes that upgrades necessary to meet the specific request are similarly 

constru

to identify beneficiaries. Entergy cites to its own proposal regarding customer-specific 

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 participantfunded 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 caus

construction of new transmission than does a situation where costs could be forced

unwilling parties, as is contemplated by the Proposed Rule. 

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 fund

would not apply t

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 th

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

consultation with the affected customer, not vetted through a regional stakeholder 

cted to meet the needs of the customers, and are not subjected to a cost-benefit test 
Docket No. RM10-23-000 - 505 -

.

534 

e potential for cost socialization will lead to the 

hat the 

sts 

r is 

processes.535 These commenters and others,536 primarily located in the Western 

service requests that the Commission found “will promote, not discourage, efficient 

investments.”533

720. Some commenters that support participant funding as a cost allocation method 

raise concerns about overly broad socialization of costs absent such a mechanism

Large Public Power Council adds that th

planning process becoming vastly more contentious. Southern Companies argue t

proposed reforms are not consistent with cost causation principles. Likewise, 

Transmission Agency of Northern California argues that broad socialization of co

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 & Pape

concerned about the potential for overly broad socialization of costs to diminish 

incentives for cost-effective planning. 

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 

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

534 E.g., Arizona Public Service Company; Large Public Power Council; Nebraska 

Public

 PUC of Nevada; Transmission Agency of Northern 

(continued...) 

 Power District; WestConnect; and Transmission Agency of Northern California. 

535 E.g., WestConnect;
Docket No. RM10-23-000 - 506 -

allocation of transmission 

. 

ple, 

d long-term purchasers for these resources, which are 

greatly comp energy credits may be 

Interconnection, believe that voluntary coordination and cost 

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. 

722. Commenters note other challenges to restricting participant funding. For exam

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), an

licated by the fact that energy and renewable 

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 

 

and California Transmission Planning Group. 

rn 

California; and Coalition for Fair Transmission Policy. 

536 E.g., Arizona Public Service Company; Bonneville Power; Tucson Electric; 

537 E.g., Arizona Public Service Company; California Commissions; and Weste

Area Power Administration. 
Docket No. RM10-23-000 - 507 -

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 interregiona

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 def

l 

er investment in the hopes that other 

al 

l 

egional 

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 region

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 regiona

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 r
Docket No. RM10-23-000 - 508 -

s 

st 

 in 

e allocation of 

osts for new transmission facilities in a manner that is roughly commensurate with the 

ts 

or 

be the cost allocation method for 

cost allocation method or methods developed in compliance with this Final Rule allocate

costs roughly commensurate with benefits. 

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 co

causation principle. Through the cost allocation principles adopted above, we require

all cases that regional and interregional cost allocation methods result in th

c

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 cos

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 

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 

regional or interregional projects that are selected in a regional transmission plan for 
Docket No. RM10-23-000 - 509 -

n 

n 

es 

might not have been built, or might have been delayed.”538 This statement embodies “but 

for” reas capture all beneficiaries 

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 transmissio

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 Commissio

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 argu

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

oning, and since participant funding does not in all cases

 538 Illinois Commerce Commission, 576 F.3d 470 at 476. 
Docket No. RM10-23-000 - 510 -

cost allocation method that mostly follows 

roject development. Yet nothing in this Final Rule precludes the use of participant 

ts. 

ion 

on 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. 

of new facilities, it cannot be said to be the 

“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 

p

funding for those transmission projects with the support of individual market participan

We find that Northern Tier Transmission Group’s argument that other cost allocat

methods will impair construction to be speculative and see no reason to conclude that 

other methods in fact will have this result.

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 

socializati

 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. 
Docket No. RM10-23-000 - 511 -

ce 

ds 

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 

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 servi

mechanisms for individual transmission service requests or requests for interconnection 

service. 

3. Whether Regional and Interregional Cost Allocation Metho

May Differ

a. Commission Proposal

le, 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 

plannin he costs of 

 

730. In the Proposed Ru

g region pursuant to an agreed-upon method for allocating t

 

540 See also discussion supra section III.A.3. 
Docket No. RM10-23-000 - 512 -

interregional facilities.541

b. Comments

731. Several commenters agree with the Commission’s proposal that the method

for allocating interregional transmission facility costs may differ from the method u

allocate regional costs.

 used 

sed to 

enter into agreements with 

nal 

e that transmission 

providers an ermine whether the cost 

542 Georgia Transmission Corporation states that if an 

interregional coordination obligation would require entities to 

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 interregio

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 stat

d their stakeholders should be permitted to det

allocation methods used for regional projects should apply to the transmission provider’s

share of interregional facilities. 

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

 541 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 176. 

542 E.g., Georgia Transmission Corporation; Indianapolis Power & Light; MISO

Transmission Owners; NEPOOL; and Northeast Utilities. 
Docket No. RM10-23-000 - 513 -

Final Rule should either clarify the manner in which 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

transmission planning regions may be different from the method or methods used by 

 two 

ither of them for regional cost allocation. Also, the method or methods for allocating a 

e 

ssion 

al transmission facilities broadly, it may be inappropriate to apply broad cost 

sharin

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. 

e

region’s share of the cost of an interregional transmission facility may differ from th

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 transmi

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

region

g for an interregional transmission facility that is found to benefit only part of that 
Docket No. RM10-23-000 - 514 -

sion 

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 transmis

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 

d 

entities should be rolled into the applicable zonal, regional, or interregional rate, and that 

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 graspe

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 
Docket No. RM10-23-000 - 515 -

tail on the standards to be applied when reviewing or 

its 

 on 

ulti-area transmission proposals, akin to the disruptive effects that unnecessary 

mission 

mission encourages the 

d 

t 

methods that the Commission is likely to consider just and reasonable. WIRES states 

that the u

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 de

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 

concern that unnecessary variance in allocation methods will have a disruptive effect

m

diversity in methods for calculating available transmission capacity had on trans

services spanning multiple areas. Federal Trade Com

Commission to consider whether stronger guidance would promote consensus sooner an

avoid creating a patchwork of transmission cost allocation methods that may not suppor

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 

se of a relatively complete set of principles affords the Commission an
Docket No. RM10-23-000 - 516 -

nt 

e extent to which the benefits of 

o 

ional cost allocation principles discussed 

ome commenters suggest that cost allocation methods should be 

periodi

ents to state policies could alter disbursement 

 

opportunity to help short-cut the endless debates about limited merits of participa

funding in a network environment and about th

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. 

742. Other commenters make suggestions or requests for guidance that are similar t

other commenters’ recommendations for addit

above. For example, s

cally recalculated or reevaluated. Many commenters believe that changes to 

transmission system topology and amendm

 

543 “Postage stamp” here refers to regionwide allocation of the cost of a 

transmission facility. 
Docket No. RM10-23-000 - 517 -

wed 

ns 

 PUC states that a cost allocation method should be designed to 

on 

te 

of benefits, so the Final Rule should require cost allocations to be periodically revie

and recalculated.544 Some of these commenters believe that permanent cost allocatio

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

evolve and reflect system changes over time. 

743. Ohio Consumers Counsel and West Virginia Consumer Advocate Divisi

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 England recommends Commission-sponsored mediation or other alternative dispu

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 

 544 E.g., Sunflower and Mid-Kansas; Electricity Cons

Associated Industrial Groups; PUC of Ohio; East Texas Cooperatives; E.ON; and 

umers Resource Council 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. 
Docket No. RM10-23-000 - 518 -

of public policy dri ompany believes the 

nt 

ic 

and 

ven projects.546 FirstEnergy Service C

Commission should clarify that the cost causation principle, including the requireme

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 publ

policy cost allocations. Transmission Dependent Utility Systems notes that not all 

projects proposed to implement public policy are worthy of presumptive acceptance 

should be rigorously scrutinized in the stakeholder process. 

b. Commission Determination

745. The Commission appreciates interested commenters’ views, suggestions and 

requests for additional Commission guidance regarding the development of an acce

cost allocation method or methods to comply with the identified cost allocation principles 

for new regional and interregional transmission facilities. We believe, how

ptable 

ever, 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 

 

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. 

546
Docket No. RM10-23-000 - 519 -

nduly 

ord public utility transmission providers in individual transmission planning 

equested 

tent 

st 

o 

ove 

e presented and evaluated at the regional level and, if agreed upon, 

 

method or methods to facilitate the development of a just and reasonable and not u

discriminatory or preferential cost allocation method or methods. Additionally, the 

principles aff

regions the flexibility necessary to accommodate unique regional characteristics. The 

Commission is concerned that providing the additional guidance or limitations r

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 consis

with the six cost allocation principles. For example, East Texas Cooperatives sugge

periodic reevaluation of cost allocation methods to respond to system changes. We d

not view such a proposal as inconsistent with the cost allocation principles adopted ab

and, as such, it could b

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 

547 See discussion supra section III.E.7. 
Docket No. RM10-23-000 - 520 -

nd other 

iple 6, we 

t types of 

s, and we will not prescribe a uniform method for such 

ind in 

t 

g to supersede the cost 

causation principle. Rather, these six principles serve as guidelines for public utility 

the cost causation principle. 

transmission providers to use the same cost allocation method for public policy a

types of transmission facilities. Instead, as discussed for Cost Allocation Princ

permit different regional and interregional cost allocation methods for differen

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 region

transmission projects. 

748. In response to Illinois Commerce Commission, the Commission declines to f

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 cos

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 attemptin

transmission providers to use to create cost allocation methods that are consistent with 
Docket No. RM10-23-000 - 521 -

Consumer Advocate Division, and ISO New England about dispute resolution, the 

Commission believes that the dispute resolution processes in place under Or 90, 

enhanced as may be necessary to comply r 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 

inal Rule. 

G. Cost Allocation Matters Related to Other Commission Rules, Joint 

750. With regard to the concerns of Ohio Consumers’ Counsel, West Virginia 

der No. 8

with ou

We will review any changes to those dispute resolution procedures in response to 

compliance filings submitted in response to this F

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

 548 See, e.g., Idaho Power Co., 128 FERC ¶ 61,064 at P 30-40; Duke Energy 

Carolinas, LL or, 

6 

order on reh’g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. 

& Regs. ¶ 31,

 Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 

(continued...) 

C, 127 FERC ¶ 61,281, at P 38-41 (2009); New York Indep. Sys. Operat

Inc., 125 FERC ¶ 61,068, at P 61-64 (2008). 

549 Standardization of Generator Interconnection Agreements and Procedures, 

Order No. 2003, 68 FR 49846 (Aug. 18, 2003), FERC Stats. & Regs. ¶ 31,146, at P 67

(2003), 

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
Docket No. RM10-23-000 - 522 -

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. 

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 

 

 

(Jan. 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 2000-A, 

f’d sub nom. Pub. 

Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 

001). 

551

552 U.S. 1230 (2008). 

550 Regional Transmission Organizations, Order No. 2000, 65 FR 809 

65 FR 12088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), af

2

 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. 
Docket No. RM10-23-000 - 523 -

te 

s. 

n 

ion 

 If this continues, Bay Area 

unicipal Transmission Group asserts that greater transparency in the interconnection 

rnia Municipal Utilities argue that, if the costs of network upgrades 

 

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 Largescale Solar state that the Commission should require transmission providers to coordina

the transmission planning study process with the generator interconnection study proces

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 i

Order No. 2003 because they believe these are being used to circumvent the transmiss

planning process, creating a situation where load serving entities are forced to finance 

projects without project beneficiaries being identified.552

M

process is needed to facilitate the determination of the most cost-effective interconnection 

alternative. Califo

552 E.g., Bay Area Municipal Transmission Group; California Municipal Utilities; 

and City of Santa Clara. 
Docket No. RM10-23-000 - 524 -

 a 

t all 

cess. 

sion 

ns of 

e 

an 

ion 

identified through generator interconnection studies are borne by load within a region, 

those upgrades should be examined by the regional transmission planning process as

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 tha

interconnection-related network upgrades would be submitted through the request 

window open in each planning cycle and evaluated in the transmission planning pro

Northern California Power Agency asserts that the generator interconnection process 

includes a loophole whereby transmission providers can circumvent the transmis

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 mea

grid expansion. 

756. Several commenters discuss cost allocation for generation interconnection in th

context of public policy projects. For example, Imperial Irrigation District asks the 

Commission to clarify that generation interconnection customers and their off-takers c

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 Domin
Docket No. RM10-23-000 - 525 -

nsmission providers to describe in their respective 

ed to accommodate an interconnection 

thern Tier Transmission Group asserts that, if a transmission provider does not 

xecute an interconnection agreement with a generator, then the transmission provider 

has no mechanism to assess costs upon the generator. Northern Tier Transmission Group 

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 tra

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 need

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. Nor

e
Docket No. RM10-23-000 - 526 -

states that, to the extent th s this practical issue, it should 

ception that 

k 

b. Commission Determination

e Commission chooses to addres

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 miscon

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 networ

upgrades.

760.

ection of a large generating transmission facility to the bulk power system. This 

s for 

interco

out the 

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 

interconn

Final Rule does not set forth any new requirements with respect to such procedure

nnecting large, small, or wind or other generation facilities. Therefore, this Final

Rule is not the proper proceeding for commenters to raise issues ab
Docket No. RM10-23-000 - 527 -

 

dressing 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 

interconnection agreements and procedures under Order Nos. 2003,553 2006554 or 661.555

However, in not ad

for generator interconnections in developing assumptions to be used in the transmission 

planning process. 

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 

 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 S

Util. Comm’rs v. FERC, 4

, 

tats. & Regs. ¶ 31,190 , aff'd sub nom. Nat’l Ass’n of Regulatory 

75 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 

 Order No. 2006, 70 FR 34189, FERC Stats. & Regs. ¶ 31,180, order on reh’g, 

clarification, Order No. 2006-B, 71 FR 42587, FERC Stats. & Regs. ¶ 31,221. 

, 

(2008). 

554

Order No. 2006-A, 70 FR 71760, FERC Stats. & Regs. ¶ 31,196, order granting 

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. 
Docket No. RM10-23-000 - 528 -

m, 

place. 

 is not 

nt 

 funding, they are creating additional 

panca ish to utilize these new facilities. 

it states that stringing radial transmission over 

network faci ed only to avoid appropriate cost allocation. 

planning. Transmission Dependent Utility Systems submit that if the Commission is 

going to implement a requirement for regional cost allocation, it should, at a minimu

eliminate pancaked rates unless there is an existing regional cost allocation method in 

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

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 mercha

lines and allocate their costs through participant

ked rates for new generation owners who may w

Gaelectric North America argues that such pancaked rates inhibit the development and 

use of renewable resources. Further, 

lities is inefficient and pursu

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, 
Docket No. RM10-23-000 - 529 -

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 r

incentive policies of Order No. 679. 

a.

ate 

Comments

766. Some commenters suggest that the Commission revisit its policy on transm

rate incentives, as set forth in Order No. 679. For example, they relate the Commissio

proposals regarding nonincumbent transmission developers to transmission rate 

incentives.

ission 

n’s 

uild a transmission facility to forgo any incentives on that facility. It 

 

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 b

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 

556 E.g., New England States Committee on Electricity; Transmission Access 

Policy Study Group; and Southern California Edison.
Docket No. RM10-23-000 - 530 -

or 

ly 

ses 

Es 

n 

 that there is a clear causal connection between 

incenti

and reasonable rates. Joint Commenters also assert that the Commission has failed to 

significantly lower than the incentive rate of return the Commission has approved f

nonincumbent transmission developers. ITC Companies replies that such instances on

demonstrate that different transmission incentives have been awarded in different ca

by different regulatory bodies, noting that there are a variety of approved utility RO

across the industry. 

767. Other commenters tie the Commission’s cost allocation proposals to transmissio

rate incentives. For example, APPA states

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 

ves that they believe substantially exceed the incentives that would result in just 
Docket No. RM10-23-000 - 531 -

 and high unemployment. According to Joint Commenters, the rate of 

vice 

in the 

ectric 

 incentives for partnership in the development of major backbone projects 

s 

ent 

t are 

 

recognize that the financial ground has shifted, citing the recent recession, historically 

low interest rates,

return needed to attract investment in a long-lived asset used to provide monopoly ser

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. 

769. Pacific Gas & Electric recommends that the Commission clearly signal 

Final Rule that rate incentives are available for utilities that dedicate resources to the 

successful development of needed regional projects. In particular, Pacific Gas & El

suggests that

crossing multiple jurisdictions are appropriate. Pacific Gas & Electric suggests that 

incentives should be offered for partnerships to both independent transmission companie

and incumbent utilities, and that the incentives should be conditioned upon establishm

of development arrangements that ensure consistent design standards are used tha

 and 557 Incentive Ratemaking for Interstate Natural Gas Pipelines, Oil Pipelines,

Electric Utilities, 61 FERC ¶ 61,168 (1992). 
Docket No. RM10-23-000 - 532 -

is 

f 

9 of the FPA, to incent transmission 

investment. Som es not undermine transmission 

n 

. 679, and notes that Pacific Gas & Electric’s request is illuminating 

becau

such incentives and how they assume the Commission will simply rubber stamp in 

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 th

proceeding.558 Several commenters argue that such comments are beyond the scope o

this rulemaking. They note that Order No. 679 was implemented in response to the 

direction of Congress, codified in section 21

e commenters note that Order No. 679 do

planning and cost allocation processes because the grant of incentives is conditioned o

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

se it shows how accustomed investor-owned utilities have become to obtaining 

advance their requests for more incentives. 

b. Commission Determination

771. We acknowledge commenters concerns regarding the Commission’s policy on 

 

558 E.g., AEP; Edison Electric Institute; EIF Management; ITC Companies; 

National Grid; Pacific Gas & Electric; and PSEG Companies. 
Docket No. RM10-23-000 - 533 -

his 

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 t

proceeding.

Relationship of This Proceeding to the Proceeding on Variable 

559

4.

Energy Resources

a. Comments

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 

773. In its reply comments, Exel ission should address in this 

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 

pay for the additional transmission facilities that such integration requires.560 

on argues that the Comm

 559

policy on transmission incentives under Order No. 679. See Promoting Transmission 

 The Commission issued a Notice of Inquiry on May 19, 2011 regarding its 

Investment Through Pricing Reform, Notice of Inquiry, 135 FERC ¶ 61,146 (2011). 

560 APPA also incorporates by reference the comments it submitted in Docket No. 

RM10-11-000. 
Docket No. RM10-23-000 - 534 -

 the 

uiring 

ntegrating wind and other variable resources. 

 Determination

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

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 req

full accounting for the costs of i

b. Commission

774. This Final Rule establishes minimum requirements to guide the affected entities in 

hich 

es. The 

le, 

developing their own transmission planning processes and cost allocation methods, w

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 resourc

VERs proceeding, however, addresses operational issues. To the extent that entities 

consider it necessary or appropriate to consider such operational issues in this Final Ru

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 
Docket No. RM10-23-000 - 535 -

ffered reasonable opportunities for joint transmission ownership. 

APPA assert s and reduces the overall costs 

 out 

f 

nation

ownership and to require that eligibility for rate incentives depend on an applicant’s 

showing that it has o

s that joint ownership diversifies financial risk

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

that joint ownership spreads the risk of projects and provides a variety of sources o

capital for projects. 

b. Commission Determi

776. s 

proceeding. e, free to consider joint ownership 

 any 

t 

particularly large backbone facilities, both in terms of increasing opportunities for 

investment in the transmission grid, as well inatory access to the 

Specific financing techniques such as joint ownership are beyond the scope of thi

Transmission developers are, of cours

when proposing and developing a transmission project. Just as we are not requiring

specific cost allocation method, we do not specifically address joint ownership as a cos

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, 

as ensuring nondiscrim
Docket No. RM10-23-000 - 536 -

transmission grid by transmission customers.561 

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 

ame standards as those used for traditional transmission solutions, and that this could be 

urces 

tment 

778. FirstE Proposed Rule does not 

ded in 

 

s

done through a competitive solicitation. GridSolar notes that distributed energy reso

connect at voltages below 69 kV and therefore do not qualify for cost allocation trea

under the 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. 

nergy Service Company argues that while the

address cost recovery for non-transmission projects, only the costs of facilities that 

perform a transmission function (including energy storage projects) should be inclu

transmission rates. FirstEnergy Service Company argues that regional transmission 

planning processes should not be a vehicle for owners of generation or demand side 

. ¶ 31,241 at P 593. 561 Order No. 890, FERC Stats. & Regs
Docket No. RM10-23-000 - 537 -

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 

aintaining the approach taken in Order No. 890 and will require that generation, 

emand resources, and transmission be treated comparably in the regional transmission 

lanning process.562 However, while the consideration of non-transmission alternatives 

smission plan, we conclude that the issue of cost recovery for nonnsmission cost allocation reforms 

m

d

p

to transmission facilities may affect whether certain transmission facilities are in a 

regional tran

transmission alternatives is beyond the scope of the tra

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)). 
Docket No. RM10-23-000 - 538 -

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 publ

utility transmission provider to subm

ic 

it a compliance filing within six months of the 

effective date of the Final Rule in this proceeding. With regard to the proposed 

ments, 

al 

der meets the 

interregional transmission coordination and interregional cost allocation require

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 addition

orders as necessary to ensure that each public utility transmission provi

requirements of the Proposed Rule. 

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 

 

564 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 179. 
Docket No. RM10-23-000 - 539 -

t 

ed 

s 

 sixl is 

e 

 by a minimum of six months. 

ost 

ission 

ay of 

 

twelve-month compliance deadlines are far more generous than the 60-day deadline tha

the Commission provided for compliance with Order No. 888 and the filing of revis

power pooling and multilateral coordination agreements, respectively. 

782. Some commenters suggest that the Commission extend the compliance deadline

for up to three years.565 Indianapolis Power & Light and SPP state that the proposed

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 refusa

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 th

Commission should extend all compliance deadlines

Arizona Corporation Commission states that the Commission should recognize that m

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 transm

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 arr

Corporation Commission; and Arizona Public Service Company. 

565 E.g., Indianapolis Power & Light; SPP; MISO Transmission Owners; Arizona 
Docket No. RM10-23-000 - 540 -

 consensus with regional groups. 

ce 

e Public Power 

LS 

ight 

federal right of first refusal from jurisdictional OATTs and agreements. 

 

changes that will require utilities to develop positions, collaborate with neighboring 

utilities, and reach

783. Western Area Power Administration recommends that, in lieu of complian

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 Larg

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 

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 r

of first refusal, suggesting that any extension of compliance periods not apply to the 

 566 E.g., Northwest & Intermountain Power Procedures Coalition and LS Power. 
Docket No. RM10-23-000 - 541 -

 within the 

sort 

rn 

need 

ture, which 

te 

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

regional planning process should provide the planning regions adequate time to 

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 weste

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 

not proceed with urgency but should allow existing regional processes to ma

may lead to a more expeditious and effective transmission planning process. 

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 motiva

 567 E.g., New England States Committee on Electricity and Xcel. 
Docket No. RM10-23-000 - 542 -

tates 

ission should require a six-month compliance filing. 

ed. 

line is unattainable and the Commission 

ould 

ation 

allowing up to two years for compliance. Pennsylvania PUC states that interregional 

transmission providers to improve coordination with their adjacent regions. Exelon s

that for sets of regions that currently have Commission-approved joint operating 

agreements, the Comm

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 involv

Xcel agrees that the proposed one-year dead

should allow more time for interregional planning and cost allocation initiatives to 

develop voluntarily. 

788. Duke and Georgia Transmission Corporation state that the Commission sh

provide two years to submit interregional transmission planning agreements, given the 

number of parties that may be involved and the difficulties of developing cost alloc

methods. Edison Electric Institute requests that the Commission be flexible regarding 

compliance deadlines for interregional agreements and cost allocation and consider 
Docket No. RM10-23-000 - 543 -

s. 

l Order 

d 

hat 

existing processes, such as those used in California ISO and ISO New England, are 

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 month

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 individua

No. 890 planning proceedings. Several commenters also urge the Commission to 

consider existing RTO or ISO cost allocation methods as compliant with the propose

cost allocation principles and to avoid reopening debates about regional cost allocation 

methods already approved by the Commission.568 Some of these commenters argue t

reasonable569 while others disagree.570

 568 E.g., California ISO; SoCal Edison; San Diego Gas & Electric; Eastern Mass. 

Consu w 

el. 

e that ISO New England’s current transmission 

planning and cost allocati

iance 

extent that a commenter believes that its concerns have not 

(continued...) 

mer Owned System; Northeast Utilities; MISO; New York ISO; NEPOOL; Ne

England States Committee on Electricity; Kansas Corporation Commission; and Xc

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 argu

on methods do not comply with this Final Rule. These 

concerns should be raised during the stakeholder process used to develop compl

with this Final Rule. To the 
Docket No. RM10-23-000 - 544 -

nging the 

ness of an existing Commission-approved method should bear a heavy burden 

en 

onal 

e 

principles. 

g a 

TO 

 

790. Several commenters state that the Commission should not lightly change existing 

regional cost allocation methods.571 For example, Duke states that parties challe

appropriate

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 op

and inclusive stakeholder process and that the regional cost allocation method either 

meets the Commission’s proposed cost allocation principles, or that the existing regi

cost allocation method is consistent with or superior to the requirement of thos

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 makin

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 R

in 

a protest to the compliance filing. 

571 E.g., Duke; New Jersey Board; Northeast Utilities; and Transmission 

Dependent Utility Systems. 

been resolved in the relevant compliance filing, it can raise those concerns at that time 
Docket No. RM10-23-000 - 545 -

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 th

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

at, 

 within twelve 

t(s) 

o the 

et 

at the 

transmission provider to meet the requirements of this Final Rule. 

 

months of the effective date of this Final Rule revising its OATT or other documen

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 t

Commission’s jurisdiction as necessary to demonstrate that it meets the requirements s

forth herein with respect to interregional transmission coordination procedures and an 

interregional cost allocation method or methods. As explained below, we expect th

twelve month and eighteen month deadlines provide sufficient time for each public utility

 572 See Appendix C for the pro forma Attachment K consistent with this Final 

Rule. 
Docket No. RM10-23-000 - 546 -

ide rates, 

preferential, and the need to build new transmission facilities that more 

nning and 

with stakeholders to develop transmission planning and cost 

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 prov

terms and conditions of jurisdictional service that are just and reasonable and not unduly

discriminatory or 

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 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. 

794. We find that the compliance time periods established in this Final Rule strike an 

appropriate balance between implementing needed reforms to transmission pla

cost allocation processes in a timely fashion and providing time for those involved in 

these processes to work 

allocation processes that conform with the requirements adopted herein. Moreover, we 

 573 This finding is supported by our discussion above in section II. 
Docket No. RM10-23-000 - 547 -

at 

tly 

2012 

ieu 

 or ISO and its public 

s 

osed OATT 

differ 

believe these compliance filing deadlines are compatible with the interests of those th

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 curren

collaborating on transmission planning to produce an initial long-term plan in midand 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 l

of compliance filings. 

795. In response to commenters’ requests, we clarify that an RTO

utility transmission provider members may make a compliance filing that demonstrate

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 prop

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 

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. 
Docket No. RM10-23-000 - 548 -

 in 

he 

r ISO’s 

n 

rohibit non-RTO/ISO members that are 

e 

to 

nsmission 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 

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

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 t

degree to which a particular RTO or ISO may already be in compliance. 

797. Furthermore, public utility transmission owners that are part of Commissionjurisdictional RTOs and ISOs may demonstrate compliance through that RTO’s o

compliance filing and are not required to make a separate compliance filing. This 

includes, in response to SPP, compliance with the interregional transmission coordinatio

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 p

geographically adjacent to and/or contiguous with an RTO/ISO from participating in th

RTO/ISO’s regional transmission planning process nor do we require an RTO/ISO 

admit nonmembers to its regional transmission planning process. The decision on 

whether to combine their tra
Docket No. RM10-23-000 - 549 -

 question. In addition, the OATT for the RTO or the ISO of 

which s a part should include commonly agreed-to 

well as to the two regions in

 a public utility transmission provider i

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 

 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-publ

utility transmission provider may satisfy the reciprocity condition in one of three way

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 Commissio

seeking a declaratory order that the propo

ic 

s. 

n 

sed reciprocity tariff substantially conforms to, 

or is su

(continued...) 

perior 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 
Docket No. RM10-23-000 - 550 -

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 211A575 on a case-by-case basis.576

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 refor

could conflict with its statutory obligations. Bonneville Power states that it is required by

statute to have Congressional approval before it can build facilities outside the Pacific 

 

ms 

whose transmission service the non-public utility transmission provider seeks to use. 

Second, the non-public utility transmission provider may

utility transmission provider under a bilateral agreement t

 provide service to a public 

hat satisfies its reciprocity 

the 

, 

 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 

obligation. Finally, the non-public utility transmission provider may seek a waiver of 

reciprocity condition from the public utility transmission provider. See Order No. 890

FERC Stats. & Regs. ¶ 31,241 at P 163. 

575

– (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. 
Docket No. RM10-23-000 - 551 -

ille 

ons, 

ee 

ation states that it is a federal power marketing 

ies to 

e a 

t of 

ty in 

t if 

Northwest or build major transmission facilities within the Pacific Northwest. Bonnev

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 obligati

Bonneville Power contends that it must retain the right to review each proposal and agr

to any proposed allocation of costs from another party. 

801. Western Area Power Administr

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 facilit

it. Western Area Power Administration also argues that requiring it to incorporat

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 Departmen

Energy delegated to the Commission. 

802. Bonneville Power requests that the Commission explain the effect of reciproci

the context of transmission planning and cost allocation. Bonneville Power states tha

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. 
Docket No. RM10-23-000 - 552 -

, 

h 

t 

e district commissions or city councils. Public Power Council thus argues that 

t 

s 

n 

ssion 

 Nos. 888 and 890 and the pro forma OATT do not 

Bonneville Power contends that if the Commission does not accept regional deviations

coordinated regional planning and cost allocation will likely be unworkable for bot

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 tha

may limit their ability to enter into contracts involving unknown future costs and that 

bind futur

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 tha

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 it

consent. 

804. Four G&T Cooperatives argues that the Commission does not have jurisdictio

under the FPA to require non-public utilities to participate in regional transmi

planning processes or to agree to regional cost allocation methods. It also argues that the

reciprocity provisions under Order
Docket No. RM10-23-000 - 553 -

ission 

owning members of an RTO or ISO. G&T 

 help 

 participation by non-jurisdictional entities in 

te in 

provide a basis for requiring non-public utilities to participate in regional transm

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 transmissionCooperatives 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 nonjurisdictional 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

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

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 participa

the regional transmission planning process and cost allocation mechanism development. 

Similarly, San Diego Gas & Electric suggests that Order No. 888’s reciprocity 
Docket No. RM10-23-000 - 554 -

at the 

 to the 

 FPA 

d that are not unduly discriminatory or 

is 

seon 

requirements be enforced, as necessary. Anbaric and PowerBridge also believe th

Final Rule should apply to all transmission providers, including to those subject

Commission’s reciprocity requirements. 

807. A number of commenters also address the Commission’s authority under

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 an

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 

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 ca

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 Commissi
Docket No. RM10-23-000 - 555 -

 the 

g for regional 

ility. 

nd 

t 

ng 

 request 

 890 to 

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

proposed reciprocity requirement would dramatically expand the commitment that nonpublic 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 fundin

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 ut

Sacramento Municipal Utility District urges the Commission to reconsider its proposal to 

invoke FPA section 211A authority on a case-by-case basis. It states that this is 

unnecessary, beyond the limited reciprocity requirements of Order Nos. 888 and 890, a

it is beyond the Commission’s authority. Western Area Power Administration states tha

FPA section 211A does not authorize the Commission to require unregulated transmitti

utilities to engage in regional transmission planning and cost allocation. 

810. Western Area Power Administration and National Rural Electric Coops

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

expand its authority over non-public utilities. Georgia Transmission Cooperative argues 

that the Commission has not provided evidence to support application of FPA section 
Docket No. RM10-23-000 - 556 -

nts that 

. 

th 

 invoke its authority under FPA section 211A. 

of FPA 

 the 

211A and that applying it would be inconsistent with prior Commission stateme

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 nonjurisdictional transmission providers as needed to achieve its goals, and they agree wi

the Commission’s decision not to

Colorado Independent Energy Association also recommends that to avoid the use 

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

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 
Docket No. RM10-23-000 - 557 -

 include all transmission 

s 

 any of 

American 

m 

e 

Commission should use this authority if it intends to achieve its stated objectives on a

non-discriminatory basis. MidAmerican believes that failure to

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 requirement

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

the initial comments, provide evidence that supports invoking FPA section 211A, either 

on a case-by-case basis or generically. Bonneville Power disagrees with Mid

that public utility transmission providers would be subject to undue discrimination if nonpublic 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 fro

discrimination by non-public utilities. Large Public Power Council disagrees that th

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 
Docket No. RM10-23-000 - 558 -

tes that the Commission cannot accomplish indirectly through its 

recipr rectly under the statute. 

s 

proceeding. It also sta

ocity provisions what it cannot accomplish di

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 purpose

over a wide range of entities, thereby confirming that express direction from Congress is 

required before the Commission can exercise jurisdiction over otherwise nonjurisdictional entities. 

3. Commission Determination

815. To maintain a safe harbor tariff, a non-public utility transmission provide

ensure that the provisions of that tariff substantially conform, or are superior, to the

forma OATT as it has been revised by this Final Rule. As noted in the Proposed Rule, 

we are encouraged, based on the

r must 

pro 

 efforts that followed Order No. 890, that both public 

gional 

-

inds 

utility and non-public utility transmission providers collaborate in a number of re

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 f
Docket No. RM10-23-000 - 559 -

ess 

n 

n above, we decline to adopt SPP’s suggestion that the 

st 

blic 

by 

le.577 

 

on the appropriate record that non-public utility transmission providers are not 

participating in the transmission planning and transmission cost allocation proc

required by this Final Rule, the Commission may exercise its authority under FPA sectio

211A on a case-by-case basis. 

816. Given our decisio

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 co

allocation processes required by this Final Rule. Rather, it remains up to each non-pu

utility transmission provider whether it wants to maintain its safe harbor status 

meeting the transmission planning and cost allocation requirements of this Final Ru

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. 
Docket No. RM10-23-000 - 560 -

s 

. 

n 

ssion 

ith 

e Commission expects all public utility and nonpublic utility transmission providers to participate in the transmission planning and cost 

 

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 thi

time, to invoke our authority under that 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 transmissio

planning processes are comprised of both public and non-public utility transmi

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 w

the approach taken in Order No. 890, th

578 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 43. 
Docket No. RM10-23-000 - 561 -

hat 

 

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 t

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. 

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 nonpublic 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 

579 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 163. 
Docket No. RM10-23-000 - 562 -

isagree 

city to expand our jurisdiction over non-public 

ice. 

 conflict 

n 

 cost 

d 

We disagree with National Rural Electric Coops that our discussion of FPA 

 on a 

l 

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 

service, therefore, must do so on terms that satisfy the reciprocity condition. We d

that we are using the principle of recipro

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 serv

820. While a number of commenters argue that this Final Rule’s reforms could

with their statutory obligations, no specific conflict has been presented for us to act on i

this Final Rule. Concerns about possible conflicts should be raised in transmission

allocation discussions and any subsequent Commission proceedings on propose

transmission cost allocation methods. 

821.

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

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 additiona

arguments concerning the scope of our authority under section 211A given that we are
Docket No. RM10-23-000 - 563 -

 section 211A because we are not applying it 

al 

rs will participate voluntarily. 

proceeding to support the application of FPA

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 Fin

Rule does not include any such explicit requirement and instead only notes an 

expectation that non-public utility transmission provide

VI. Information Collection Statement

823. The Office of Management and Budget (OMB) requires that OMB approve certa

information collection and data retention requirements imposed by agency rules.

in 

on 

ed 

 

580 Up

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. 

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 solicit

580 5 C.F.R. 1320.11(b). 

581 44 U.S.C. 3507(d). 
Docket No. RM10-23-000 - 564 -

 estimates, ways to enhance the quality, utility, 

on 

 these processes. As an example, Arizona Public Service Company states that 

rizona 

regional transmission planning processes, including transportation, lodging, and meal 

expenses. 

comments on the need for this information, whether the information will have practical 

utility, the accuracy of provided burden

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 Commissi

burden estimate in the Proposed Rule. 

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

it participates in WestConnect, which in the past twelve months has involved over two 

dozen regional or subregional transmission planning meetings. According to A

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 
Docket No. RM10-23-000 - 565 -

ule 

is 

l 

oes 

than the minimum set forth in this Final Rule, which may 

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 R

represent the incremental burden changes related only to the requirements set forth in th

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 regiona

transmission planning processes on how to comply with the Commission’s rules, it d

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 

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 

 582 5 C.F.R. 1320.3(b)(1)-(2). 
Docket No. RM10-23-000 - 566 -

et 

d Rule. 

ic 

es in the 

roposed Rule are reasonable estimates of the average national rates for the employees 

 Commission has included, rden estimate, the r o

si er ma ve pa in a reg

s and interregional transmission ion procedures. 

ation Collection Costs

estimates. Thus, for the most part, the Commission adopts the burden estimates that it s

out in the Propose

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 publ

utility transmission provider is located. Therefore, we find that the averag

P

described below. 

828. Finally, the

that a public utility transmis

transmission planning proc

 in its bu

y need to tra

 numbe

te

f hours 

on provid l to partici ional 

es coordinat

Burden Estimate and Inform : The estimated Public Reporting 

burden and cost for the requirements contained in this Final Rule follow. 

FERC-917 - Proposed Reporting 

Requirements in RM10-23 

Annual 

Number of 

Respondents 

(Filers) 

Annual 

Number of 

Responses 

Hours per 

Response 

Total 

Annual 

Hours 

in Year 

1 

Total Annual 

Hours in 

Subsequent 

Years 

Participation in a transparent and 

open regional transmission plan

process that meets regional 

transmission planning principles, 

ning 

includes consideration of 

transmission needs driven by Public 132 132

110 hrs in 

Year 1; 52 

hrs in

subsequent 

years 14520 6864
Docket No. RM10-23-000 - 567 -

Cost to

Policy Requirements, identifies and 

evaluates transmission facilities to 

meet needs, develops cost 

allocation method(s), and produces 

a regi lan that 

describ

allocation me

Comm

onal transmission p

es and incorporates a cost 

thod(s) that meets the 

ission's principles. 

Development

transm ssion 

procedures that meet the 

Comm ts, 

including the ongoing requirement 

to pro

transmission planning information 

and p

as well as the development of a cost 

alloca

transm

the C 132 132

133 hrs in 

Year 1; 43 

years 17556 5676

 of interregional 

i coordination 

ission’s requiremen

vide or post certain 

rovide annual data exchange, 

tion method for interregional 

ission facilities that meets 

ommission's principles. 

hrs in 

subsequent 

Confo

transm

those

transm

Policy

conforming tariff changes for 

interregional transmission 

57 hrs in 

Year 1; 25 

subsequent 

3300

rming tariff changes for local 

ission planning, including 

 related to consideration of 

ission needs driven by Public 

 Requirements; and 

regional transmission planning and 

coordination. 132 132

hrs in 

years 7524 

Total Estimated Additional 

15840

Burden Hours, Proposed for 

FERC-917 in NOPR in RM10-23 39600 

 Comply: 
Docket No. RM10-23-000 - 568 -

 Year 1: $4,514,400 or [39,600 hours X $114 per hour583] 

 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 and reasonable and not unduly discriminatory or preferential. We 

n 

 

expect to achieve this goal through this Final Rule by reforming electric transmissio

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). 
Docket No. RM10-23-000 - 569 -

ion: 

hone: (202) 395-4638, 

s, comments should be sent electronically 

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 [Attent

Desk Officer for the Federal Energy Regulatory Commission, p

fax (202) 395-7285]. Due to security concern

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 

 584 Regulations Implementing the National Environmental Policy Act, Order No. 

486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). 
Docket No. RM10-23-000 - 570 -

at 

is

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. The reforms herein do not require transmission 

or other facilities to be built, but rather establish transmission planning mechanisms th

will result in a more appropriate allocation of costs and thus better ensure just and 

reasonable and not unduly discriminatory or preferential rates. 

VIII.

585

Regulatory Flexibility Act Analys

y Act of 1980 (RFA)586 generally requires a description 

l or 

 of the 

a OATT is 132. Of these public utility transmission providers, 

832. The Regulatory Flexibilit

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, contro

operate interstate transmission facilities other than those that have received waiver

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 form

 585 18 C.F.R. 380.4(a)(15). 

586 5 U.S.C. 601-612. 
Docket No. RM10-23-000 - 571 -

f these 

aiver 

t 

der Order Nos. 888, 889, and 890. Accordingly, 

ct 

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 o

entities retains its rights to request waiver of these requirements. The criteria for w

that would be applied under this rulemaking for small entities is unchanged from tha

used to evaluate requests for waiver un

the Commission certifies that this Final Rule will not have a significant economic impa

on a substantial number of small entities. 

IX. Document Availability

833. In addition to publishing the full text of this document in the Federal Re

Commission provides all intereste

gister, the 

d persons an opportunity to view and/or print the 

mmission’s Home Page 

rmal 

ailable 

 

contents of this document via the Internet through the Co

(http://www.ferc.gov) and in the Commission’s Public Reference Room during no

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 av

on eLibrary. The full text of this document is available on eLibrary in PDF and 

ily 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.” 

587 A firm is “small” if, including its affiliates, it is primar
Docket No. RM10-23-000 - 572 -

, printing, and/or downloading. To access this 

, type the docket number excluding the last three digits of this 

g 

ess hours from FERC Online Support at (202)502-6652 (toll free at 1-866-

08-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at 

(202) 502-8371, TTY (202) 502-8659. E-mai oom at 

public.referenceroom@ferc.gov. 

X. Effective Date and Congressional Notification

Microsoft Word format for viewing

document in eLibrary

document in the docket number field. 

835. User assistance is available for eLibrary and the Commission’s web site durin

normal busin

2

l the Public Reference R

836. These regulations are effective [insert date 60 days after publication in the 

FEDERAL REGISTER]. 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. 
Docket No. RM10-23-000 - 573 -

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, wit

statement attached. 

h a separate 

( S E A L ) 

tary. 

Nathaniel J. Davis, Sr., 

Deputy Secre
Regulatory Text 

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 

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. 

2. Amend § 35.28 as follows: 

a. Paragraph (c)(1) through (c)(1)(iii) are revised. 

b. Paragraph (c)(1)(vi) is revised. 

c. Paragraphs (c)(3), (c)(3)(i), and (c)(3)(ii) are revised. 

d. Paragraphs (c)(4) through (c)(4)(ii) are revised. 

e. Paragraph (d) (1) is revised. 

f. Paragraph (e)(1) is revised. 

§ 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, 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 
Docket No. RM10-23-000 - 575 -

 on Open Access Reforms) and 

n 

. & 

C Stats. 

ng rates, must be filed no later than 60 days prior to 

the dat

and Stranded Costs), as revised by the open access pro forma tariff contained in Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 (Final Rule

further revised in Order No. 1000, FERC Stats. & Regs. ¶ ______ (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 Commissio

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. ¶ ______. 

(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, FER

& Regs. ¶ ______, and accompanyi

e 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 [insert date that is 60 days 

after date of publication of the Final Rule in the FEDERAL REGISTER], 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. ¶ ____, pursuant to section 

206 of the FPA and accompanying rates pursuant to section 205 of the FPA in 
Docket No. RM10-23-000 - 576 -

accordance with the procedures set forth in Order No. 890, FERC Stats. & Regs. ¶ 31,241 

and Order No. 1000, FERC Stats. & Regs ¶ ____. 

(iii) If a public utility owns, controls, or operates transmission facilities used for

the transmission of electric energy in interstate commerce as of [insert date that is 60 

days after date of publication of the Final Rule in the FEDERAL REGISTER], 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

revisions to the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ 

31,241 as amended by Order No. 1000, 

 the 

FERC Stats. & Regs. ¶ ____, pursuant to section 

ats. 

C Stats. & Regs. ¶ ______, must demonstrate 

s 

he 

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 St

& Regs. ¶ 31,241 and Order No. 1000, FER

that the deviation is consistent with the principles of Order No. 888, FERC Stats. & Reg

¶ 31,036, Order No. 890, FERC Stats. & Regs. ¶ 31,241, and Order No. 1000, FERC 

Stats. & Regs. ¶ ______. 

* * * * * 

 (3) Every public utility that owns, controls, or operates facilities used for t
Docket No. RM10-23-000 - 577 -

oint 

r 

ats. & Regs. ¶ ______, or such other open access 

mmission consistent with Order No. 888, FERC 

 No. 

e 

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 j

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 furthe

revised in Order No. 1000, FERC St

tariff as may be approved by the Co

Stats. & Regs. ¶ 31,036, Order No. 890, FERC Stats. & Regs. ¶ 31,241, and Order

1000, FERC Stats. & Regs. ¶ ______. 

 (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 [insert date that is 60 days after date of publication of the Final Rule in th

FEDERAL REGISTER], 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-latera

arrangement or agreement that contains transmission rates, term

l 

s or conditions and that is 

executed on or before [insert date that is 60 days after date of publication of the Final 

Rule in the FEDERAL REGISTER], a public utility member of such power pool, public

utility holding company or other multi-lateral arrangement or agreement that owns, 
Docket No. RM10-23-000 - 578 -

ts. & Regs. ¶ 31,241 as 

e 

e 

bility for transmission services, including ancillary services, over such facilities. 

Such ta o a t f co ned in Order No. 888, FERC Stats. & Regs. 

¶ 31,03 s r

000, FERC Stats. & Regs. ¶ ______, or 

 may be approved by the Commission consistent with 

Order egs. ¶ 

31,241 O

 FERC Stats. & Regs. ¶ ____, 

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 Sta

amended by Order No. 1000, FERC Stats. & Regs. ¶ ____, pursuant to section 206 of th

FPA and accompanying rates pursuant to section 205 of the FPA in accordance with th

procedures set forth in Order No. 890, FERC Stats. & Regs. ¶ 31,241 and Order No. 

1000, FERC Stats. & Regs ¶ ____. 

* * * * * 

 (4) Consistent with paragraph (c)(1) of this section, every Commissionapproved ISO or RTO must have on file with the Commission a tariff of general 

applica

riff must be the pr form arif ntai

6, a evised by the pro forma tariff contained in Order No. 890, FERC Stats. &

Regs. ¶ 31,241 and further revised in Order No. 1

such other open access tariff as

No. 888, FERC Stats. & Reg. ¶ 31,036, Order No. 890, FERC Stats. & R

, and rder No. 1000, FERC Stats. & Regs. ¶ ______ . 

(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,
Docket No. RM10-23-000 - 579 -

suant to section 206 of the FPA and accompanying rates pursuant to section 205 of the 

PA in accordance with the procedures set forth in Order No. 890, FERC Stats. & Regs. 

 31,241 and Order No. 1000, FERC Stats. & Regs ¶ ____. 

(ii) If a Commission-approved ISO or RTO can demonstrate that its existing 

pen access tariff is consistent with or superior to the revisions to the pro forma tariff 

tariff in Orde rder No. 

1000, FERC Stats. & Regs. ¶ ______, or any portions thereof, the Commission-approved 

ISO or RTO may instead set forth such demonstr tion in its filing pu ction 206 

in e wi r No. 1000, FERC Stats. & Regs ¶ 

__

(d) Waiv

pur

F

¶

o

contained in Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised by the pro forma 

r No. 890, FERC Stats. & Regs. ¶ 31,241 and further revised in O

a rsuant to se

 accordanc

__. 

th the procedures set forth in Orde

ers. * * * 

ter than [insert date that is 60 days af

DERAL REGISTER

(1) No la ter date of publication of the 

Final Rule in the FE ], or 

* * * 

(e) Non-p compliance. 

* * 

ublic utility procedures for tariff reciprocity 

(1) A non submit a transmission tariff and a request for 

de laratory order th e requirements of Order 

No. 888, FERC Sta ats. & Regs. ¶ 31,241, 

and Order No. 1000

-public utility may 

c at its voluntary transmission tariff meets th

ts. & Regs. ¶ 31,036, Order No. 890, FERC St

, FERC Stats. & Regs. ¶ ______ . 
Docket No. RM10-23-000 - 580 -

* * * 

Note: The following appendices will not be published in the Code of Federal Regulations

* * 

. 

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 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. 

Section III.A. 

12 months Submit revised Attachment K of 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. 

Section III.C. 

18 months Submit revised Attachment K of 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. 

Section IV.C. 

18 months Submit revised Attachment K of the pro Section IV.D. 
Docket No. RM10-23-000 - 581 -

jurisdictional documents to include a cost 

on consistent 

with the principles of this Final Rule. 

forma OATT and any other Commission 

allocation method or methods for 

interregional cost allocati
Docket No. RM10-23-000 - 582 -

 Abbreviated Names of 

co

commenters that are used in this F

Abbreviation Initial Commenter(s) 

26 Public Interest lliance for Clean Energy New York; Citizens 

 Energy 

roject; Conservation Law Foundation; Earthjustice; 

ronmental Defense 

und; Environmental Law & Policy Center; Fresh 

 for Market 

ransformation; Iowa Environmental Council; Land 

y; Natural 

esources Defense Council; Pennsylvania Land 

W 

nergy Coalition; Pace Energy and Climate Center; 

oject for 

ustainable FERC Energy Policy; Sierra Club; 

; The Wilderness 

Society; Union of Concerned Scientists; and 

Western Grid Group 

alition of 

outheastern Utilities 

Central Electric Power Cooperative, Inc.; Dalton 

Utilities; Georgia Transmission Corporation; JEA; 

mpany, LLC (on behalf 

f Progress Energy Carolinas, Inc. and Progress 

as 

ompany; South Carolina Public Service Authority 

AEP merican Electric Power Service Corporation 

Appendix B: Commenters 

The following two tables ntain the abbreviated names of initial and reply

inal Rule. 

Initial Commenters

Organizations 

A

Utility Board of Wisconsin; Climate and

P

Environment Northeast; Envi

F

Energy; Great Plains Institute; Institute

T

Trust Alliance; National Audubon Societ

R

Trust Alliance; Nevada Wilderness Project; N

E

Piedmont Environmental Council; Pr

S

Southern Alliance for Clean Energy

Ad Hoc Co

S

MEAG Power; Orlando Utilities Commission; 

Progress Energy Service Co

o

Energy Florida, Inc.); South Carolina Electric & G

C

(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) 

A
Docket No. RM10-23-000 - 583 -

Abbreviation Initial Commenter(s) 

Alabama PSC labama Public Service Commission 

mpanies 

ny; 

ny Interstate Line Company; and 

llegheny Energy Supply Company, LLC 

ALLETE ALLETE, Inc. 

nergy es, Inc. 

stitute 

American Forest & Paper merican Forest & Paper Association 

American Transmission 

Anbaric and PowerBridge nbaric Holding, LLC; PowerBridge, LLC 

APPA blic Power Assocation 

Commission 

Arizona Public Service 

Company 

Atlantic Grid 

Avista and Puget Sound Inc. 

AWEA 

; 

A

Allegheny Energy Co Monongahela Power Company; The Potomac 

Edison Company; West Penn Power Compa

Trans-Alleghe

A

Alliant E Alliant Energy Corporate Servic

American Antitrust In American Antitrust Institute 

A

American Transmission Company LLC 

A

American Pu

Arizona Corporation Arizona Corporation Commission 

Arizona Public Service Company 

Atlantic Grid Development, LLC on behalf of 

Atlantic Wind Connection 

Avista Corporation and Puget Sound Energy, 

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 
Docket No. RM10-23-000 - 584 -

Abbreviation Initial Commenter(s) 

Bay Area Municipal 

Transmission Group 

Bonneville Power 

Boundless Energy and Sea oundless Energy, LLC and Sea Breeze Pacific 

Brattle Group (The) eter Fox-Penner; Johannes Pfeifenberger; and 

California Commissions 

California ISO t System Operator 

orporation 

California Municipal Utilities alifornia Municipal Utilities Association (Cities of 

g; Burbank; 

Cerritos; Colton; Corona; Glendale; Gridley; 

Healdsburg; Hercules; Lodi; Lompoc; Moreno 

; 

 Cucamonga; Redding; Riverside; Roseville; 

Santa Clara; Shasta Lake; Ukiah; and Vernon; the 

Imperial; Merced; Modesto; Turlock Irrigation 

a Power Agency; 

outhern California Public Power Authority; 

 of Northern California; 

assen Municipal Utility District; Power and Water 

amento Municipal 

tility District; the Trinity and Truckee Donner 

California Transmission Imperial 

City of Santa Clara, California; the City of Palo 

Alto, California; and the City of Alameda, 

California 

Bonneville Power Administration 

Breeze 

B

Regional Transmission System 

P

Delphine Hou 

California Public Utilities Commission and the 

Energy Resources Conservation and Development 

Commission of the State of California 

California Independen

C

C

Alameda; Anaheim; Azusa; Bannin

Valley; Needles; Palo Alto; Pasadena; Pittsburg

Rancho

Districts; the Northern Californi

S

Transmission Agency

L

Resources Pooling Authority; Sacr

U

Public Utility Districts; the Metropolitan Water 

District of Southern California; and the City and 

County of San Francisco, and Hetch-Hetchy) 

Sacramento Municipal Utility District; the
Docket No. RM10-23-000 - 585 -

Abbreviation Initial Commenter(s) 

Planning Group rigation District; the Los Angeles Department of 

ublic 

Power Authority; the Transmission Agency of 

Northern California; the Turlock Irrigation District; 

California State Water Project te 

CapX2020 Utilities 

ative; Great River Energy; 

innesota Power; Minnkota Power Cooperative; 

innesota Municipal Power Agency; WPPI Energy; 

City and County of San ity and County of San Francisco 

Department of Water and 

and 

ower 

ara 

roup 

Clean Line lean Line Energy Partners LLC 

Coalition for Fair 

ission Policy 

MS Energy Corporation; Consolidated Edison; 

rtheast Utilities; PPL 

orporation; Progress Energy, Inc.; Public Service 

Corporation; Southern 

ompany; United Illuminating Company 

Ir

Water and Power; the Southern California P

the Southern California Edison Company; the 

Pacific Gas & Electric Company and the San Diego 

Gas & Electric Company 

California Department of Water Resources Sta

Water Project 

Central Minnesota Municipal Power Agency; 

Dairyland Power Cooper

M

Missouri River Energy Services; Otter Tail Power 

Company; Rochester Public Utilities; Southern 

M

and Xcel Energy Inc. 

Champlain Hudson Champlain Hudson Power Express, Inc. 

Francisco 

C

City of Los Angeles 

Power 

City of Los Angeles Department of Water 

P

City of Santa Cl City of Santa Clara, California 

Clean Energy G Clean Energy Group 

C

Transm

C

DTE Energy Company; No

C

Enterprise Group; SCANA 

C
Docket No. RM10-23-000 - 586 -

Abbreviation Initial Commenter(s) 

Colorado Independent Energy olorado Independent Energy Association 

ColumbiaGrid 

; Public Utility District No. 1 

n; 

d the City of Seattle, by and through its 

ity Light Department) 

Connecticut & Rhode Island onnecticut Department of Public Utility Control 

blic Utilities Commission 

dation 

Orange & Rockland 

k, Inc. 

Consumers Energy Company 

Dayton Power and Light 

DC Energy 

PSC ic Service Commission 

Dominion 

Duquesne Light Company 

Association 

C

ColumbiaGrid (Avista Corporation; Bonneville 

Power Administration

of Chelan County, Washington; Public Utility 

District No. 1 of Snohomish County, Washingto

Public Utility District No. 2 of Grant County, 

Washington; Puget Sound Energy, Inc.; City of 

Tacoma, Department of Public Utilities, Light 

Division; an

C

Commissions 

C

and the Rhode Island Pu

 

Conservation Law Foun

Consolidated Edison and 

Conservation Law Foundation 

Consolidated Edison Company of New Yor

and Orange and Rockland Utilities, Inc. 

Consumers Energy Company 

Dayton Power and Light Company (The) 

DC Energy, LLC 

Delaware Delaware Publ

Direct Energy Direct Energy Services, LLC; Direct Energy 

Business, LLC; and Energy America, LLC 

Dominion Resources Services, Inc. 

Duke Duke Energy Corporation 

Duquesne Light Company 
Docket No. RM10-23-000 - 587 -

Abbreviation Initial Commenter(s) 

EARTHJUSTICE 

East Texas Cooperatives 

Eastern Massachusetts 

Consumer-Owned System 

ghting Plant; and Wellesley Municipal 

ight Plant 

Edison Electric Institute dison Electric Institute 

EIF Management 

Electricity Consumers 

Resource Council and the 

Associated Industrial Groups 

ican 

sociation; Coalition of Midwest 

ransmission Customers; Florida Industrial Power 

rgia Industrial Group-Electric; 

dustrial Energy Users – Ohio; Oklahoma 

Customer Coalition; West Virginia Energy Users 

Group; and Wisconsin Industrial Energy Group 

Enbridge Enbridge Inc. 

Energy Consulting Group Energy Consulting Group LLC (representing Central 

 Diverse Power 

corporated; Pataula EMC; Snapping Shoals EMC; 

Energy Future Coalition 

Group 

ergy 

ation; 

EARTHJUSTICE 

East Texas Electric Cooperative, Inc.; Northeast 

Texas Electric Cooperative, Inc.; Tex-La Electric 

Cooperative of Texas, Inc.; Sam Rayburn G&T 

Electric Cooperative 

Belmont Municipal Light Department; Braintree 

Electric Light Department; Concord Municipal 

Light Plant; Hingham Municipal Lighting Plant; 

Reading Municipal Light Department; Taunton 

Municipal Li

L

E

EIF Management, LLC 

Electricity Consumers Resource Council; Amer

Chemistry Council; Association of Businesses 

Advocating Tariff Equity; Carolina Utility 

Customers As

T

Users Group; Geo

In

Industrial Energy Consumers; PJM Industrial 

Georgia EMC; Cobb EMC;

In

Upson EMC; and Washington EMC) 

Energy Future Coalition; Alliance for Clean En

New York, Inc.; American Wind Energy 

Association; BrightSource Energy, Center for

American Progress, Conservation Law Found
Docket No. RM10-23-000 - 588 -

Abbreviation Initial Commenter(s) 

st 

t, 

oup; Mid-Atlantic 

enewable Energy Coalition; Natural Resources 

est Project; 

ierra Club; Solar Energy Industries Association; 

; 

merica; and Western 

rid Group 

Environmental Defense Fund nvironmental Defense Fund 

al NGOs Environmental Non-Governmental Organizations 

(Environmental Integrity Project; Izaak Walton 

 Michigan 

Environmental Council; Ohio Citizen Action; 

Natural Resources Defense Council; Fresh Energy; 

ierra Club; and 

Earthjustice) 

te & Renewables 

orth America 

Renewables North America, LLC 

xelon Exelon Corporation 

ederal Trade Commission Federal Trade Commission 

irst Wind First Wind Energy, L.L.C. 

ervice Company FirstEnergy Service Company, on behalf of 

FirstEnergy Companies: Ohio Edison Company; 

nd 

Electric Illuminating Company; The Toledo Edison 

Incorporated; Jersey Central Power & Light 

Environmental Northeast; Fresh Energy; Interwe

Energy Alliance; Invenergy Thermal Developmen

LLC; Invenergy Wind Development, LLC; ITC 

Holdings, Corp.; Mesa Power Gr

R

Defense Council; Renewable Northw

S

The FERC Project; The Stella Group, Ltd.; The 

Wilderness Society; Union of Concerned Scientists

Utility Workers Union of A

G

E

Environment

League of America; Clean Air Council;

Citizens for Pennsylvania’s Future; S

E.ON E.ON U.S. LLC 

E.ON Clima

N

E.ON Climate & 

E

F

F

FirstEnergy S

Pennsylvania Power Company; The Clevela

Company; American Transmission Systems,
Docket No. RM10-23-000 - 589 -

Abbreviation Initial Commenter(s) 

Company; Metropolitan Edison Company; and 

rstEnergy 

Solutions Corp. and their respective electric utility 

Florida PSC 

Four G&T Cooperatives ic 

 and 

Gaelectric North America 

Georgia Transmission 

Corporation 

Governors of Delaware and 

Maryland 

Grasslands 

Green Energy and 21st 

Century s, LLC 

Horizon Wind Energy 

Iberdrola Renewables newables, Inc. 

erez-Arriaga 

Illinios Commerce 

Commission 

erce Commission 

perial Irrigation District Imperial Irrigation District 

dependent Energy 

ion 

Independent Energy Producers Association 

Pennsylvania Electric Company, and Fi

subsidiaries and affiliates 

Florida Public Service Commission 

Associated Electric Cooperative; Basin Electr

Power Cooperative; and Tri-State Generation

Transmission Association 

Gaelectric North America 

Georgia Transmission Corporation 

Governors of Delaware and Maryland 

Grasslands Renewable Energy LLC 

Green Energy Express LLC and 21st Century 

Transmission Holding

Grid Solar Grid Solar, LLC 

Horizon Wind Energy LLC 

Iberdrola Re

Ignacio P Ignacio J. Perez-Arriaga 

Illinois Comm

Im

In

Producers Associat
Docket No. RM10-23-000 - 590 -

Abbreviation Initial Commenter(s) 

Indianapolis Power & Light 

Indicated PJM Transmission 

Owners 

omac 

dison Company and West Penn Power Company; 

merican Transmission Systems, 

corporated; Jersey Central Power & Light 

ings, 

lmarva 

rgy, 

ia Electric 

Integrated Transmission 

Benefits Model Proponents 

cate; 

ity; 

Integrys Wisconsin c Service Corporation; Upper 

eninsula Power Company; and Integrys Energy 

Invenergy venergy Wind Development LLC 

land ISO New England Inc. 

nt System Operator; ISO New 

Indianapolis Power & Light Company 

Monongahela Power Company; The Pot

E

and Trans-Allegheny Interstate Line Company; 

Baltimore Gas and Electric Company; The Dayton 

Power and Light Company; Duquesne Light 

Company; A

In

Company; Metropolitan Edison Company; 

Pennsylvania Electric Company; Pepco Hold

Inc.; Potomac Electric Power Company; De

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 Ene

LLC; Public Service Electric and Gas Company; 

PSEG Power LLC; PSEG Energy Resources & 

Trade LLC; UGI Utilities, Inc.; and Virgin

and Power Company 

Maine PUC; Maine Office of the Public Advo

Maine Office of Energy Independence and Secur

New Hampshire Public Utilities Commission; 

Environment Northeast; and Conservation Law 

Foundation 

Publi

P

Services, Inc. 

ISO New Eng

In

ISO/RTO Council California Independe
Docket No. RM10-23-000 - 591 -

Abbreviation Initial Commenter(s) 

ngland, Inc.; Midwest Independent Transmission 

t 

.C.; 

ITC Companies 

st 

Joint Commenters 

source Council; Indiana 

tility Regulatory Commission; Modesto Irrigation 

ce Commission; 

ational Association of State Utility Consumer 

erence of Public 

tility Commissioners; New Hampshire Office of 

ivision of Rate 

ounsel; New York State Public Service 

ominion Electric Cooperative; Sacramento 

e 

ublic Advocate; Transmission Agency of Northern 

ce Board 

Greater Missouri 

d KCP&L 

Greater Missouri Operations Company 

ation 

ommission 

Land Trust Alliance iance 

E

System Operator, Inc.; New York Independen

System Operator, Inc.; PJM Interconnection, L.L

Southwest Power Pool, Inc. 

International Transmission Company; Michigan 

Electric Transmission Company, LLC; ITC Midwe

LLC; ITC Great Plains, LLC; and Green Power 

Express LP 

American Chemistry Council; American Forest & 

Paper Association; American Public Power 

Association; California Municipal Utilities 

Association; California Public Utilities Commission; 

Electricity Consumers Re

U

District; Montana Public Servi

N

Advocates; New England Conf

U

Consumer Advocate; New Jersey D

C

Commission; Office of the Nevada Attorney 

General, Bureau of Consumer Protection; Old

D

Municipal Utility District; South Dakota Public 

Utilities Commission; State of Maine, Office of th

P

California; Utility Reform Network; Vermont

Department of Public Service; and Vermont Public 

Servi

Kansas City Power & Light 

and KCP&L 

Kansas City Power & Light Company an

Kansas Corpor

C

Kansas Corporation Commission 

Land Trust All
Docket No. RM10-23-000 - 592 -

Abbreviation Initial Commenter(s) 

 Power 

r and 

ower 

ty; 

ver 

Long Island Power Authority 

LS Power 

Maine PUC aine Public Utility Commission 

tral Maine 

Power Company; and Maine Public Service 

f Public Utilities and 

assachusetts Department of Energy Resources 

Massachusetts Municipal and 

New Hampshire Electric 

Citizens Against 

Rate Excess 

ompany 

t System Transmission 

perator, Inc. 

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

Authority; Los Angeles Department of Powe

Power; Lower Colorado River Authority; MEAG

Power; Nebraska Public Power District, New York 

Power Authority; Omaha Public Power District;

Orlando Utilities Commission; Platte River P

Authority; Puerto Rico Electric Power Authori

Sacramento Municipal Utility District; Salt Ri

Project; Santee Cooper; Seattle City Light; 

Snohomish County Public Utility District No. 1; and

Tacoma Public Utilities 

Long Island Power Authority 

LS Power Transmission, LLC 

M

Maine Utilities Bangor Hydro Electric Company; Cen

Massachusetts Departments Massachusetts Department o

M

Massachusetts Municipal Wholesale Electric 

Company and New Hampshire Electric Cooperative, 

Inc. 

Michigan Michigan Citizens Against Rate Excess 

MidAmerican MidAmerican Energy Holdings C

MISO Midwest Independen

O
Docket No. RM10-23-000 - 593 -

Abbreviation Initial Commenter(s) 

MISO Transmission Owners meren Services Company (as agent for Union 

blic Service 

ompany; Central Illinois Light Co., and Illinois 

Power Company); American Transmission 

t & Power 

(Springfield, IL); Dairyland Power Cooperative; 

Great River Energy; Hoosier Energy Rural Electric 

Company; MidAmerican Energy Company; 

subsidiary Superior 

Water, L&P); Montana-Dakota Utilities Co.; 

thern 

States Power Company (Minnesota and Wisconsin 

corporations); Northwestern Wisconsin Electric 

ipal 

Minnesota PUC and 

Minnesota Office of Energy 

Security 

y 

Modesto Irrigation District odesto Irrigation District 

y Commenters American Electric Power Corp.; AWEA, Energy 

Future Coalition; Iberdrola Renewables; ITC 

Mesa 

Power Group, LLC; NextEra Energy, Inc.; and SEIA

ARUC National Association of Regulatory Utility 

National Audubon Society 

National Grid 

A

Electric Company, Central Illinois Pu

C

Company LLC; City Water, Ligh

Cooperative, Inc.; Indianapolis Power & Light 

Minnesota Power (and its 

Northern Indiana Public Service Company; Nor

Company; Otter Tail Power Company; Southern 

Illinois Power Cooperative; Southern Indiana Gas &

Electric Company; Southern Minnesota Munic

Power Agency; Wolverine Power Supply 

Cooperative, Inc. 

Minnesota Public Utilities Commission and 

Minnesota Office of Energy Securit

M

Multipart

Holdings Corp.; LS Power Transmission LLC; 

N

Commissioners 

National Audubon Society 

National Grid USA 
Docket No. RM10-23-000 - 594 -

Abbreviation Initial Commenter(s) 

National Rural Electric Coops ic Cooperative Association 

esources Defense 

Council 

ense Council 

Nebraska Public Power 

District 

NEPOOL ew England Power Pool Participants Committee 

ydro Nevada Hydro Company 

ttee on Electricity 

Electricity 

y; New 

t utilities 

s affiliate, Vermont Transco LLC 

 Board New Jersey Board of Public Utilities 

on of Rate 

Counsel 

on of Rate Counsel 

New York ISO Independent System Operator, Inc. 

sion 

wners 

Central Hudson Gas & Electric; Consolidated 

Edison Company of New York, Inc.; New York 

Authority; 

New York State Electric & Gas Corporation; 

Niagara Mohawk Power Corporation; Orange and 

 Gas and 

National Rural Electr

Natural R Natural Resources Def

Nebraska Public Power District 

Nevada H

N

New England States 

Commi

New England States Committee on 

New England Transmission 

Owners 

Bangor Hydro Electric Company; Central Maine 

Power Company; NSTAR Electric Compan

England Power Company; Northeast Utilities 

Service Company on behalf of the Northeas

system operating companies; The United 

Illuminating Company; and Vermont Electric 

Transmission Company, Inc., on behalf of itself and 

it

New Jersey

New Jersey Divisi New Jersey Divisi

New York 

New York PSC 

New York Transmis

New York State Public Service Commission 

O

Power Authority; Long Island Power 

Rockland Utilities, Inc.; and Rochester
Docket No. RM10-23-000 - 595 -

Abbreviation Initial Commenter(s) 

Electric Corporation 

ission and Public 

Staff of the North Carolina Utilities Commission 

Northeast Utilities 

Northern California Power 

Agency 

Northern Tier Transmission 

Group 

in 

ition 

 Operations; 

trol & Dispatch; 

EverPower Renewables; Exergy Development 

; 

Invenergy; LS Power Associates; Ridgeline Energy; 

ing, 

NorthWestern Corporation orthWestern Corporation (Montana) 

Companies 

y ompany and Sierra Pacific Power 

ompany 

Ohio Consumers' Counsel and 

West Virginia Consumer 

Advocate Division 

Oklahoma Corporation 

Commission 

Oklahoma Gas and Electric klahoma Gas and Electric Company 

NextEra NextEra Energy, Inc. 

North Carolina Agencies North Carolina Utilities Comm

Northeast Utilities Service Company 

Northern California Power Agency 

Northern Tier Transmission Group 

Northwest & Intermounta

Power Producers Coal

Calpine Corporation; Capital Power

Constellation Energy Con

Group; First Wind; Horizon Wind Energy

Shell Energy North America; TransAlta Market

Inc; and TransCanada 

(Montana) 

N

NRG NRG Companies 

NV Energ Nevada Power C

C

Ohio Consumers' Counsel and West Virginia 

Consumer Advocate Division 

Oklahoma Corporation Commission 

O
Docket No. RM10-23-000 - 596 -

Abbreviation Initial Commenter(s) 

er District 

Organization of MISO States a Utility Regulatory Commission; Iowa 

tilities Board; Michigan Public Service 

a Public Utilities 

ommission; Missouri Public Service Commission; 

orth Dakota 

ublic Service Commission; South Dakota Public 

blic Service 

ommission 

as and Electric Pacific Gas and Electric Company 

attern Transmission Pattern Transmission LP 

Pennsylvania PUC blic Utility Commission 

ic Power 

ompany; Delmarva Power & Light Company; and 

Pioneer Transmission ioneer Transmission, LLC 

n, L.L.C. 

nergyPlus, 

LLC; PPL Brunner Island, LLC; PPL Holtwood, 

LLC; PPL Martins Creek, LLC; PPL Montour, LLC; 

ty Park, LLC; 

ower Mount Bethel Energy, LLC; PPL New Jersey 

PPL 

Company 

Old Dominion Old Dominion Electric Cooperative 

Omaha Public Pow Omaha Public Power District 

Indian

U

Commission; Minnesot

C

Montana Public Service Commission; N

P

Utilities Commission; Wisconsin Pu

C

Pacific G

P

Pennsylvania Pu

PHI Companies Pepco Holdings, Inc.; Potomac Electr

C

Atlantic City Electric Company 

P

PJM PJM Interconnectio

Powerex Powerex Corp. 

PPL Companies PPL Electric Utilities Corporation; PPL E

PPL Susquehanna, LLC; PPL Universi

L

Solar, LLC; PPL New Jersey Biogas, LLC; 

RenewableEnergy, LLC; PPL Montana, LLC; PPL 

Colstrip I, LLC; and PPL Colstrip II, LLC 
Docket No. RM10-23-000 - 597 -

Abbreviation Initial Commenter(s) 

PSC of Wisconsin ublic Service Commission of Wisconsin 

PSEG Companies ublic Service Electric and Gas Company; PSEG 

s & Trade 

LC 

Public Power Council 

UC of Ohio Public Utility Commission of Ohio 

al Utility 

istrict 

Sacramento Municipal Utility District 

t 

San Diego Gas & Electric lectric Company 

g, Colton, 

asadena, and Riverside, CA 

Energy Industries and 

Large-scale Solar 

Energy Industries Association and Large-scale 

olar Association 

Sonoran Institute onoran Institute 

a Electric & 

as 

South Carolina Electric & Gas Company 

fornia Edison Company 

 Companies 

ompany; Gulf Power Company; Mississippi Power 

Primary Power Primary Power, LLC 

P

P

Power LLC; and PSEG Energy Resource

L

Public Power Council 

PUC of Nevada Public Utility Commission of Nevada 

P

Sacramento Municip

D

Salt River Projec Salt River Project Agricultural Improvement and 

Power District 

San Diego Gas & E

Six Cities Cities of Anaheim, Azusa, Bannin

P

Solar Solar 

S

S

South Carolin

G

Southern California Edison Southern Cali

Southern Alabama Power Company; Georgia Power

C

Company; and Southern Power Company 
Docket No. RM10-23-000 - 598 -

Abbreviation Initial Commenter(s) 

Southwest Area Transmission outhwest Area Transmission Subregional Planning 

SPP 

Starwood 

Sunflower and Mid-Kansas 

Transmission Access Policy 

Study Group 

 of 

nia 

lifornia 

ent 

Utility Systems 

perative Corporation; Golden 

pread Electric Cooperative, Inc.; Kansas Electric 

ectric 

Membership Corporation; and Seminole Electric 

Cooperative, Inc. 

tric Power Company 

nd 

Reid 

Byron Dorgan and Harry 

eid 

Vermont Electric pany, Inc. 

n 

on 

ington Utilities and 

Transportation Commission 

ransportation 

ommission 

WECC Western Electricity Coordinating Council 

Westar Westar Energy, Inc. and Kansas Gas and Electric 

Company 

Subregional Planning Group 

S

Group 

Southwest Power Pool, Inc. 

Starwood Energy Group Global, L.L.C. 

Sunflower Electric Power Corporation and MidKansas Electric Company, LLC 

Transmission Access Policy Study Group 

Transmission Agency

Northern Califor

Transmission Agency of Northern Ca

Transmission Depend Arkansas Electric Coo

S

Power Cooperative, Inc.; North Carolina El

Tucson Electric Tucson Elec

U.S. Senators Dorgan a United States Senators

R

Vermont Electric Power Com

Virginia State Corporation 

Commissio

Virginia State Corporation Commissi

Wash Washington Utilities and T

C
Docket No. RM10-23-000 - 599 -

ter(s) 

anning Parties asin Electric 

l 

ict; 

ew 

trict; Salt 

Power 

e, Inc.; 

rind Western 

Western Area Power 

Administration 

Western Grid Group 

Western Independent 

Transmission Group 

The Wilderness Society and 

vocates 

he Wilderness Society and Western Resource 

Wind Coalition (The) 

WIRES 

Wisconsin Electric Power 

Company 

Xcel 

Reply Commenters

Abbreviation Reply Commenter(s) 

Abbreviation Initial Commen

Arizona Public Service Company; B

Power Cooperative; Black Hills Corporation; E

Paso Electric Company; Imperial Irrigation Distr

NV Energy; Public Service Company of N

Mexico; Sacramento Municipal Utility Dis

River Project Agricultural Improvement and 

District; Southwest Transmission Cooperativ

Transmission Agency of Northern California; T

State Generation and Transmission Association, 

Inc.; Tucson Electric Power Company; a

Area Power Administration 

Western Area Power Administration 

Western Grid Group 

Western Independent Transmission Group

WestConnect Pl

Western Resource Ad

T

Advocates 

Wind Coalition (The) 

Working Group for Investment in Reliable and 

Economic Electric Systems 

Wisconsin Electric Power Company 

Xcel Energy Services Inc. 
Docket No. RM10-23-000 - 600 -

Abbreviation Reply Commenter(s) 

26 Public Interest 

Organizations 

 Law Foundation; Earth Justice; 

nergy Conservation Council of Pennsylvania; 

ortheast; Environmental Defense Fund; 

esh 

Energy; Great Plains Institute; Institute for 

Market Transformation; Iowa Environmental 

st Energy 

fficiency Alliance; National Audubon 

e Council; 

Northeast Energy Efficiency Partnerships; NW 

Energy Coalition; Pace Energy and Climate 

ouncil; Project for 

ustainable FERC Energy Policy; Sierra Club; 

he 

ilderness Society; Union of Concerned 

s*

f 

Southeastern Utilities 

, Inc.; 

alton Utilities; Georgia Transmission 

ric 

 Kentucky Utilities Company; 

EAG Power; Orlando Utilities Commission; 

 (on 

ehalf of Progress Energy Carolinas, Inc. and 

ina 

f 

wer 

 

Citizens Utility Board of Wisconsin; Climate 

and Energy Project; CNT Energy; 

Conservation

E

Energy Future Coalition; Environmental 

N

Environmental Law & Policy Center; Fr

Council; Land Trust Alliance; Midwe

E

Society; Natural Resources Defens

Center; Pennsylvania Land Trust Association; 

Piedmont Environmental C

S

Southern Alliance for Clean Energy; T

W

Scientists; Western Grid Group; Western 

Resource Advocates; Wind on the Wire 1

Ad Hoc Coalition o Central Electric Power Cooperative

D

Corporation; JEA; Louisville Gas & Elect

Company and

M

Progress Energy Service Company, LLC

b

Progress Energy Florida, Inc.); South Carol

Electric & Gas Company; South Carolina 

Public Service Authority (Santee Cooper); and

Southern Company Services, Inc. (on behalf o

Alabama Power Company, Georgia Po

1

 A “*” indicates that the co ly 

comment filing. 

mposition of this group as altered in the rep
Docket No. RM10-23-000 - 601 -

Abbreviation Reply Commenter(s) 

y, Mississippi 

ower Company, and Southern Power 

EP 

Alabama Municipal Electric 

Authority 

Arizona Public Service rizona Public Service Company 

Electric 

Bay Area Municipal 

Transmission Group 

alo 

lifornia; the City of Alameda, 

alifornia 

California ISO rator 

California Transmission 

Planning Group 

ict; the 

s 

ngeles Department of Water and Power; the 

ority; 

acific Gas & Electric Company; San Diego 

Company, Gulf Power Compan

P

Company)* 

American Electric Power Service Corporation

Alabama Municipal Electric Authority 

A

APPA American Public Power Association 

Company 

A

Atlantic Grid Atlantic Grid Development, LLC, on behalf of

Atlantic Wind Connection 

Baltimore Gas & Baltimore Gas and Electric Company 

City of Santa Clara, California; the City of P

Alto, Ca

C

Bonneville Power Bonneville Power Administration 

California Independent System Ope

Corporation 

California PUC California Public Utilities Commission 

Sacramento Municipal Utility Distr

Imperial Irrigation District; the City of Lo

A

Southern California Public Power Auth

the Transmission Agency of Northern 

California; the Turlock Irrigation District; the 

Southern California Edison Company; the

P

Gas & Electric Company
Docket No. RM10-23-000 - 602 -

Abbreviation Reply Commenter(s) 

fornia 

 for Fair 

Transmission Policy 

NA 

inating Company 

Skop of the Florida PSC 

 of the Florida 

SC 

Conservation Law Foundation Conservation Law Foundation 

Consolidated Edison and 

ckland 

onsolidated Edison Company of New York, 

es, Inc. 

ental Groups fense Council; 

Environmental Law & Policy Center; Fresh 

Natural Resources Defense Council; National 

Rural Electric Coops; Citizens for 

astern Environmental and 

s 

New Jersey Highlands Coalition; New Jersey 

ub; Delaware 

iverkeeper Network; New Jersey 

East Texas Cooperatives 

.; 

rn G&T Electric Cooperative 

stitute 

City of Santa Clara City of Santa Clara, Cali

Coalition CMS Energy Corporation; Consolidated 

Edison; DTE Energy Company; Northeast 

Utilities; PPL Corporation; Progress Energy, 

Inc.; Public Service Enterprise Group; SCA

Corporation; Southern Company; United 

Illum

Commissioner Nathan A. Commissioner Nathan A. Skop

P

Orange & Ro

C

Inc. and Orange and Rockland Utiliti

EarthJustice and 

Environm

EARTHJUSTICE; Environmental Integrity 

Project; Natural Resources De

Energy 

EarthJustice et al. EARTHJUSTICE on behalf of Sierra Club; 

Pennsylvania’s Future 

E

Conservation Group Chapter of the Sierra Cl

R

Conservation Foundation; Stop the Lines 

East Texas Electric Cooperative, Inc.; 

Northeast Texas Electric Cooperative, Inc

Tex-La Electric Cooperative of Texas, Inc.;

Sam Raybu

Edison Electric In Edison Electric Institute 
Docket No. RM10-23-000 - 603 -

Abbreviation Reply Commenter(s) 

EIF Management 

Entergy Entergy Services Inc., on behalf of the Entergy 

; 

xas, 

Environmental Defense Fund 

Exelon 

First Wind 

Florida PSC 

Green Energy and 21st

Century sion Holdings, LLC 

 Resources 

 England 

Transmission Owners 

rs 

Illinois Commerce 

Commission 

erce Commission 

ISO New England O New England Inc. 

O/RTO Council SO 

 York 

ITC Companies 

EIF Management, LLC 

Operating Companies (Entergy Arkansas, Inc.

Entergy Gulf States Louisiana, LLC; Entergy 

Louisiana LLC; Entergy Mississippi, Inc.; 

Entergy New Orleans, Inc.; and Entergy Te

Inc. 

Environmental Defense Fund 

Exelon Corporation 

First Wind Energy, L.L.C. 

Florida Public Service Commission 

Green Energy Express LLC and 21st Century

Transmis

H-P Energy H-P Energy Resources LLC 

Identified New Identified New England Transmission Owne

Illinois Comm

IS

California Independent System Operator; I

New England, Inc.; Midwest Independent 

Transmission System Operator, Inc.; New

Independent System Operator, Inc.; PJM 

Interconnection, L.L.C.; Southwest Power 

Pool, Inc. 

International Transmission Company; 

Michigan Electric Transmission Company, 

IS
Docket No. RM10-23-000 - 604 -

Abbreviation Reply Commenter(s) 

, 

Large Public Power Council ility 

lorado 

, Long 

ower District, New York 

ower Authority; Omaha Public Power 

atte 

 Electric 

tility District No. 1; Tacoma Public 

tilities 

LS Power S Power Transmission, LLC 

Maine Parties Utilities Commission; Maine 

ffice of the Public Advocate; Maine 

and Security 

MEAG Power EAG Power 

ansmission Owners ion 

., 

n 

yland 

rative; Great River Energy; 

oosier Energy Rural Electric Cooperative, 

er & Light Company; 

idAmerican Energy Company; Minnesota 

LLC; ITC Midwest LLC; ITC Great Plains

LLC; and Green Power Express LP 

Austin Energy; Chelan County Public Ut

District No. 1; Clark Public Utilities; Co

Springs Utilities; CPS Energy (San Antonio); 

IID Energy, JEA (Jacksonville, FL)

Island Power Authority; Los Angeles 

Department of Water and Power; Lower 

Colorado River Authority; MEAG Power; 

Nebraska Public P

P

District; Orlando Utilities Commission; Pl

River Power Authority; Puerto Rico

Power Authority; Sacramento Municipal 

Utility District; Salt River Project; Santee 

Cooper; Seattle City Light; Snohomish County 

Public U

U

L

Maine Public

O

Governor’s Office of Energy, Independence 

M

Ameren Services Company (as agent for Un

Electric Company, Central Illinois Public 

Service Company; Central Illinois Light Co

and Illinois Power Company); America

Transmission Company LLC; City Water, 

Light & Power (Springfield, IL); Dair

Power Coope

MISO Tr

H

Inc.; Indianapolis Pow

M
Docket No. RM10-23-000 - 605 -

Abbreviation Reply Commenter(s) 

ern 

diana Public Service Company; Northern 

Wisconsin corporations); Northwestern 

ail Power 

tric 

Multiparty Commenters 

; 

rid 

c Coops operative 

New England States 

e on Electricity 

ew England States Committee on Electricity 

mission 

NextEra 

Power (and its subsidiary Superior Water, 

L&P); Montana-Dakota Utilities Co.; North

In

States Power Company (Minnesota and 

Wisconsin Electric Company; Otter T

Company; Southern Illinois Power 

Cooperative; Southern Indiana Gas & Elec

Company; Southern Minnesota Municipal 

Power Agency; Wolverine Power Supply 

Cooperative, Inc. 

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 G

Group* 

National Grid National Grid USA 

National Rural Electri National Rural Electric Co

Association 

Committe

New Jersey Board 

N

New Jersey Board of Public Utilities 

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 Energy, Inc. 

N

Owners 

ew York Trans
Docket No. RM10-23-000 - 606 -

Abbreviation Reply Commenter(s) 

outh 

akota Commission 

nd 

Ohio Consumers’ Counsel ffice of the Ohio Consumers’ Counsel 

inion Old Dominion Electric Cooperative 

es na 

; 

Commission; 

ion; Public Utilities 

ommission; Wisconsin Public Service 

attern Transmission 

PJM onnection, L.L.C. 

EnergyPlus, LLC; PPL Brunner Island, LLC; 

a, 

LLC; PPL University Park, LLC; Lower Mount 

Bethel Energy, LLC; PPL New Jersey Solar, 

 Montana, LLC; 

PL Colstrip I, LLC; PPL Colstrip II, LLC; 

PPL Maine, LLC; PPL Wallingford Energy 

LLC* 

North Dakota and S

D

North Dakota Public Service Commission a

South Dakota Public Utilities Commission 

O

Old Dom

Organization of MISO Stat Illinois Commerce Commission; India

Utility Regulatory Commission; Iowa Utilities 

Board; Michigan Public Service Commission

Minnesota Public Utilities 

Missouri Public Service Commission; Montana 

Public Service Commission; North Dakota 

Public Service Commiss

Commission of Ohio; Pennsylvania Utility 

Commission; South Dakota Public Utilities

C

Commission* 

Pacific Gas and Electric Pacific Gas and Electric Company 

Pattern Transmission LP 

PJM Interc

P

Powerex Powerex Corp. 

PPL Companies PPL Electric Utilities Corporation; PPL 

PPL Holtwood, LLC; PPL Martins Creek, 

LLC; PPL Montour, LLC; PPL Susquehann

LLC; PPL New Jersey Biogas, LLC; PPL 

RenewableEnergy, LLC; PPL

P
Docket No. RM10-23-000 - 607 -

Abbreviation Reply Commenter(s) 

PSEG Companies Public Service Electric and Gas Company; 

PSEG Power LLC; PSEG Energy Resources & 

Trade LLC 

Sacramento Municipal Utility 

District 

Sacramento Municipal Utility 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-scale Solar 

Solar Energy Industries Association and Largescale Solar Association 

South Carolina Office of 

Regulatory Staff 

South Carolina Office of Regulatory 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 Ne

Transmission Agency of 

Northern California 

Transmission Agency of Northern California 

Western Independent 

Transmission Group 

Western Independent Transmission Group 

WIRES ent in Reliable and 

Economic Electric Systems 

w England States Southern New England States 

Working Group for Investm
Docket No. RM10-23-000 - 608 -

Pro Forma OATT 

cess 

Local Transmission Planning 

nated, open and transparent planning 

Appendix C: Pro Forma Open Access Transmission Tariff 

ATTACHMENT K 

Transmission Planning Pro

The Transmission Provider shall establish a coordi
Docket No. RM10-23-000 - 609 -

mers and other 

 of 

mission 

le and not unduly discriminatory basis. The Transmission 

 Provider’s Tariff. 

, 

ansparency, information 

nning 

e 

nisms for considering transmission needs driven by Public Policy 

nning process also shall provide a 

echanism for the recovery and allocation of planning costs consistent with Order No. 

890. 

process with its Network and Firm Point-to-Point Transmission Custo

interested parties to ensure that the Transmission System is planned to meet the needs

both the Transmission Provider and its Network and Firm Point-to-Point Trans

Customers on a comparab

Provider’s coordinated, open and transparent planning process shall be provided as an 

attachment to the Transmission

The Transmission Provider’s planning process shall satisfy the following nine principles

as defined in Order No. 890: coordination, openness, tr

exchange, comparability, dispute resolution, regional participation, economic pla

studies, and cost allocation for new projects. The planning process also shall include th

procedures and mecha

Requirements consistent with Order No. 1000. The pla

m

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; 
Docket No. RM10-23-000 - 610 -

e 

i) The dispute resolution process; 

s 

n Planning

 process 

nd evaluated. The regional transmission planning process also shall develop a regional 

 of 

(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 th

Transmission Provider; 

(v

(vii) The Transmission Provider’s study procedures for economic upgrades to addres

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 Transmissio

The Transmission Provider shall participate in a regional transmission planning

through which transmission facilities and non-transmission alternatives may be proposed 

a

transmission plan that identifies the transmission facilities necessary to meet the needs
Docket No. RM10-23-000 - 611 -

 transmission planning region. 

he regional transmission planning process must be consistent with the provision of 

and conditions that are just and 

 in Order No. 1000. 

he 

The regional transmission planning process 

rder No. 1000. The regional 

vide a mechanism for the recovery and allocation 

 and selection. 

transmission providers and transmission customers in the

T

Commission-jurisdictional services at rates, terms 

reasonable and not unduly discriminatory or preferential, as described

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 t

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. 

also shall include the procedures and mechanisms for considering transmission needs 

driven by Public Policy Requirements, consistent with O

transmission planning process shall pro

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

The description of the regional transmission planning process must include sufficient 
Docket No. RM10-23-000 - 612 -

) The process for consulting with customers; 

(ii) The notice proce

(iii) The methodology, criteria, and processes used to develop a transmission plan; 

ion 

 seek 

h to 

ms for considering transmission needs driven by 

Public Policy Requirements, consistent with Order No. 1000; and 

ation method or 

detail to enable Transmission Customers to understand: 

(i

dures and anticipated frequency of meetings;

(iv) The method of disclosure of criteria, assumptions and data underlying transmiss

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

regional cost allocation; 

(vii) Process for submission of data by merchant transmission developers that wis

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 mechanis

(xi) The relevant cost allocation method or methods. 

The regional transmission planning process must include a cost alloc
Docket No. RM10-23-000 - 613 -

ethods that satisfy the six regional cost allocation principles set forth in Order No. 

h neighboring transmission 

ination 

on of the process for 

oordination between public utility transmission providers in neighboring transmission 

e 

ariff 

The Transmission Provider must ensure that the following requirements are included in 

any applicable interregional transmission coordination procedures: 

m

1000. 

Interregional Transmission Coordination 

The Transmission Provider, through its regional transmission planning process, must 

coordinate with the public utility transmission providers in eac

planning region within its interconnection to address transmission planning coord

issues related to interregional transmission facilities. The interregional transmission 

coordination procedures must include a detailed descripti

c

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 possibl

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 T
Docket No. RM10-23-000 - 614 -

e interregional transmission 

cilities that could address transm iently or cost-effectively than 

o; 

(2) A formal procedure to id

ain a website or e-mail list for the communication of 

allocating between the two transmission planni

st 

set forth in Order No. 1000. 

(1) A commitment to coordinate and share the results of each transmission planning 

region’s regional transmission plans to identify possibl

fa ission needs more effic

separate regional transmission facilities, as well as a procedure for doing s

entify 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 maint

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

ng regions the costs of a new interregional 

transmission facility that is located within both transmission planning regions. Such co

allocation method or methods must satisfy the six interregional cost allocation principles 
UNITED STATES OF AMERICA 

 (Issued July 21, 2011) 

ing 

al issues that are 

inhibiting needed investment. 

e 

rt 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 c

ht of 

first refusal is not a right of “forever” refusal. That is, a right to “forever” block a needed 

transm rom reaching consumers. 

 

FEDERAL ENERGY REGULATORY COMMISSION 

 

 

Transmission Planning and Cost Allocation by Docket No. RM10-23-000 

Transmission Owning and Operating Public Utilities 

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 plann

for long-distance transmission lines, which is only a subset of the critic

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 requir

other federal agencies to act.1

 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 thwa

onstructing needed transmission lines. 

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 rig

ission project could prevent the lowest-cost power f

1

 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.” 
Docket No. RM10-23-000 -2-

t 

ts 

 incumbent does not seek to share the costs of those projects; (2) upgrades to 

existing assets; and (3) projects on existing right of way.2

 However, notably absent from 

these c d 

f 

s of cost allocation. And because a 

transmission provider would have retained its authority to address reliability issues in its 

franch

r 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

balancing of projects could help ensure that all the parts of a region receive benefits that 

are at l

first refusal, thus 

To encourage needed transmission investment, the final rule permits incumben

transmission owners to maintain their existing rights of first refusal for: (1) local projec

where the

ategories of projects is the right of a utility to build a project within its franchise

service territory in order to maintain the reliability of its existing network – regardless o

whether the cost of that project is allocated on a regional basis. 

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 purpose

ised 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.3

 

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 waive

. 

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 

east roughly equivalent. Yet under the final rule, local projects that have their

costs assigned regionally generally cannot maintain a right of 

 2

 Section III.B.3.d of the final rule, at PP 318-319. 

3

 For a description of the blanket waiver, see section III.B.4.b of the final rule, at P 

344 (“P

r 

y a 

transmission facility.”) 

rovided the public utility transmission provider follows the NERC approved 

mitigation plan, the Commission will not subject that public utility transmission provide

to enforcement action for the specific NERC reliability standard violation(s) caused b

nonincumbent transmission developer’s decision to abandon a 
Docket No. RM10-23-000 -3-

ocal 

n 

 of 

fusal 

nefits 

e project and thus improve the power grid 

hould be available to a non-incumbent developer. 

A review of the transmission proje ous regional 

 first refusal under 

 they are built on an 

xisting right of way, or their costs are not allocated to other transmission providers.4

 

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 Com g 

al 

ight 

n 

discouraging transmission owners from seeking regional cost allocation for their l

projects. For this reason, instead of encouraging more regional cooperation, the rule 

could ultimately discourage such cooperation by encouraging more local transmissio

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

first refusal. That is, the Commission should have emphasized that a right of first re

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 be

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 th

s

cts that have been adopted in vari

plans indicates that most projects will be allowed to retain the right of

the final rule, as most projects involve upgrades to existing assets, or

e

mission-jurisdictional5

 tariff to prevent the lowest-cost power from reachin

consumers. 

Recognizing that no party to this proceeding asserted that a right of first refus

grants its holder a right to refuse building a project forever, I believe that a federal r

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 o

 4

 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. 

le, any time limitation on a right of first 

refusal cerning 

5

 Consistent with the remainder of the ru

 under my approach would be subject to relevant state and other law con

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. 
Docket No. RM10-23-000 -4-

whether to exercise its right to build a project.F

6

F 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 best reflects the needs and 

circumstances of that region. F

7

F 

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. 

 _______________________ 

 Philip D. Moeller 

 Commissioner 

 6

 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. 

7

 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.