139 FERC ¶ 61,132

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM10-23-001; Order No. 1000-A]

Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities

(Issued May 17, 2012)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on Rehearing and Clarification

SUMMARY: The Federal Energy Regulatory Commission affirms its basic 

determinations in Order No. 1000, amending the transmission planning and cost 

allocation requirements established in Order No. 890 to ensure that Commissionjurisdictional services are provided at just and reasonable rates and on a basis that is just 

and reasonable and not unduly discriminatory or preferential. This order affirms the 

Order No. 1000 transmission planning reforms that: (1) require that each public utility 

transmission provider participate in a regional transmission planning process that 

produces a regional transmission plan; (2) provide that local and regional transmission 

planning processes must provide an opportunity to identify and evaluate transmission 

needs driven by public policy requirements established by state or federal laws or 

regulations; (3) improve coordination between neighboring transmission planning regions 

for new interregional transmission facilities; and (4) remove from Commission-approved 

tariffs and agreements a federal right of first refusal. This order also affirms the Order 
Docket No. RM10-23-001 - 2 -

No. 1000 requirements that each public utility transmission provider must participate in a 

regional transmission planning process that has: (1) a regional cost allocation method for 

the cost of new transmission facilities selected in a regional transmission plan for 

purposes of cost allocation and (2) an interregional cost allocation method for the cost of 

new transmission facilities that are located in two neighboring transmission planning 

regions and are jointly evaluated by the two regions in the interregional transmission 

coordination process required by this Final Rule. Additionally, this order affirms the 

Order No. 1000 requirement that each cost allocation method must satisfy six cost 

allocation principles. 

FOR FURTHER INFORMATION CONTACT:

John Cohen

Federal Energy Regulatory Commission 

Office of the General Counsel

888 First Street, NE

Washington, DC 20426

(202) 502-8705

Shiv Mani

Federal Energy Regulatory Commission 

Office of Energy Policy and Innovation

888 First Street, NE

Washington, DC 20426

(202) 502-8240

SUPPLEMENTARY INFORMATION:
139 FERC ¶ 61,132

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

 Philip D. Moeller, John R. Norris,

 and Cheryl A. LaFleur.

Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities

Docket No. RM10-23-001

ORDER NO. 1000-A 

ORDER ON REHEARING AND CLARIFICATION

(Issued May 17, 2012)

TABLE OF CONTENTS

Paragraph Numbers

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

II. The Need for Reform............................................................................................................4.

A. Final Rule .........................................................................................................................4.

B. Requests for Rehearing and Clarification ........................................................................13.

1. Arguments Regarding Whether the Commission Provided Substantial Evidence 

for the Transmission Planning and Cost Allocation Reforms...........................................13.

C. Commission Determination..............................................................................................50.

III. Transmission Planning ........................................................................................................102.

A. Regional Transmission Planning Process ........................................................................102.

1. Legal Authority for Order No. 1000’s Transmission Planning Reforms.....................103.

a. Final Rule .................................................................................................................103.

b. Order No. 1000’s Interpretation of FPA Section 202(a)..........................................108.

i. Requests for Rehearing and Clarification.............................................................108.

ii. Commission Determination.................................................................................121.

c. Role of FPA Section 217(b)(4) ................................................................................159.

i. Requests for Rehearing and Clarification.............................................................159.

ii. Commission Determination.................................................................................168.
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d. Effect on Integrated Resource Planning and State Authority Over 

Transmission Siting, Permitting, and Construction ......................................................180.

i. Requests for Rehearing and Clarification ............................................................180.

ii. Commission Determination.................................................................................186.

e. Legal Authority Related to Consideration of Transmission Needs Driven by 

Public Policy Requirements..........................................................................................195.

i. Requests for Rehearing and Clarification.............................................................195.

ii. Commission Determination.................................................................................203.

f. Legal Issues Related to Order No. 1000’s Interregional Transmission 

Coordination Reforms...................................................................................................217.

i. Requests for Rehearing and Clarification.............................................................217.

ii. Commission Determination.................................................................................222.

g. Other Legal Issues Related to Regional Transmission Planning Requirements......228.

i. Requests for Rehearing and Clarification.............................................................228.

ii. Commission Determination.................................................................................230.

2. Regional Transmission Planning Requirements ..........................................................232.

a. Final Rule .................................................................................................................232.

b. Requests for Rehearing and Clarification ................................................................235.

c. Commission Determination......................................................................................263.

3. Consideration of Transmission Needs Driven by Public Policy Requirements...........302.

a. Final Rule .................................................................................................................302.

b. Requests for Rehearing and Clarification ................................................................304.

c. Commission Determination......................................................................................317.

B. Nonincumbent Transmission Developers ........................................................................340.

1. Legal Authority.............................................................................................................341.

a. Final Rule .................................................................................................................341.

b. Requests for Rehearing and Clarification ................................................................345.

i. Arguments That the Commission Does Not Have the Authority To 

Eliminate a Federal Right of First Refusal ...............................................................345.

(a) Commission Determination ...........................................................................357.

ii. Arguments That the Commission Is Inappropriately Regulating the 

Construction of Transmission...................................................................................371.

(a) Commission Determination ...........................................................................377.

iii. Arguments That the Commission Must Meet the Mobile-Sierra Public 

Interest Standard Before Requiring Federal Rights of First Refusal To Be 

Removed From Agreements.....................................................................................383.

(a) Commission Determination ...........................................................................388.

2. Requirement To Remove a Federal Right of First Refusal from CommissionJurisdictional Tariffs and Agreements, and Limits on the Applicability of That 

Requirement.......................................................................................................................392.
Docket No. RM10-23-001 -3-

a. Final Rule .................................................................................................................392.

b. Requests for Rehearing and Clarification ................................................................395.

c. Commission Determination......................................................................................415.

3. Framework To Evaluate Transmission Projects Submitted for Selection in the 

Regional Plan for Purposes of Cost Allocation.................................................................431.

a. Qualification Criteria To Submit a Transmission Project for Selection in the 

Regional Transmission Plan for Purposes of Cost Allocation......................................432.

i. Final Rule..............................................................................................................432.

ii. Requests for Rehearing and Clarification............................................................433.

iii. Commission Determination................................................................................439.

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

Purposes of Cost Allocation..........................................................................................445.

i. Final Rule..............................................................................................................445.

ii. Requests for Rehearing and Clarification............................................................446.

iii. Commission Determination................................................................................452.

c. Reevaluation of Regional Transmission Plans When There Is a Project Delay 

and Reliability Compliance Obligations of Transmission Developers.........................457.

i. Final Rule..............................................................................................................457.

ii. Requests for Rehearing and Clarification............................................................460.

iii. Commission Determination................................................................................477.

d. Recovery of Abandoned Plant Costs and Backstop Authority ................................484.

i. Final Rule..............................................................................................................484.

ii. Requests for Rehearing........................................................................................485.

iii. Commission Determination................................................................................489.

C. Interregional Transmission Coordination.........................................................................493.

1. Interregional Transmission Coordination Requirements..............................................493.

a. Interregional Transmission Coordination Procedures and Geographical Scope......493.

i. Final Rule..............................................................................................................493.

ii. Requests for Rehearing and Clarification............................................................495.

iii. Commission Determination................................................................................500.

2. Implementation of the Interregional Transmission Coordination Requirements.........506.

a. Procedure for Joint Evaluation .................................................................................506.

i. Final Rule..............................................................................................................506.

ii. Requests for Rehearing and Clarification............................................................507.

iii. Commission Determination................................................................................509.

b. Stakeholder Participation .........................................................................................513.

i. Final Rule..............................................................................................................513.

ii. Requests for Rehearing and Clarification............................................................514.

iii. Commission Determination................................................................................518.

IV. Cost Allocation....................................................................................................................523.
Docket No. RM10-23-001 -4-

A. Legal Authority for Cost Allocation Reforms ................................................................525.

1. Final Rule......................................................................................................................525.

2. Requests for Rehearing or Clarification ......................................................................530.

a. Petitioners’ Arguments That The FPA Requires a Contract before Costs Are 

Allocated .......................................................................................................................530.

b. Arguments That Order No. 1000’s Cost Allocation Reforms Are Inconsistent 

With the Cost Causation Principle ................................................................................548.

c. Arguments That The Commission Did Not Show That Existing Rates Are 

Unjust and Unreasonable ..............................................................................................551.

3. Commission Determination..........................................................................................555.

B. Cost Allocation Method for Regional Transmission Facilities........................................593.

1. Final Rule......................................................................................................................593.

2. Requests for Rehearing and Clarification.....................................................................597.

3. Commission Determination..........................................................................................613.

C. Cost Allocation Method for Interregional Transmission Facilities..................................626.

1. Final Rule......................................................................................................................626.

2. Requests for Rehearing or Clarification .......................................................................631.

3. Commission Determination..........................................................................................634.

D. Principles for Regional and Interregional Cost Allocation..............................................638.

1. Use of a Principles-Based Approach ............................................................................638.

a. Arguments That Principles-Based Cost Allocation Methods Are Unfair and 

Arguments Related to Commission Determination of Cost Allocation Method 

Pursuant to the Compliance Process.............................................................................640.

i. Commission Determination..................................................................................647.

2. Cost Allocation Principle 1—costs allocated in a way that is roughly 

commensurate with benefits..............................................................................................654.

a. Requests for Rehearing or Clarification...................................................................658.

i. Commission Determination..................................................................................674.

3. Cost Allocation Principle 2—no involuntary allocation of costs to nonbeneficiaries.......................................................................................................................684.

a. Final Rule .................................................................................................................684.

b. Requests for Rehearing or Clarification...................................................................686.

c. Commission Determination......................................................................................689.

4. Cost Allocation Principle 3—benefit to cost threshold ratio........................................692.

a. Final Rule .................................................................................................................692.

b. Request for Rehearing or Clarification ....................................................................694.

c. Commission Determination......................................................................................695.

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

planning region(s) unless those outside voluntarily assume costs ....................................696.

a. Final Rule .................................................................................................................696.
Docket No. RM10-23-001 -5-

b. Requests for Rehearing or Clarification...................................................................697.

c. Commission Determination......................................................................................707.

6. Whether To Establish Other Cost Allocation Principles..............................................715.

a. Final Rule .................................................................................................................715.

b. Requests for Rehearing ............................................................................................716.

c. Commission Determination......................................................................................717.

E. Application of Cost Allocation Principles........................................................................718.

1. Participant Funding.......................................................................................................718.

a. Final Rule .................................................................................................................718.

b. Requests for Rehearing or Clarification...................................................................719.

c. Commission Determination......................................................................................726.

F. Other Cost Allocation Issues ...........................................................................................738.

1. Final Rule......................................................................................................................738.

2. Requests for Rehearing or Clarification .......................................................................739.

3. Commission Determination..........................................................................................745.

V. Compliance and Reciprocity ................................................................................................748.

A. Compliance.......................................................................................................................748.

1.Final Rule........................................................................................................................748.

2.Requests for Rehearing or Clarification .........................................................................749.

3.Commission Determination............................................................................................751.

B. Reciprocity .......................................................................................................................754.

1. Final Rule......................................................................................................................754.

2. Requests for Rehearing or Clarification .......................................................................755.

3. Commission Determination .........................................................................................771.

VI. Information Collection Statement .......................................................................................779.

VII. Document Availability.......................................................................................................784.

VIII. Effective Date and Congressional Notification................................................................787.

Appendix A: Abbreviated Names of Petitioners

Appendix B: Pro Forma Open Access Transmission Tariff Attachment K
Docket No. RM10-23-001 -6-

I. Introduction

1. In Order No. 1000, the Commission amended the transmission planning and cost 

allocation requirements established in Order No. 890 to ensure that Commissionjurisdictional services are provided at just and reasonable rates and on a basis that is just 

and reasonable and not unduly discriminatory or preferential. Order No. 1000’s 

transmission planning reforms require: (1) each public utility transmission provider to 

participate in a regional transmission planning process that produces a regional 

transmission plan; (2) that local and regional transmission planning processes must 

provide an opportunity to identify and evaluate transmission needs driven by public 

policy requirements established by state or federal laws or regulations; (3) improved 

coordination between neighboring transmission planning regions for new interregional 

transmission facilities; and (4) the removal from Commission-approved tariffs and 

agreements of a federal right of first refusal. 

2. Order No. 1000 also requires that each public utility transmission provider must 

participate in a regional transmission planning process that has: (1) a regional cost 

allocation method for the cost of new transmission facilities selected in a regional 

transmission plan for purposes of cost allocation and (2) an interregional cost allocation 

method for the cost of new transmission facilities that are located in two neighboring 

transmission planning regions and are jointly evaluated by the two regions in the 

interregional transmission coordination process required by this Final Rule. Order No. 
Docket No. RM10-23-001 -7-

1000 also requires that each cost allocation method must satisfy six cost allocation 

principles.

3. Taken together, the reforms adopted in Order No. 1000 will ensure that 

Commission-jurisdictional services are provided at just and reasonable rates and on a 

basis that is just and reasonable and not unduly discriminatory or preferential. The 

Commission therefore rejects requests to eliminate, or substantially modify, the various 

reforms adopted in Order No. 1000; however, we do make a number of clarifications.1

 

We address each of the arguments made by petitioners in turn.2

 1 No changes are being made to the regulatory text previously adopted, because 

any reference to Order No. 1000 (as well as to Order Nos. 888 and 890) in the existing 

regulatory text is meant to include any clarifications or changes made in subsequent 

orders on rehearing or clarification (e.g., Order Nos. 888-A, 890-A, and the instant Order 

No. 1000-A, etc.). The Commission has chosen this convention to help promote 

readability of the regulatory text. 

2 A list of petitioners filing requests for rehearing and/or clarification is provided 

in Appendix A. An untimely request for rehearing was filed by the New Jersey Board of 

Public Utilities (New Jersey BPU). Pursuant to section 313(a) of the Federal Power Act 

(FPA), 16 USC 8251(a) (2006), an aggrieved party must file a request for rehearing 

within thirty days after the issuance of the Commission’s order. Because the 30-day 

rehearing deadline is statutory, it cannot be extended, and New Jersey BPU's request for 

rehearing must be rejected as untimely. Moreover, the courts have repeatedly recognized 

that the time period within which a party may file an application for rehearing of a 

Commission order is statutorily established at 30 days by section 313(a) of the FPA and 

that the Commission has no discretion to extend that deadline. See, e.g., City of 

Campbell v. FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985); Boston Gas Co. v. FERC, 575 

F.2d 975, 977-79 (1st Cir. 1978).
Docket No. RM10-23-001 -8-

II. The Need for Reform

A. Final Rule

4. In Order No. 1000, the Commission concluded that it was appropriate to adopt the 

package of reforms addressing transmission planning and cost allocation set forth in the 

order, stating that its review of the record, as well as recent studies, indicated that the 

transmission planning and cost allocation requirements of Order No. 8903 were an 

inadequate foundation for public utility transmission providers to address challenges they 

currently face or will face in the near future.4

 The Commission found that the record was 

adequate to support its conclusion that the existing requirements of Order No. 890 are too 

narrowly focused geographically and fail to provide for adequate analysis of the benefits 

associated with interregional transmission facilities traversing neighboring transmission 

planning regions.5

 

5. The Commission found that recent increases in transmission investment in fact 

support the need to ensure that transmission planning and cost allocation requirements are 

 3 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC 

Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 

(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on 

clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

4 Id. P 42.

5 Id. P 373.
Docket No. RM10-23-001 -9-

adequate to support more efficient and cost-effective investment decisions.6 It noted that 

this increase appears to be only the beginning of a longer-term period of investment in 

new transmission facilities, which is being driven, in part, by changes in the generation 

mix. Specifically, the Commission explained that existing and potential environmental 

regulation and state renewable portfolio standards are driving significant changes in the 

mix of resources, resulting in the early retirement of some coal-fired generation, 

increased reliance on natural gas for electricity generation, and large-scale integration of 

renewable generation.7

 The Commission stated that these shifts in the generation fleet 

increase the need for new transmission and that the existing transmission grids were not 

built to accommodate them.8

 It stated that the increased focus on investment in new 

transmission projects makes it even more critical to implement the reforms to ensure that

the more efficient or cost-effective projects come to fruition. In short, the Commission 

stated that the record in this proceeding and the cited reports confirm that additional, and 

potentially significant, investment in new transmission facilities will be required in the 

future to meet reliability needs and integrate new sources of generation. The 

Commission concluded that it was, therefore, critical that it act now to address 

 6 Id. P 44.

7 Id. P 45.

8 Id.
Docket No. RM10-23-001 -10-

deficiencies to ensure that more efficient or cost-effective investments are made as the 

industry addresses these challenges.

6. The Commission then stated that it would not wait for systemic problems to 

undermine transmission planning before action is taken. Rather, the Commission 

concluded that it must act promptly to establish the rules and processes necessary to 

allow public utility transmission providers to ensure planning of and investment in the 

right transmission facilities as the industry moves forward to address the many challenges 

it faces. The Commission noted that such planning is a complex process that requires 

consideration of a broad range of factors and an assessment of their significance over a 

period that can extend decades into the future, and that the development of transmission 

facilities can involve long lead times and complex problems related to design, siting, 

permitting, and financing.9

 Given the need to deal with these matters over a long time 

horizon, the Commission concluded that it is appropriate and prudent to act at this time 

rather than allowing the problems in transmission planning and cost allocation to 

continue or to increase.

7. The Commission concluded that its actions are consistent with the D.C. Circuit’s 

opinions in National Fuel and Associated Gas Distributors.

10 Consistent with National 

 9 Id. P 50.

10 Id. P 51 (citing National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. 

(continued...)
Docket No. RM10-23-001 -11-

Fuel, the Commission found that the problem it seeks to resolve, i.e., the narrow focus of 

current planning requirements and the shortcomings of current cost allocation practices, 

represents a significant “theoretical threat” that justifies Order No. 1000’s requirements 

and is not one that the Commission can address adequately or efficiently through the 

adjudication of individual complaints.11 The Commission explained that the actual 

experiences cited in the record provide additional support for action but are not necessary 

to justify the remedy, and that the remedy is justified by the theoretical threat identified 

therein.12 

8. The Commission also explained that the facts and findings of Associated Gas 

Distributors are in no way comparable to the matters involved in this proceeding.13 It 

disagreed that its reforms will have an impact on the industry that is comparable to the 

impact at issue in Associated Gas Distributors. The Commission pointed out that 

compliance with Order No. 1000 will involve the adoption and implementation of 

additional processes and procedures, and that many public utility transmission providers 

 

Cir. 2006) (National Fuel); Associated Gas Distrib. v. FERC, 824 F.2d 981 (D.C. Cir. 

1985) (Associated Gas Distributors)).

11 Id. P 52.

12 Id. P 53.

13 Id. P 54-55.
Docket No. RM10-23-001 -12-

already engage in processes and procedures of this type, even if some public utility 

transmission providers may need to do more than others to comply.14

9. The Commission disagreed with assertions that it relied on unsubstantiated 

allegations of discriminatory conduct or that the current Order No. 890 processes have 

not been in place long enough to justify the reforms.15 It stated that it need not make 

specific factual findings of discrimination to promulgate a generic rule to ensure just and 

reasonable rates or eliminate undue discrimination. 

10. The Commission disagreed with claims 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.16 The Commission stated that while the 

concerns it has with existing planning and cost allocation processes may not affect each 

region of the country equally, it nonetheless remained concerned that the existing 

processes are inadequate to ensure the development of more efficient and cost-effective 

transmission. It noted that it is well-established that the choice between rulemaking and 

case-by-case adjudication lies primarily in the informed discretion of the administrative 

agency. It also noted that each transmission planning region has unique characteristics, 

 14 Id. P 56-57.

15 Id. P 58.

16 Id. P 60.
Docket No. RM10-23-001 -13-

and Order No. 1000 provided significant flexibility to transmission planning regions to 

accommodate regional differences.17

11. On the specific issue of nonincumbent transmission developers, the Commission 

found that there was sufficient justification in the record to implement the elimination of 

federal rights of first refusal contained in Commission-jurisdictional tariffs or 

agreements. It noted that although it previously accepted in some cases, and rejected in 

others, a federal right of first refusal, it found its reasoning in the cases rejecting the 

federal right of first refusal to be more persuasive. In particular, the Commission stated 

that it rejected a federal right of first refusal based on an expectation that “[t]he presence 

of multiple transmission developers would lower costs to customers.”18 The Commission 

explained that it is not in the economic self-interest of incumbent transmission providers 

to permit new entrants to develop transmission facilities, even if proposals submitted by 

new entrants would result in a more efficient or cost-effective solution to a region’s 

 17 Id. P 61.

18 Cleco Power LLC, 101 FERC ¶ 61,008 at P 117 (2002), order terminating 

proceedings, 112 FERC ¶ 61,069 (2005); see also Carolina Power and Light Co., 

94 FERC ¶ 61,273 at 62,010, order on reh’g, 95 FERC ¶ 61,282 at 61,995 (2001) 

(finding that a federal right of first refusal would unduly limit the planning authority and 

present the possibility of discrimination by self-interested transmission owners, 

potentially reduce reliability, and possibly precluding lower cost or superior transmission 

facilities or upgrades by third parties from being planned and constructed).
Docket No. RM10-23-001 -14-

needs.19 In addition, the Commission required all public utility transmission providers to 

adopt a framework that requires, among other things, the development of qualification 

criteria and protocols for the submission and evaluation of proposed transmission 

projects.20

12. Regarding its cost allocation reforms, the Commission concluded in Order No. 

1000 that considering the changes within the industry and the implementation of other 

reforms in Order No. 1000, the requirements of Order No. 890 were no longer adequate 

to ensure rates, terms and conditions of jurisdictional service are just and reasonable and 

not unduly discriminatory or preferential.21 It found that the challenges associated with 

allocating the cost of transmission appear to have become more acute as the need for 

transmission infrastructure has grown.22 The Commission explained that within RTO or 

ISO regions, particularly those that encompass several states, the allocation of 

transmission costs is often contentious and prone to litigation.23 It also noted that in other 

regions, few rate structures are currently in place that reflect an analysis of the 

 19 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 256.

20 Id. P 7.

21 Id. P 497.

22 Id. P 498.

23 Id. P 498.
Docket No. RM10-23-001 -15-

beneficiaries of a transmission facility and provide for the corresponding cost allocation 

of the transmission facility’s cost.24 Similarly, the Commission noted that there are few 

rate structures in place today that provide for the allocation of costs of interregional 

transmission facilities.25 Finally, the Commission found that the lack of clear ex ante

cost allocation methods that identify beneficiaries of proposed regional and interregional 

transmission facilities may be impairing the ability of public utility transmission 

providers to implement more efficient or cost-effective transmission solutions identified 

during the transmission planning process.26

B. Requests for Rehearing and Clarification

1. Arguments Regarding Whether the Commission Provided 

Substantial Evidence for the Transmission Planning and Cost 

Allocation Reforms

13. While several petitioners seeking rehearing or clarification express general support 

for Order No. 1000,27 others argue that the Commission failed to provide adequate 

justification under FPA section 206 for adopting its reforms.28 Coalition for Fair 

 24 Id. P 498.

25 Id. P 498.

26 Id. P 499.

27 See, e.g., AEP; WIRES; AWEA; and Energy Future Coalition Group.

28 See, e.g., Large Public Power Council; Alabama PSC; Xcel; Georgia PSC; Ad 

Hoc Coalition of Southeastern Utilities; and PPL Companies.
Docket No. RM10-23-001 -16-

Transmission Policy acknowledges that the circumstances against which the Commission 

must fulfill its statutory responsibilities change with developments in the electric 

industry, including changes with respect to demands on the transmission grid; however, it 

argues that Order No. 1000 takes the principle several steps beyond the Commission’s 

existing statutory authority. Coalition for Fair Transmission Policy contends that the 

Commission makes a number of statements about problems facing the industry that are 

remarkable in their ambiguity, and the existence of problems does not empower the 

Commission to address every policy problem that arises from such developments or to 

commandeer regional transmission planning. Coalition for Fair Transmission Policy 

asserts that, if this was the case, section 216 of the FPA, which gives the Commission 

limited authority to site transmission facilities in national interest electric transmission 

corridors, would not have been necessary.

14. PPL Companies argue that the Commission failed to show that existing rates, 

terms and conditions are unjust and unreasonable or unduly discriminatory absent Order 

No. 1000.29 They also contend that Order No. 1000 not only fails to identify who is 

being discriminated against and who is discriminating, but never addresses whether 

discrimination has actually materialized in the three years since the Commission’s last 

major rulemaking in this area. PPL Companies assert that, although the Commission is 

 29 PPL Companies at 6 (citing 16 U.S.C. § 825l(b)). 
Docket No. RM10-23-001 -17-

empowered to act against undue discrimination before it occurs, it must at least identify 

the discrimination it seeks to remedy.30 They also maintain that the Commission did not 

specify which rate it has found to be unjust and unreasonable or what substantial 

evidence it relies upon to draw that conclusion.

15. Similarly, California ISO asserts that the Commission failed to identify any 

instance in which an existing rate is unjust, unreasonable, or unduly discriminatory or 

preferential because it does not include provisions for interregional coordination. 

Instead, California ISO asserts that the Commission only offers an unsupported 

hypothesis that planning between or among regions will enhance the Commission’s 

ability to perform its mission.

16. Oklahoma Gas and Electric Company argues that Order No. 1000 provides no 

evidence that existing tariff provisions that address the construction and ownership of 

transmission facilities in any way result in unjust and unreasonable rates, or in undue 

discrimination against any customers. It asserts that the evidence the Commission cited 

is far weaker than the evidence it relied upon to support its expansion of the Standards of 

Conduct in Order No. 2004, where the court stated that “citing no evidence 

 30 PPL Companies at 6 (citing Associated Gas Distributors, 824 F.2d 981 at 1008).
Docket No. RM10-23-001 -18-

demonstrating that there is in fact an industry problem is not reasoned decisionmaking.”31

17. Oklahoma Gas and Electric Company also claims that Order No. 1000 is devoid of 

support for the conclusion that existing tariff provisions interfere with transmission 

planning. It argues that there is no evidence, anecdotal or otherwise, that current RTO 

transmission planning processes generate an unreasonably limited range of options, and 

that there is no evidence that projects are delayed because they are being constructed by 

incumbent transmission owners. Specifically, Oklahoma Gas and Electric Company 

argues that the Commission cannot support a finding that the current transmission rules in 

SPP result in rates that are unjust and unreasonable.32

18. Georgia PSC argues that the Commission should recognize ongoing transmission 

processes that utilities are participating in and allow them to work before inserting 

another process that will strain resources.

 31 Oklahoma Gas and Electric Company at 14 (citing National Fuel, 468 F.3d at 844). 

32 Oklahoma Gas & Electric Company also states that SPP’s transmission planning 

process is robust and almost all of the projects are being completed within designated 

timeframes. It contends that where appropriate, the process permits nonincumbent 

developers to collaborate with incumbent transmission owners to address system needs. 

It also asserts that the 90-day time limit for incumbent transmission owners to agree to 

build a designated project prevents a transmission provider from blocking or delaying the 

construction of projects and ensures that the process is open and transparent.
Docket No. RM10-23-001 -19-

19. Ad Hoc Coalition of Southeastern Utilities and Large Public Power Council assert 

that the Commission misread National Fuel, arguing that the court faulted the 

Commission for failing to support its decision with record evidence, and was noncommittal on whether a decision might be supported by theory alone.33 They state that it 

is incumbent on an agency to “examine the relevant data and articulate a satisfactory 

explanation for its action including a rational connection between the facts found and the 

choice made.”34 They further note that National Fuel commented that “[p]rofessing that 

an order ameliorates a real industry problem but then citing no evidence demonstrating 

that there is in fact an industry problem is not reasoned decision-making.”35

20. Several petitioners take issue with the Commission’s conclusion that it may act by 

citing to a “theoretical threat” rather than providing concrete evidence that the reforms 

are necessary.36 For example, petitioners argue that the Commission failed to set forth 

 33 Ad Hoc Coalition of Southeastern Utilities at 16 (quoting National Fuel, 468 

F.3d at 844 (“[W]e express no view here whether a theoretical threat alone would be 

sufficient to justify an order extending the Standards to non-marketing affiliates.”)).

34 Id. at 16 (quoting Motor Vehicles Mfrs. Ass’n of U.S. v. State Farm Mut. Auto 

Ins. Co., 463 U.S. 29, 43 (1983) (State Farm)).

35 Ad Hoc Coalition of Southeastern Utilities at 16 (quoting National Fuel, 468 

F.3d at 843).

36 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Large Public Power 

Council; North Carolina Agencies; and Southern Companies.
Docket No. RM10-23-001 -20-

substantial evidence, or any evidence, of undue discrimination to support its reforms.37 

Xcel adds that the Commission appears to concede that it lacks actual evidence of undue 

discrimination. Ad Hoc Coalition of Southeastern Utilities and Large Public Power 

Council argue that it is reasonable to conclude that the Commission has effectively 

conceded that there is no evidence justifying Order No. 1000 and that the Commission is 

relying on theory alone.38 

21. Ad Hoc Coalition of Southeastern Utilities and Large Public Power Council, as 

well as North Carolina Agencies, argue that the flaw in the Commission’s decision is that 

both the problem it aims to solve and the solution are theoretical. Ad Hoc Coalition of 

Southeastern Utilities contends that reasoned decision-making calls for substantially 

 37 See, e.g., FirstEnergy Service Company; PSEG Companies at 25-32 (citing the 

APA, as well as National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831, 838 (D.C. Cir. 

2006) and Florida Gas Transmission Co. v. FERC, 604 F.3d 636, 645 (D.C. Cir. 2010)); 

Xcel; PSEG Companies; Sponsoring PJM Transmission Owners; Baltimore Gas & 

Electric at 15 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 229); Ad Hoc 

Coalition of Southeastern Utilities at 55 (quoting in part Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 253); Large Public Power Council; and MISO Transmission Owners 

Group 2.

38 Large Public Power Council also claims that the D.C. Circuit has taken judicial 

notice of the efficiencies derived from vertical integration. According to Large Public 

Power Council, this means that the court is effectively insisting that the Commission 

offer evidence that decisions to disaggregate utility operations planning must overcome a 

presumption that the efficiencies derived from vertical integration are not in the public 

interest. Large Public Power Council at n.38 (citing National Fuel, 468 F.3d at 840 

(citing Tenneco Gas v. FERC, 969 F.2d 1187, 1197 (D.C. Cir. 1992))).
Docket No. RM10-23-001 -21-

more than a hypothesis that existing planning and cost allocation mechanisms may be 

suboptimal, and speculation that the mechanisms discussed in the order will result in the 

development of more efficient transmission. Southern Companies also argue that the 

Commission’s explanation of the need for the transmission planning and cost allocation 

reforms in Order No. 1000 is built entirely on speculation.39 Given this, Southern 

Companies contend that Order No. 1000 fails to represent lawful, reasoned agency 

decision-making by depending on a speculative theoretical threat to support the required 

reforms rather than providing the required assessment.40 

22. Southern Companies and Ad Hoc Coalition of Southeastern Utilities state that 

Order No. 1000’s reliance on an alleged theoretical threat misinterprets precedent that 

agencies need to prove theories beyond mere hypothesis or conjecture.41 They argue that 

courts have historically allowed agencies to support orders by theory alone when the 

theory itself is well supported and represents a highly developed prediction of what 

actually happens in the real world. Southern Companies, Ad Hoc Coalition of 

Southeastern Utilities, and Large Public Power Council cite to Business Roundtable v. 

 39 Southern Companies at 89-90 (citing Algonquin Gas Transmission Co. v. FERC, 

948 F.2d 1305 (D.C. Cir. 1991)). 

40 Southern Companies at 91 (citing State Farm, 463 U.S. 29, 43 (1983)). 

41 Southern Companies at 14 (citing National Fuel; Electricity Consumer Resource 

Council v. FERC, 747 F.2d 1511, 1517 (D.C. Cir. 1984) (ELCON)); Ad Hoc Coalition of 

Southeastern Utilities at 22-23 (citing same).
Docket No. RM10-23-001 -22-

SEC,

42 where the court concluded that the Securities and Exchange Commission (SEC) 

had not adequately considered the effects of a proposed rule on efficiency, competition 

and capital formation. They maintain that the case deals with matters that are similar to 

the present proceeding. 

23. With respect to federal rights of first refusal, Sponsoring PJM Transmission 

Owners state that Order No. 1000’s hypothetical discrimination stands in marked contrast 

to the concrete findings in Order No. 888 justifying the implementation of open 

transmission access and assert the Commission offers no evidentiary support for its 

findings. Baltimore Gas & Electric argues that the Commission is taking away a tariffsanctioned right with nothing more than a “concern” that a right of first refusal may be 

leading towards rates that may become too high. It states that if the Commission believes 

that the problem is that rates will become too high, it should deal with the problem 

directly by lowering them, rather than by eliminating rights of first refusal.43

24. FirstEnergy Service Company takes issue with the Commission’s reliance on 

National Fuel and asserts that a tenuous application of theory cannot support a 

 42 Business Roundtable v. SEC, 647 F.3d 1144 (D.C. Cir. 2011).

43 Baltimore Gas & Electric at 18 (quoting National Fuel Gas Supply Corp. v. 

FERC, 468 F.3d 831, 844 (D.C. Cir. 2006)).
Docket No. RM10-23-001 -23-

rulemaking.44 According to FirstEnergy Service Company, while the court in National 

Fuel acknowledged the possibility of an agency proceeding on theory alone to support a 

rulemaking, it also cautioned that such reliance required a substantial showing of the need 

in order to proceed.45 California ISO makes a similar argument. Both FirstEnergy

Service Company and California ISO assert that the Commission has not made any 

showing similar to that described in National Fuel to justify its sole reliance on theory.

25. On the issue of the Commission’s nonincumbent transmission developer reforms, 

Southern Companies assert that they do not have a federal right of first refusal and that 

there are no restrictions on a nonincumbent developer’s ability to pursue transmission 

projects in the SERTP planning process. Southern Companies argue the Commission has 

failed to articulate a legal basis for imposing its nonincumbent requirements upon 

Southern Companies, when it has no right of first refusal. Furthermore, Southern 

Companies argue that the reason for the lack of nonincumbents in the Southeast is 

because the incumbent transmission owners have developed a robust transmission grid 

and are adequately investing in transmission. Southern Companies also assert that there 

have been no significant merchant transmission projects within their footprint because 

 44 FirstEnergy Service Company at 15 (citing National Fuel Supply Corp. v. 

FERC, 468 F.3d 831 (D.C. Cir. 2006) (National Fuel)).

45 FirstEnergy Service Company at 15 (quoting National Fuel, 468 F.3d 831 at 

844-45).
Docket No. RM10-23-001 -24-

there is no congestion and generation is not remotely located. Thus, Southern Companies 

argue that Order No. 1000’s generic findings of undue discrimination against 

nonincumbents are counter to record evidence and that to date no nonincumbents have 

proposed alternative transmission projects in the SERTP. In addition, Southern 

Companies state that the Commission does not have the authority to impose 

nonincumbent-related development rights sua sponte generically upon the industry. 

26. Petitioners also argue that the Commission failed to identify any established 

theoretical principles in support of its reforms.46 Southern Companies maintain that the 

Commission’s reasoning does not meet the scientific standards of a “good theory,” which 

it defines as satisfying two conditions: “[i]t must accurately describe a large class of 

observations on the basis of a model that contains only a few arbitrary elements, and it 

must make definite predictions about the results of future observations.”47 Xcel argues 

that if the Commission intends to rely only on theoretical evidence, it must satisfy the 

requirements of National Fuel by explaining why the individual complaint procedure 

provided an insufficient remedy.48 MISO Transmission Owners Group 2 asserts that 

 46 See, e.g., FirstEnergy Service Company; Xcel; Sponsoring PJM Transmission 

Owners; PSEG Companies; and Xcel.

47 Southern Companies at 15 (quoting Stephen Hawking & Leonard Mlodinow, A 

Briefer History of Time 13-14 (2005)).

48 Xcel at 13-14 (citing Nat’l Fuel, 468 F.3d 831, 834, 844 (D.C. Cir. 2006)). 
Docket No. RM10-23-001 -25-

National Fuel did not authorize the Commission to issue a rulemaking solely on the basis 

of a “theoretical threat” but indicated that if the Commission attempted to do so, it would 

be required to provide a substantial explanation. It argues that the Commission provides 

no such analysis, but rather summarily indicates that the threat of abuse “is not one that 

can be addressed adequately or efficiently through the adjudication of individual 

complaints.”49 MISO Transmission Owners Group 2 contends that a case-by-case 

analysis would be particularly appropriate in this instance given the dearth of empirical 

evidence demonstrating harm, compared to the actual examples of nonincumbent 

transmission developer participation in transmission planning processes in MISO and 

elsewhere. 

27. Other petitioners add that the reforms are unnecessary because there is evidence 

that transmission expansion has increased significantly over the past several years.50 

Large Public Power Council states that Order No. 1000 does not rely on any finding 

regarding the need to increase transmission development. Some petitioners also point to 

existing processes in the Southeast as undercutting the predicate for Order No. 1000.51 

 49 MISO Transmission Owners Group 2 at 15 (quoting Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 52).

50 See, e.g., PSEG Companies.

51 See, e.g., Ad Hoc Coalition of Southeastern Utilities; North Carolina Agencies; 

and Southern Companies.
Docket No. RM10-23-001 -26-

North Carolina Agencies assert that there is error in the Commission’s unwillingness to 

consider the highly developed planning processes in the region as a relevant factor in 

ascertaining the need for new rules. They also claim that although the anticipated 

demand for significant interregional transmission projects to transfer large amounts of 

remotely located renewable energy to fulfill public policy mandates is a major factual 

predicate for the proposals articulated, this is simply not present in the Southeast due to 

its resource base. They note that the Southeast already has a robust transmission system, 

as recognized in DOE’s 2009 Transmission Congestion Study. North Carolina Agencies 

state that utilities in the Southeast remain vertically integrated and provide bundled retail 

service; the bulk of the resulting transmission cost is included in, and recovered through, 

state approved bundled retail rates. Thus, they argue that the evidence demonstrates that 

needed transmission investment is not lacking with respect to the utilities in the 

Southeast. 

28. Southern Companies raise similar arguments with respect to existing regional 

transmission planning, interregional transmission coordination, and cost allocation 

processes in the Southeast, claiming that the new planning processes will not be 

associated with any previously unidentified new load growth, supply or demand side 

resource, or transmission service request because all of those elements are already 

addressed in the bottom-up planning processes. Southern Companies further argue that 

because Order No. 1000 lacks a process to identify new solutions, it will only serve to 
Docket No. RM10-23-001 -27-

potentially optimize existing upgrades, which is already occurring due to extensive 

coordination with neighboring utilities in the Southeast. Ad Hoc Coalition of 

Southeastern Utilities raise similar arguments, and add that Order No. 1000’s concern 

that some regional transmission planning processes permitted by Order No. 890 are only 

a forum to confirm simultaneous feasibility does not apply to planning processes in the 

Southeast.

29. Southern Companies explain that their Order No. 890 Attachment K compliance 

filing was accepted as of July 2010, and none of the changed circumstances cited in 

Order No. 1000 has occurred since then. Southern Companies assert that the 

Commission ignored evidence addressing their existing transmission planning processes 

and explaining how those processes assure consideration of better regional solutions and 

support just and reasonable rates. Southern Companies assert that unless detailed facts 

show existing cost allocation methods are impairing the proposal and consideration of 

better regional solutions, Order No. 1000 may not lawfully determine they are causing 

Southern Companies’ rates, terms, and conditions for transmission service to be unjust 

and unreasonable. They also argue that, although the Commission is permitted in certain 

circumstances to make generic findings in support of its rulemaking, specific findings for 

specific entities are required when the actual facts applicable to those entities run counter 
Docket No. RM10-23-001 -28-

to generic principles.52 They add that, on rehearing, the Commission must address 

substantial evidence that supports the justness and reasonableness of Southern 

Companies’ existing processes in determining whether the reforms of Order No. 1000 

should be applied to supplant such processes, or exclude Southern Companies from Order 

No. 1000’s generic findings. 

30. Ad Hoc Coalition of Southeastern Utilities add that there are no planning gaps that 

need to be filled in the Southeast by the Commission’s interregional coordination 

requirements. Ad Hoc Coalition of Southeastern Utilities and Southern Companies assert 

that the Southeastern utilities already share on an interregional basis data containing all of 

the information needed to make informed and efficient planning decisions. Ad Hoc 

Coalition of Southeastern Utilities further argues that the implication that additional 

interregional coordination will identify whether interregional transmission facilities are 

more efficient or cost-effective than regional transmission facilities is unfounded, and 

involves integrated resource planning analysis and ‘optimatization’ analyses along the 

seams/interfaces that already occur in the Southeast. Ad Hoc Coalition of Southeastern 

Utilities concludes that the Commission’s holdings regarding its interregional 

coordination requirements are unfounded and counter to the record evidence.

 52 Southern Companies at 92 (citing National Fuel, 468 F. 3d at 839). 
Docket No. RM10-23-001 -29-

31. Moreover, Ad Hoc Coalition of Southeastern Utilities and Southern Companies 

assert that the factual record in this rulemaking demonstrates that the required 

interregional coordination reforms are likely to do more harm than good. For instance, 

Ad Hoc Coalition of Southeastern Utilities and Southern Companies state that it is costly 

to negotiate many coordination agreements and parallel OATT language with many 

different entities and to prospectively implement multiple bureaucratic requirements.

32. Sacramento Municipal Utility District argues that a generic rule is arbitrary and 

inappropriate to address a problem that exists, if at all, only in isolated pockets.53 It also 

argues that the Commission cannot defend its actions on purely theoretical grounds 

unless it abandons its unsubstantiated claim that an actual problem exists.54 Sacramento 

Municipal Utility District states that to the extent the Commission’s rule was adopted to 

address a theoretical problem, it has failed to meet its burden of establishing that the 

burdens and costs imposed by the rule are justified by the threat to be addressed.55 With 

respect to transmission planning in particular, Sacramento Municipal Utility District 

contends that the assertion that regional planning taking place under Order No. 890 is 

 53 Sacramento Municipal Utility District at 4 (citing Associated Gas Distributors, 

824 F.2d 981 at 1019). 

54 Sacramento Municipal Utility District at 5 (citing National Fuel, 468 F.3d at 

839). 

55 Sacramento Municipal Utility District at 5 (citing National Fuel, 468 F.3d at 

844).
Docket No. RM10-23-001 -30-

insufficient and producing unjust and unreasonable rates is premised on the existence of 

an actual, not theoretical, problem. It states that there is no evidence to support this 

assertion, and no evidence that the alleged problem affects more than a few isolated 

regions of the country. Sacramento Municipal Utility District adds that Order No. 1000 

scarcely acknowledges comments documenting the success of various regional planning 

efforts, but instead refers to generalized statements of concern about potential problems 

in unidentified regions of the country involving unidentified utilities. It states that this is 

not the type of evidence upon which a rule purporting to address a national problem can 

be sustained and this is the same problem that resulted in the remand in National Fuel.

56 

It argues that the Commission failed to establish that the burdens imposed by Order No. 

1000 are justified by the threat addressed,57 and that Order No. 1000 fails the test of 

reasoned decision-making, citing the fact that Order No. 1000 failed to take into account 

whether imposition of its mandatory cost allocation provisions will discourage rather than 

facilitate regional planning. Alabama PSC likewise contends that the speculative benefits 

identified in Order No. 1000 are not legally sufficient to justify the rule’s burdens and 

disruptions and, as such, Order No. 1000 is not justified under the Commission’s 

 56 Sacramento Municipal Utility District at 32 (citing Nat’l Fuel Gas Supply Corp. 

v. FERC, 468 F.3d 831, 844 (D.C. Cir. 2006)).

57 Sacramento Municipal Utility District at 33 (citing Nat’l Fuel Gas Supply Corp. 

v. FERC, 468 F.3d 831, 844 (D.C. Cir. 2006)).
Docket No. RM10-23-001 -31-

authority under section 206. Alabama PSC encourages the Commission to consider a 

regional or case-by-case approach if the Commission continues to believe that it should 

move forward with this initiative. 

33. Similarly, Ad Hoc Coalition of Southeastern Utilities contends that Order No. 

1000 violates the guidance provided by National Fuel regarding what may be permissible 

by an order solely based upon a theory, arguing that the record demonstrates that there 

will be little benefit, and possible harm, if the interregional transmission coordination 

requirements are implemented. Additionally, Ad Hoc Coalition of Southeastern Utilities 

contend that these reforms would be burdensome to implement, because public utility 

transmission providers would have to negotiate a number of coordination agreements and 

parallel OATT language with many different entities and then prospectively implement a 

number of bureaucratic requirements.58 Southern Companies agree.

34. NARUC argues that Order No. 1000 does not identify actual concerns or problems 

or rely on any factual record, but relies entirely on the conclusory statement that planning 

and cost allocation may be impeding the development of beneficial transmission lines. It 

also argues that efforts to sort through the ambiguities and comply with Order No. 1000 

may stall existing local, regional, and DOE-funded interconnectionwide planning 

 58 Ad Hoc Coalition of Southeastern Utilities at 66 (quoting National Fuel, 468 

F.3d at 844 (arguing that the Commission must explain how the “potential danger . . . 

unsupported by a record of abuse, justifies such costly prophylactic rules.”)).
Docket No. RM10-23-001 -32-

processes, creating uncertainty and requiring limited resources to be reallocated to 

compliance filings rather than to finalizing plans. NARUC further asserts that Order No. 

1000 is premature because the results of the interconnectionwide planning process may 

eliminate the need for reform or indicate a need for different reforms.

35. Some petitioners also take issue with the Commission’s efforts to distinguish 

Order No. 1000 from Associated Gas Distributors.

59 Large Public Power Council argues 

that the Commission is in error in attempting to minimize the exacting evidentiary 

standard for generic rulemaking called for in Associated Gas Distributors on the ground 

that the impact of the decision here is not “comparable.”60 It argues that while the 

Commission states in Order No. 1000 that compliance “will involve implementation of 

additional processes and procedures” and many public utility transmission providers 

“already engage in processes and procedures of this type,” the goal of Order No. 1000 is 

to remedy unjust and unreasonable rates on a national basis by implementing new 

planning and cost recovery procedures.61 Large Public Power Council asserts that even if 

 59 See, e.g., Large Public Power Council; Ad Hoc Coalition of Southeastern 

Utilities; MISO Transmission Owners Group 2; Southern Companies; and Sacramento 

Municipal Utility District.

60 Large Public Power Council at 17 (quoting Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 56).

61 Large Public Power Council at 17-18 (quoting Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at 56).
Docket No. RM10-23-001 -33-

this is not the case, the implications of Order No. 1000 involve cost shifting for the 

recovery of potentially hundreds of billions of dollars in transmission investment. Ad 

Hoc Coalition of Southeastern Utilities raises similar concerns, explaining that the 

attempt to distinguish Associated Gas Distributors “gives short shrift to the 

Commission’s ambitions in promulgating Order No. 1000, which is to implement new 

planning and cost recovery procedures.”62 

36. MISO Transmission Owners Group 2 maintains that, while the Commission 

argued that Associated Gas Distributors states that it need not provide empirical data for 

every proposition upon which it depends, the Commission has a duty to “respond 

meaningfully” to the objections raised by opponents of its proposal, which it failed to 

do.63 Southern Companies argue that the Commission did not squarely address 

comments asserting that there was no need for an industrywide solution when the 

problem applies only to a limited portion of the industry.

37. Similarly, California ISO argues that the Commission cannot find support in 

Associated Gas Distributors for acting based on a theoretical threat.64 In contrast to 

Associated Gas Distributors, California ISO asserts that the Commission is not relying on 

 62 Ad Hoc Coalition of Southeastern Utilities at 18.

63 MISO Transmission Owners Group 2 at 13.

64 California ISO at 16 (citing Associated Gas, 824 F.2d 981 at 1008-09).
Docket No. RM10-23-001 -34-

an economic theory to determine the means for achieving its goal, but rather is attempting 

to rely on theory to establish the statutory predicate for action.65 Furthermore, California 

ISO argues that the Commission’s hypothesis that, in a regulated market, the absence of 

an ex ante cost allocation method will cause rates to be unjust or unreasonable is not 

based on an established economic theory. California ISO asserts that there is no 

empirical evidence for this hypothesis, and that the Commission has not cited any peerreviewed or other economic analysis supporting its conclusion. As such, California ISO 

concludes that such a hypothesis cannot support action under section 206.

38. In addition, California ISO argues that the Commission has not identified any 

evidence to support a causal connection between a cost allocation methodology and 

improved cost-effectiveness. California ISO acknowledges two commenters that 

provided concrete examples that uncertainty about cost allocation was preventing some 

projects from going forward, but argues that these examples do not support the 

Commission’s finding.

39. MISO Transmission Owners Group 2 asserts that the Commission relies on 

general suppositions to support its mandate that all rights of first refusal be removed from 

Commission-jurisdictional tariffs and contracts. For example, it states that Order No. 

1000 states that nonincumbent transmission developers seeking to invest in transmission 

 65 California ISO at 17 (citing Associated Gas, 824 F.2d 981 at 1008-09).
Docket No. RM10-23-001 -35-

can be discouraged from doing so, but the Commission never identifies a single instance 

of a nonincumbent transmission developer foregoing an opportunity to invest in a 

transmission facility because of any existing federal right of first refusal. MISO 

Transmission Owners Group 2 maintains that the Commission ignored examples it and 

others gave of nonincumbent transmission developer involvement in regional planning 

processes, such as the CapX2020 Transmission Capacity Expansion Initiative, in which 

eleven entities, including MISO Transmission Owners, nonincumbent transmission 

developers, and transmission dependent utilities are engaged in a collaborative effort to 

construct nearly 700 miles of new extra-high voltage transmission facilities from the 

Dakotas to Wisconsin. 

40. Similarly, MISO argues that while its existing regional planning processes have 

resulted in significant transmission expansion in the past and will result in even greater 

transmission construction in the future, Order No. 1000 does not identify any evidence 

that transmission planning, expansion and/or cost allocation have been hindered or 

harmed by the Transmission Owners Agreement provisions relating to the obligation to 

build, including any associated rights whose nature and effects may resemble rights of 

first refusal. It asserts that the Commission cannot use any evidence that may involve 

other RTO, ISOs, or public utilities to draw conclusions about any unjustness and 

unreasonableness of provisions in MISO’s Transmission Owners Agreement, and to 

require the removal or modification of such provisions.
Docket No. RM10-23-001 -36-

41. Baltimore Gas & Electric states that the Commission’s rationale for eliminating 

the right of first refusal has no applicability to it and other transmission owner members 

of PJM since they have all relinquished transmission planning decisions to PJM. 

According to Baltimore Gas & Electric, it does not matter that transmission owners have 

an economic incentive to be unduly discriminatory in transmission planning once they 

have transferred that role to an RTO. Baltimore Gas & Electric asserts that PJM’s Order 

No. 890 compliance filing ensures an open, transparent, and stakeholder-participatory 

transmission planning process that no transmission owner member has the ability to 

manipulate for anticompetitive purposes. In any event, Baltimore Gas & Electric states 

that the opportunity for undue discrimination existed in the abstract when federal right of 

first refusal rights were initially approved by the Commission, and that nothing has 

changed to warrant their removal now. Baltimore Gas & Electric adds that there are 

opportunities for any lawfully sanctioned activity to be misused. Thus, Baltimore Gas & 

Electric concludes that speculation as to how some bad actors may misuse rights is not a 

rational basis for eliminating the rights for all actors.

42. Similarly, Sunflower, Mid-Kansas, and Western Farmers dispute Order No. 

1000’s conclusion that it is not in the economic self-interest of public utility transmission 

providers, at least in the SPP region, to expand the grid to permit access to competing 
Docket No. RM10-23-001 -37-

sources of supply to serve their customers.66 They note that no state in the SPP region 

has enacted retail competition and, consequently, those states would not stand for 

anticompetitive behavior by incumbent transmission owners that would result in higher 

rates to consumers.67

43. Petitioners also disagree with the Commission’s conclusion that it can rely on the 

benefits of competition to support the rule without a ground for a reasonable expectation 

that competition may have some beneficial impact.68 These petitioners disagree with the 

Commission’s interpretation of, and citation to, Wisconsin Gas.69 Ad Hoc Coalition of 

Southeastern Utilities and Large Public Power Council argue that Wisconsin Gas dealt 

with the benefits of competition associated with promoting competitive sales of natural 

gas, which Congress made a national policy. In contrast, they argue that there is no 

indication that Congress has endorsed promoting competition for the development of 

 66 Sunflower, Mid-Kansas, and Western Farmers at 3 (citing Order No. 1000, 

FERC Stats. & Regs. ¶ 31,323 at P 254).

67 Sunflower, Mid-Kansas, and Western Farmers argue that this is borne out by 

activity in SPP of at least two independent transmission developers (ITC Great Plains, 

LLC and Prairie Wind Transmission, LLC).

68 See, e.g., PSEG Companies; Ad Hoc Coalition of Southeastern Utilities at 55 

(quoting Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 268); and Large Public 

Power Council.

69 See, e.g., PSEG Companies; Ad Hoc Coalition of Southeastern Utilities at 56 

(citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 268, n.243); and Large Public 

Power Council.
Docket No. RM10-23-001 -38-

transmission infrastructure. Large Public Power Council quotes the language from 

Wisconsin Gas where the court stated that “unsupported or abstract allegations of benefits 

that will accrue from increased competition cannot substitute for a conscientious effort to 

take into account what is known as to past experience and what is reasonably predictable 

about the future.” 70 Large Public Power Council asserts that here, the Commission not 

only lacks any legitimate basis for a presumption that competition in the transmission 

development business serves the public interest, but fails to amass any evidence for its 

view. 

44. A number of petitioners question the Commission’s assertion that adding more 

transmission developers may lead to the identification of more efficient alternatives.71 

Oklahoma Gas and Electric Company asserts that the Commission has not supported the 

assumption that competition between potential developers in the process of evaluating 

and selecting proposed projects will result in more cost-effective transmission service 

rates. Sponsoring PJM Transmission Owners argue that precedent does not support the 

Commission’s conclusion that the mere invocation of general beneficial impacts of 

 70 Large Public Power Council at 28 (quoting Wisconsin Gas, 770 F.2d 1144 at 

1158).

71 See, e.g., Southern Companies; Sponsoring PJM Transmission Owners at 16, 20 

(citing Williston Basin Interstate Pipeline Co. v. FERC, 358 F.3d 45, 50 (D.C. Cir. 

2004)); Ad Hoc Coalition of Southeastern Utilities at 57 (quoting Washington Gas, 770 

F.2d at 1158). 
Docket No. RM10-23-001 -39-

competition suffices to support modifying rates pursuant to section 206. Sponsoring PJM 

Transmission Owners also assert the real issue is not competition between transmission 

providers, but rather which entity will be the monopoly owner of a transmission line. 

Oklahoma Gas and Electric Company states that nothing in Order No. 1000 will result in 

head-to-head competition between service providers, or between competing lines. It 

elaborates that the market will not be choosing who constructs new projects, but rather 

the stakeholder process will be used to make a choice based on uncertain estimates and 

inputs.

45. Sponsoring PJM Transmission Owners argue the Commission has not explained or 

demonstrated how competition among transmission developers would reduce the cost of 

transmission construction and consequently transmission service. For instance, 

Sponsoring PJM Transmission Owners state that even if a nonincumbent submits a 

proposal that it projects will have the lowest cost, the Commission has produced no 

evidence that its actual costs of construction will be lower than the cost the incumbent 

would incur. Instead, they argue that the incumbent is far more likely to have existing 

rights of way and more experience with construction and logistical issues that may arise 

in its area, and thus is better positioned politically to overcome local objections to siting. 

Baltimore Gas & Electric notes that the Commission has recognized that incumbents 

have certain advantages, such as a unique knowledge of their own systems and other 

matters, and that the Commission has stated that such factors can be highlighted in the 
Docket No. RM10-23-001 -40-

decisional process leading to project selection. Baltimore Gas & Electric states that it is 

thus unclear to why the Commission would require that the existing federal right of first 

refusal provision should be eliminated if the same result can be achieved in the decisional 

process by taking into account that the incumbent is better placed to construct and own a 

project.

46. Sponsoring PJM Transmission Owners argue the Commission has not explained 

how any reduction in construction costs – assuming it could be achieved – would 

translate into lower rates, after taking into account differing corporate structures, rates of 

return, and Commission-granted incentives. Ad Hoc Coalition of Southeastern Utilities 

and Large Public Power Council argue that the efficiencies that the Commission 

presumes will be associated with its decisions, and that it assumes will overcome added 

costs and risks, are not a matter that the Commission is entitled to presume. Xcel argues 

that the Commission’s rationale to increase competition does not apply to reliability 

projects, which have the narrow function of ensuring reliable service to customers.72

47. Some petitioners argue that the mixed record does not justify the Commissions 

ruling.73 For instance, petitioners argue that the Commission must, as a matter of law, 

 72 Xcel at 12-13 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 284-

85). 

73 See, e.g., Baltimore Gas & Electric at 16-17 (citing Central Iowa Power 

Cooperative v. FERC, 606 F.2d 1156 (D.C. Cir. 1979)).
Docket No. RM10-23-001 -41-

take notice of efficiencies lost and reliability problems created by the Commission’s 

decision.74 Specifically, Large Public Power Council argues that planning engineers will 

spend time addressing stakeholder and competitors’ concerns in Commission-sponsored 

planning forums rather than working to meet the needs of their native loads. 

Additionally, it states that countless hours will be needed to perform studies, reengineer 

systems, and coordinate third-party construction schedules and priorities. Ameren adds 

that MISO will have to expend considerable resources to re-assess years of transmission 

planning work to apply the new rule. 

48. Sponsoring PJM Transmission Owners argue the Commission has ignored other 

potential costs associated with eliminating the right of first refusal, including expensive 

mitigation plans in the event that a nonincumbent abandons a reliability project. 

Similarly, Xcel asserts that Commission’s statement in P 344 of Order No. 1000 indicates 

the Commission’s belief that certain nonincumbent transmission developers will not be 

able to complete the projects assigned to them. Xcel adds that other risks will increase 

from the utility transmission providers’ inability to guarantee reliable service, such as 

litigation arising from outages.

 74 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Large Public Power 

Council at 27 (citing National Fuel and Tenneco Gas).
Docket No. RM10-23-001 -42-

49. Ad Hoc Coalition of Southeastern Utilities asserts that Commission policy has 

persistently treated transmission as a natural monopoly, and therefore the court’s decision 

in Wisconsin Gas should serve as a warning light rather than the license that the 

Commission assumes it to be. Southern Companies contend that Order No. 1000

assumes that vertical integration is unduly discriminatory because it requires 

nonincumbents to have a right to propose, own, build and operate integrated network 

elements. Southern Companies assert that they operate under the traditional regulatory 

compact, with efficiencies of vertical integration, economy of scale, duty to serve, and 

adequate return on investment, which ensures necessary transmission is constructed on 

schedule and is appropriately operated and maintained. Southern Companies state that by 

not recognizing and rationally explaining this change in precedent, the Commission has 

acted arbitrarily and capriciously. 

C. Commission Determination

50. We deny the requests for rehearing that challenge the Commission’s determination 

that the reforms instituted by Order No. 1000 are needed. As we noted in Order No. 

1000, changes are at work in the electric utility industry that have created an additional, 

and potentially significant, need for new transmission infrastructure. Order No. 1000 

cited studies conducted by the North American Electric Reliability Corporation (NERC) 

and Edison Electric Institute (EEI) that confirmed an increase in transmission 

development over the last several years, and the Commission cited to an EEI-
Docket No. RM10-23-001 -43-

commissioned Brattle Group study suggesting that approximately $298 billion in new 

transmission facilities will be required over the period 2010 to 2030.75 Order No. 1000 

explained that these changes are being driven in large part by the changes in the 

generation mix, and it cited NERC’s 2009 Assessment, which stated that existing and 

potential environmental regulation and state renewable portfolio standards are driving 

significant changes in the generation mix, resulting in early retirements of coal-fired 

generation, an increasing reliance on natural gas, and large-scale integration of renewable 

generation.76

51. The Commission concluded in Order No. 1000 that current transmission planning 

and cost allocation requirements are inadequate to meet these challenges. Current 

requirements threaten to thwart identification of transmission solutions that are more 

efficient or cost-effective than would be the case without the reforms contained in Order 

No. 1000. As a result, the Commission concluded – and we affirm here – that it is 

necessary and appropriate that we take proactive steps to ensure that this threat does not 

result in such adverse consequences. The narrow focus of current transmission planning 

requirements, and the shortcomings of current cost allocation practices, represent a threat

that justifies Order No. 1000’s requirements, and it is not one that the Commission can 

 75 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 44-45.

76 Id. P 45.
Docket No. RM10-23-001 -44-

address adequately or efficiently through the adjudication of individual complaints.77 

The Commission explained that the actual experiences cited in the record provide

additional support for action but are not necessary to justify the remedy, and that the 

remedy is justified by the theoretical threat identified therein.

52. Order No. 1000 addresses the inadequacy of existing requirements by establishing 

minimum criteria that the transmission planning process must satisfy, including general 

principles that cost allocation practices must follow. These criteria are interrelated and 

were designed as a package to ensure that an effective transmission planning process is in 

place in each region.78 Effective transmission planning requires coordination among 

transmission planning entities; is open and transparent, which is necessary for any 

process that involves multiple entities with a variety of needs or views regarding this 

process; considers all transmission needs of all transmission customers; results in an 

identifiable product reflecting regional determinations; and does not create unnecessary 

barriers to the consideration of good ideas or the selection of the most advantageous

transmission solutions, regardless of whether the developer of a transmission solution is 

an incumbent transmission developer/provider or a nonincumbent transmission 

 77 Id. P 52.

78 Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at 42; Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 at P 47.
Docket No. RM10-23-001 -45-

developer. Effective transmission planning should also recognize that there may be even 

more efficient or cost-effective solutions that are identified through interregional 

transmission coordination efforts than those solutions identified in a regional 

transmission planning process. Finally, effective transmission planning is performed 

with a clear ex ante understanding of who will pay for a facility selected in a regional 

transmission plan for purposes of cost allocation. Without that understanding, the 

likelihood that selected facilities will be implemented is diminished, undermining the 

entire purpose of the transmission planning process, namely, the development of efficient 

and cost-effective transmission solutions.

53. These basic principles encompass all the reforms found in Order No. 1000 and 

show how the reforms are interrelated to serve a common purpose. If any of the reforms 

are absent, the effectiveness of transmission planning and cost allocation processes would 

be undermined. We are not able to identify any argument raised on rehearing that 

demonstrates that any of these principles are invalid. Instead, the overriding objection 

raised by the petitioners to the Commission’s discussion of the need for the reforms in 

Order No. 1000 is that the Commission either has not demonstrated the existence of a 

problem that requires correction through implementation of new requirements, or that it 

has not shown that the problems it has identified exist in all regions of the country, thus 

undermining the need for generic rules that apply to all public utility transmission 

providers. The petitioners that raise these objections maintain that the development of 
Docket No. RM10-23-001 -46-

needed transmission facilities is proceeding apace, either nationally or in a specific 

region, and thus currently there is nothing amiss that requires correction. From this, 

petitioners conclude that the Commission has not presented substantial evidence of a 

current problem that shows the need for its reforms. 

54. We disagree. As the Commission noted in Order No. 1000, the expansion of the 

transmission grid is the result of a complex and often contentious process that occurs over 

a long time horizon.79 It is capital intensive and subject to numerous regulatory hurdles. 

It is further complicated by the problem of determining how costs for the expansion will 

be allocated in instances when multiple entities benefit. Given the fundamental 

importance of transmission infrastructure, and the many difficulties involved in its 

development, including the long lead times involved, we continue to believe that a 

proactive approach is necessary. As discussed in Order No. 1000 and reiterated below, 

such an approach is fully consistent with the applicable legal requirements.

55. Petitioners’ specific arguments that the Commission has not adequately justified 

the need for the reforms in Order No. 1000 fall under six broad headings: (1) the 

Commission has failed to demonstrate that any existing rate, term or condition of or for 

transmission service is unjust and unreasonable or unduly discriminatory or preferential; 

(2) the Commission supports its need for reform based solely on the existence of a 

 79 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 50.
Docket No. RM10-23-001 -47-

theoretical threat, and it is not clear in National Fuel whether such a decision can be 

supported on this basis alone: (3) the theoretical threat that the Commission uses to 

justify its reforms in Order No. 1000 amounts to hypothesis and speculation and ignores 

existing realities, especially in the Southeast; (4) the Commission has not identified a 

theoretical threat that justifies the removal of federal rights of first refusal from 

Commission-jurisdictional tariffs and agreements and that the Commission has not shown 

that there is a reasonable expectation that competition in transmission development may 

have some beneficial impact on rates; (5) the burdens imposed by the Commission’s 

reforms outweigh the benefits; and (6) other issues that do not fall into a general 

category. We address each of these arguments in turn below. 

Whether is it necessary that the Commission demonstrate that any 

existing rate, term or condition of or for transmission service is 

unjust and unreasonable or unduly discriminatory or preferential 

56. California ISO, PPL Companies, Southern Companies, and Oklahoma Gas and 

Electric Company challenge the Commission on the grounds that it has failed to 

demonstrate that any existing rate, term or condition of or for transmission service is 

unjust and unreasonable or unduly discriminatory or preferential. However, the 

Commission is not required to make individual findings concerning the rates of 

individual public utility transmission providers when proceeding under FPA section 206 
Docket No. RM10-23-001 -48-

by means of a generic rule.80 When the Commission proceeds by rule it can conclude 

that “any tariff violating the rule would have such adverse effects . . . as to render it 

‘unjust and unreasonable’” within the meaning of section 206 of the FPA.81 

57. One circumstance that can justify the application of this principle is the existence 

of a threat that, in the absence of Commission action, would materialize and cause rates 

to be unjust and unreasonable, or unduly discriminatory or preferential. A threat that has 

not yet materialized is what the court in National Fuel described as a “theoretical threat.” 

The Commission justified the need for the reforms in Order No. 1000 based on such a 

threat created by the inadequacy of existing transmission planning and cost allocation 

requirements to meet the anticipated challenges facing the industry, a threat whose 

existence was illustrated by actual problems that the Commission noted in the order, but 

that are not necessary to justify its response to the threat.82 

Whether the reforms in Order No. 1000 can be supported on the 

basis of a theoretical threat alone

58. A number of petitioners call into question the use of a theoretical threat as the 

basis for the Commission’s reforms.83 For example, Ad Hoc Coalition of Southeastern 

 80 Associated Gas Distributors v. FERC, 824 F.2d at 1008.

81 Id. (emphasis in original).

82 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 53.

83 See, e.g., Ad Hoc Coalition of Southeastern Utilities; and Large Public Power 

(continued...)
Docket No. RM10-23-001 -49-

Utilities maintains that, based on National Fuel, it is not clear whether a decision might 

be supported by theory alone. We disagree that the court in National Fuel was noncommittal on this point. The court specifically stated that the Commission could choose 

“to rely solely on a theoretical threat.”84 While it listed certain matters that the 

Commission would need to address on remand, it did not comment on the possibility of 

addressing them successfully, nor did it say anything to suggest that this approach might 

be defective in principle. FirstEnergy Service Company argues that the list of specific 

matters that the court listed defines the showing that must be made to rely on a theoretical 

threat in all cases. However, the court’s list of matters to be addressed on remand was 

simply a reflection of the specific issues it saw in the case at hand, not what was required 

in all cases. Moreover, when the court stated in National Fuel that it expressed “no view 

here whether a theoretical threat alone would justify an order. . . ,”85 it was referring to 

the justification of an order in the matter at hand, not any and every possible proceeding. 

Additionally, we note that the same court subsequently reconfirmed the legitimacy of 

 

Council.

84 National Fuel, 468 F.3d at 844.

85 Id. at 844.
Docket No. RM10-23-001 -50-

reliance on theoretical threats, and it based its conclusion directly on the ruling it made in 

National Fuel.

86 

Whether the Commission’s argument that the reforms in Order No. 

1000 are needed amounts to hypothesis and speculation and ignores 

existing realities, especially in the Southeast

59. Several petitioners characterize the Commission’s approach as based on 

hypothesis and speculation. For example, Southern Companies claim that the 

Commission is making “little more than a guess – a speculative hypothesis,”87 and Ad 

Hoc Coalition of Southeastern Utilities and Alabama PSC also claim that the 

Commission is acting on mere conjecture. Southern Companies insist that the 

Commission must provide detailed facts showing that existing cost allocation methods 

are impairing better regional transmission solutions. NARUC states that the Commission 

does not identify actual concerns or problems or rely on any factual record and instead 

proceeds in a conclusory fashion. Some petitioners also maintain that the existing 

situation in the Southeast undercuts the Commission’s position. 

 86 BNSF Railway Co. v. Surface Transportation Board, 526 F.3d 770, 778 (D.C. 

Cir. 2008) (BNSF Railway Co.) (finding that the Surface Transportation Board could 

adopt a new method to correct excessive railroad rates arising through gaming behavior 

by the railroads even when there was no evidence of such behavior on their part). 

87 Southern Companies at 16. 
Docket No. RM10-23-001 -51-

60. As an initial matter, we note that, based on our expertise and knowledge of the 

industry, we do not consider it to be speculation or conjecture to conclude that regional 

transmission planning is more effective if it results in a transmission plan, is open and 

transparent, and considers all transmission needs. Nor do we consider it speculation or 

conjecture to state that barriers to the proposal and evaluation of alternative transmission 

solutions will inhibit more efficient or cost-effective transmission solutions, or that the 

implementation of transmission plans will be improved where there is a clear ex ante 

understanding of who will pay for the facilities selected in the regional transmission plan 

for purposes of cost allocation. As we explain in the following discussion, such 

propositions are fully consistent with the grounds for action that courts have accepted in 

the past. 

61. To argue that drawing such conclusions amounts to speculation or conjecture also 

conflicts with the principle articulated above that the Commission is not required to make 

individual findings under section 206 when formulating generic rules. They also imply 

that a threat that can justify Commission action in a rulemaking must be actual, i.e., one 

whose consequences have been realized, not one whose consequences are anticipated or, 

as the court expressed it in National Fuel, a threat that is “theoretical.” 

62. These criticisms thus mischaracterize what the courts mean by proceeding on the 

basis of a theoretical threat. It means to proceed on the basis of a particular type of fact, 

“generic” facts that constitute the basis for “generic factual predictions” that can 
Docket No. RM10-23-001 -52-

constitute a rational basis for an agency’s decision.88 The court in Associated Gas 

Producers gave the following as an example of an acceptable generic factual prediction: 

“the increased incentive to compete vigorously in the market would eventually lead to 

lower prices for all consumers.”89 The court treated such predictions as based on 

behavioral assumptions that are not subject to serious dispute. Thus the court stated that 

“[a]gencies do not need to conduct experiments in order to rely on the prediction that an 

unsupported stone will fall; nor need they do so for predictions that competition will 

normally lead to lower prices.”90 Indeed, the court acknowledged that such propositions 

can be accepted without record evidence when the prediction is viewed “as at least likely 

enough to be within the Commission’s authority.”91

63. Other courts have recognized that when promulgating rules of general and 

prospective applicability, agencies can draw “factual inferences . . . in the formulation of 

a basically legislative-type judgment, for prospective application only.”92 Such 

judgments are closely bound up to what are sometimes referred to as “legislative facts,” 

 88 Associated Gas Distributors, 824 F.2d 981 at1008.

89 Id. (citing Wisconsin Gas, 770 F2d at 1161).

90 Id. at 1008-9. 

91 Id. at 1008.

92 United States v. Florida East Coast Ry., 410 U.S. 224, 246 (1973); United Air 

Lines, Inc. v. Civil Aeronautics Board, 766 F.2d 1107, 1119 (7th Cir 1985).
Docket No. RM10-23-001 -53-

i.e., “facts which help the tribunal determine the content of law and of policy and help the 

tribunal to exercise its judgment or discretion in determining what course of action to 

take.”93 The District of Columbia Circuit has stated that “legislative facts are crucial to 

the prediction of future events and to the evaluation of certain risks, both of which are 

inherent in administrative policymaking.”94 The Supreme Court has ruled that when 

dealing with matters that are “primarily of a judgmental or predictive nature . . . complete 

factual support in the record for [an agency’s] judgment or prediction is not possible or 

required; ‘a forecast of the direction in which future public interest lies necessarily 

involves deductions based on the expert knowledge of the agency.’”95 This is precisely 

what is involved in the Commission’s reasoning in Order No. 1000. 

64. We disagree with the arguments made by various petitioners that we have ignored 

evidence that disproves our reasoning. The evidence in question consists of a description 

of the current state of transmission planning and development in a specific region 

combined with an expression of satisfaction with the current situation. For example, 

 93 Association of National Advertisers, Inc., v. FTC, 627 F.2d 1151, 1161-62 (D.C. 

Cir. 1979) (Ass’n of National Advertisers) (quoting 2 K. Davis, Administrative Law 

Treatise, § 15.03, at 353 (1958)). 

94 Id. at 1162.

95 FCC v. National Citizens Committee for Broadcasting, 436 U.S. 775, 814 

(1978) (quoting FPC v. Transcontinental Gas Pipe Line Corp., 365 U.S. 1, 29 (1961)); 

see also Ass’n of National Advertisers, Inc., 627 F.2d at 1162.
Docket No. RM10-23-001 -54-

North Carolina Agencies state that there is no evidence that transmission is lacking in the 

Southeast and that there is no need in this region for transmission projects that can 

transfer large amounts of renewable energy. North Carolina Agencies state that the 

transmission planning processes in the Southeast are already highly developed, and 

Southern Companies state that in the Southeast all transmission needs have already been 

planned for. 

65. First, the Commission is authorized not simply to make generic findings but also 

to act on generic factual predictions.96 To state that the facts in a particular region run 

counter to the Commission’s assessment of the future course of events is to argue either 

that present circumstances can be expected to persist into the future or that certain basic 

principles, such as the proposition that transmission developers are more likely to invest 

if they have a mechanism by which their costs will be allocated, do not apply in the 

region. We do not find the latter sort of claim to be credible, and the former claim simply 

overlooks the fact that the present is not a prediction of the future. The Commission is 

authorized to make rules with prospective effect that will prevent situations that are 

inconsistent with the FPA from occurring, which means that it is authorized to consider 

how the future may be different from the present if the rules it proposes are not adopted. 

We thus also reject Sacramento Municipal Utility Districts’ claim that the Commission 

 96 Associated Gas Distributors, 824 F.2d at 1008.
Docket No. RM10-23-001 -55-

cannot act unless it shows the existence of an “actual problem” in a particular region, a 

claim that lies at the root of all the arguments that petitioners make on this point. An 

“actual problem” is what one has when a theoretical threat comes to fruition. To insist 

that the Commission must identify the existence of an actual problem in the present 

before it can act is thus to deny that a theoretical threat that one reasonably concludes 

exists can be a basis for action. Such a conclusion is inconsistent with the cases we have 

cited on this point.97

66. In addition, these arguments overlook the fact that in Order No. 1000, the 

Commission identifies a minimum set of requirements that must be met to ensure that 

transmission planning processes and cost allocation mechanisms result in Commissionjurisdictional services being provided at rates, terms, and conditions that are just and 

reasonable and not unduly discriminatory or preferential. Given that the requirements are 

minimum requirements, it would not be surprising that some current practices in some 

regions may already satisfy many of them. If that is the case, the public utility 

transmission providers concerned need only show in their compliance filing how current 

practices in their regions satisfy the Commission’s standards. This does not mean that 

the reforms are not needed, as all of these requirements are not satisfied in all regions. 

We thus do not consider Alabama PSC’s proposal of a regional or case-by-case approach 

 97 See, e.g., BNSF Railway Co., 526 F.3d at 778.
Docket No. RM10-23-001 -56-

for applying these reforms to be appropriate or necessary. We also disagree with 

Southern Companies and others that assert that there is not an issue to be remedied in 

their respective regions. As we note above, if public utility transmission providers 

believe that they already satisfy the minimum requirements in Order No. 1000, they may 

seek to demonstrate this in their compliance filings.

67. The concept of minimum requirements supplies the answer to Southern 

Companies argument that there is no basis for requiring them to adopt the nonincumbent 

transmission developer reforms of Order No. 1000 because they do not have a federal 

right of first refusal and because there are no restrictions on nonincumbent transmission 

projects in the SERTP planning process. Southern Companies also note that to date no 

nonincumbents have proposed projects in SERTP. They attribute this to incumbents, 

who they argue have developed a robust transmission grid and are adequately investing in 

transmission. However, the purpose of the minimum requirements for nonincumbent 

transmission developers is to provide objective criteria that can help ensure that the lack 

of nonincumbent participation will not be attributable to lack of equal treatment or some 

other reason identified in Order No. 1000 as an impairment to the identification and 

evaluation of more efficient or cost-effective alternatives. Moreover, if the requirements 

of Order No. 1000 are in fact already met in SERTP, then Southern Companies need only 

show in their compliance filing how current practices satisfy the Commission’s 

requirements. Finally, Southern Companies state the Commission has no authority to 
Docket No. RM10-23-001 -57-

impose nonincumbent development rights, but the Commission is not imposing any such 

rights in Order No. 1000. It is simply establishing minimum requirements for the 

treatment of nonincumbent transmission developers in the transmission planning process. 

These requirements do not confer any rights to develop a facility. They only confer a 

right to have a proposal considered. 

68. Some petitioners confuse agency judgments based on legislative facts, i.e., factual 

inferences made in light of the policy underlying a statute, with formal academic theories. 

Southern Companies maintain that the theoretical basis of Order No. 1000 does not 

constitute good theory by scientific standards.98 California ISO argues that the 

Commission’s hypothesis that the absence of a regional cost allocation method will cause 

rates to be unjust or unreasonable is not based on an established economic theory and the 

Commission cites no peer-reviewed or other economic analysis that supports its 

conclusion. 

69. The courts have specifically rejected such notions. The court in Associated Gas 

Distributors clearly distinguished between generic factual predictions that are commonly 

made in rulemakings and the practice of economics as an academic discipline.99 The 

court criticized the use of another case, Electricity Consumers Resource Council v. 

 98 See, e.g., Southern Companies.

99 Associated Gas Distributors, 824 F.2d at 1008.
Docket No. RM10-23-001 -58-

FERC,

100 to invoke economic theory as a basis for decision making in a way that is 

similar to the way that Southern Companies and Ad Hoc Coalition of Southeastern 

Utilities invoke economic theory. For example, Southern Companies state that “FERC 

has pointed to no . . . established theory (such as marginal pricing at issue in Electricity 

Consumers) upon which it may rely to support the application of Order No. 1000’s 

requirements to the Southeast.”101 The court in Associated Gas Distributors stated that 

“[c]learly nothing in Electricity Consumer’s reference to ‘economic theory’ was intended 

to invalidate agency reliance on generic factual predictions merely because they are 

typically studied in the field called economics.”102 

70. This is the case because the court recognized that there was no reason that an 

agency must demonstrate the validity of well-established general principles such as “that 

competition will normally lead to lower prices.”103 Southern Companies and Ad Hoc 

Coalition of Southeastern Utilities confuse a theoretical threat, a potential threat that has 

 100 747 F.2d 1511 (D.C. Cir. 1984) (Electricity Consumers). 

101 Southern Companies at 16. 

102 Associated Gas Distributors, 824 F.2d at 1008; accord Sacramento Municipal 

Utility District v. FERC, 616 F.3d 520, 531 (D.C. Cir. 2010) (stating that “[n]either 

[Electricity] Consumers nor any other case law prevents the Commission from making 

findings based on ‘generic factual predictions’ derived from economic research and 

theory.”).

103 Associated Gas Distributors, 824 F.2d at 1009.
Docket No. RM10-23-001 -59-

not yet materialized, with a theory used in an academic discipline, an area of activity that 

is not comparable to the tasks or responsibilities entrusted to a regulatory agency. The 

type of principles that the Commission has relied upon here are fully commensurate with 

those that the court in Associated Gas Distributors said the Commission could utilize 

when addressing matters that fall within its area of expertise. For these same reasons, we 

disagree with the argument of California ISO that the Commission’s finding that the 

absence of a cost allocation method will cause rates to be unjust or unreasonable must be 

based on an established economic theory and that the Commission must cite a peerreviewed or other economic analysis that supports its conclusion. 

71. Moreover, we note that the substantial evidence standard does not require 

scientific certitude, a point which serves to dispel the confusion between theoretical 

threats and scientific theories. It only requires evidence that a “reasonable mind might 

accept” as “adequate to support a conclusion.”104 In the context of rulemakings that 

involve legislative facts and generic factual predictions, the relevant criterion is whether 

the agency has provided a reasonable explanation of the problem presented and its 

solution to it.105 A reasonable justification of a policy choice is not, and given the nature 

of the task involved cannot be, a scientific prediction. 

 104 Dickenson v. Zurko, 527 U.S. 150, 155 (1999).

105 See Federal Communications Commission v. Nat’l Citizens Comm. for 

(continued...)
Docket No. RM10-23-001 -60-

72. This point is confirmed by the discussion of theoretical threats in National Fuel. 

While some petitioners argue that this case requires substantial empirical verification of 

the existence of a theoretical threat,106 a careful examination of what the courts says 

shows that this is not correct. The court did not specify any requirements for 

demonstrating the existence of a theoretical threat other than a showing that the threat is 

“plausible.”107 A specific theoretical threat that it found met this requirement is stated in 

its entirety in the following language: 

If a pipeline did not have an affiliated marketer, it would be in 

its interest to disseminate widely information relevant to 

operating constraints, capacity, and available receipt points, 

limited only by the cost of doing so. The affiliate 

relationship, however, creates an incentive for the pipeline to 

withhold information that otherwise would be made available 

to the affiliate's competitors. Withholding this information 

from non-affiliated shippers reduces their ability to arrange 

transactions efficiently.108

 

Broadcasting, 436 U.S. 775, 814 (1978) (stating that “complete factual support in the 

record for the [agency’s] judgment or prediction is not possible or required”); Industrial 

Union v. Hodgson, 499 F.2d 467 at 475-476 (1974). Bradford Nat'l Clearing Corp. v. 

SEC, 590 F.2d 1085, 1103-04 (D.C. Cir. 1978) (judicial deference to agency increases 

where agency decision rests primarily on predictions).

106 See, e.g., Sacramento Municipal Utility District.

107 National Fuel, 468 F.3d at 840.

108 Tenneco Gas v. FERC, 969 F.2d 1187, 1197 (1992) (Tenneco Gas).
Docket No. RM10-23-001 -61-

This description of a theoretical threat, which is drawn from an earlier decision cited by 

the court in National Fuel, corresponds precisely to the type of generic factual predictions 

discussed above that can justify agency action. It focuses on an incentive to withhold 

information that is created simply by the existence of an affiliate relationship. The court 

nowhere indicated that the plausibility of this theory depended on additional confirmation 

in the form of predictive economic models or extensive empirical data. 

73. We thus disagree with Southern Companies that our use of words such as “may” 

and “could” in describing the anticipated effects of our reforms is evidence that these 

reforms are based on speculation or guesswork. When making a generic factual 

prediction, one is not predicting what will occur with certainty in every instance but 

rather what it is reasonable to conclude will occur with sufficient frequency and to a 

sufficient degree to conclude that the reforms are needed. Our use of words such as 

“may” and “could” in this context must be understood in this sense. 

74. California ISO states that the Commission is not relying on economic theory to 

determine the means for achieving its goal but rather to establish a statutory predicate for 

action. However, a theoretical threat, which should not be confused with an economic 

theory, is precisely that, a predicate for agency action. The Commission’s task is to 

assess current circumstances and to form a judgment on the steps necessary to avoid 

adverse effects on rates that it concludes are likely to arise if the present situation persists. 

We reject the idea that the only appropriate predicates for our action in this area are 
Docket No. RM10-23-001 -62-

current failures that are traceable to inadequate transmission planning and cost allocation. 

That would mean that the only predicate for action is a fully realized threat, which is 

contrary both to the clear position taken by the courts, and, given the special problems 

involved in transmission development, to the public interest.109

75. Finally, aside from National Fuel and Associated Gas Distributors, the only case 

that petitioners cite on rehearing dealing with evidentiary burdens in a rulemaking is 

Business Roundtable v. SEC. In that case, the court vacated a rule issued by the SEC on 

the grounds that it had not adequately considered the rule’s effect upon efficiency, 

competition, and capital formation. A number of petitioners describe this case as 

involving matters that are “remarkably” or “strikingly” similar to the present 

proceeding.110 However, Business Roundtable dealt with a failure by the SEC to comply 

 109 We reject for the same reasons the contention by Ad Hoc Coalition of 

Southeastern Utilities and Large Public Power Council that it is somehow significant that 

the Commission has effectively conceded that there is no evidence justifying Order No. 

1000 and it is relying on theory alone. The Commission is acting on the basis of a 

theoretical threat whose existence has been demonstrated through a reasonable 

explanation. The identification of this threat is based “on an assessment of the relevant 

market conditions” and involves “a forecast of the direction in which future public 

interest lies” which “necessarily involves deductions based on the expert knowledge of 

the agency.” Ass’n of National Advertisers, 627 F.2d at 1162 (internal citations omitted). 

Such judgments will satisfy evidentiary requirements in rulemakings such as this one. Id.

at 1161-62. 

110 See, e.g., Southern Companies; Ad Hoc Committee of Southeastern Utilities; 

and Large Public Power Council. 
Docket No. RM10-23-001 -63-

with specific provisions of the Exchange Act and the Investment Company Act of 1940 

that require it to assess the economic impacts of a new rule. The court described these 

requirements as being “unique” to the SEC.111 Requirements that apply uniquely to the 

SEC under statutes that it administers do not address requirements that apply to this 

Commission under the FPA or its compliance with them. Moreover, the petitioners that 

rely on Business Roundtable point to no requirements in the FPA that are similar to those 

that applied to the SEC under its statutes and that might show how the case applies to this 

proceeding. We are, of course, required to consider the burdens that Order No. 1000 

creates in relation to the benefits that we expect its requirements to produce.

112 However, 

we have done that and have concluded that, in light of the substantial investment in new 

transmission facilities that is generally expected to occur, the potential benefits from 

improved planning for new transmission facilities outweigh the burdens involved in 

complying with the requirements of Order No. 1000 to revise existing transmission tariffs 

and institute additional planning procedures. 

Whether the Commission has identified a theoretical threat that 

justifies the removal of federal rights of first refusal from 

Commission jurisdictional tariffs and agreements and has shown 

 111 Business Roundtable at 1148.

112 See, e.g., National Fuel, 468 F.3d at 844; Associated Gas Distributors, 824 

F.2d at 1019.
Docket No. RM10-23-001 -64-

that there is a reasonable expectation that competition in 

transmission development may have some beneficial impact on rates

76. A number of petitioners contend that the Commission has not identified a 

theoretical threat that justifies the removal of federal rights of first refusal from 

Commission jurisdictional tariffs and agreements and that the Commission has not shown 

that there is a reasonable expectation that competition in transmission development may 

have some beneficial impact on rates. In fact, the record in this proceeding includes the 

type of evidence that courts have found appropriate in these circumstances. The Federal 

Trade Commission, one of the two federal agencies responsible for enforcement of the 

antitrust laws, supported the elimination of federal rights of first refusal as a means for 

promoting consumer benefit, support that it described as consistent with antitrust policy 

disfavoring regulatory barriers to entry in all but a limited number of instances.113 While 

we possess our own expertise on barriers to entry when dealing specifically with the 

transmission grid, we note that the court in Tenneco Gas attributed considerable weight to 

analogous remarks by the Department of Justice that supported the identification of a 

theoretical threat.114 

 113 Federal Trade Commission Comments on Proposed Rule at 2, 7.

114 Tenneco Gas, 969 F.2d at 1202.
Docket No. RM10-23-001 -65-

77. Large Public Power Council maintains that Wisconsin Gas contains strictures 

regarding agency action premised on the benefits of competition that the Commission has 

violated. This case requires only “that there must be ‘ground for reasonable expectation 

that competition may have some beneficial impact.’”115 We think that there is a 

reasonable expectation that removal of a barrier to entry in the area of transmission 

development will have benefits of the type that competition creates in most industries. 

When the court in Wisconsin Gas stated that “unsupported or abstract allegations of the 

benefits that will accrue from increased competition”116 do not form an adequate basis for 

agency action, it did this in response to the Commission’s position on a complex rate 

issue whose effects were difficult to discern. Order No. 1000 does not involve a 

comparable situation. In fact, the court’s full argument was that such allegations “cannot 

substitute for ‘a conscientious effort to take into account what is known as to past 

experience and what is reasonably predictable about the future.’”117 In fact, we have 

made just such an effort, and on that basis we find it quite reasonable to expect benefits 

 115 Wisconsin Gas, 770 F.2d 1144, at 1158 (quoting FCC v. RCA Communications, 

Inc., 346 U.S. 86, 96-7 (1953)).

116 Id. at 1158.

117 Id. (quoting American Public Gas Association v. FPC, 567 F.2d 1016, 1037 

(D.C. Cir. 1977)).
Docket No. RM10-23-001 -66-

from removing barriers to transmission development. Moreover, as noted above, this 

analysis is consistent with that of the Federal Trade Commission. 

78. We also see no significance in the fact that Wisconsin Gas involved competitive 

sales of natural gas in accordance with a policy established by Congress. Ad Hoc 

Committee of Southeastern Utilities and Large Public Power Council state that Congress 

has voiced no similar policy regarding competition in the development of transmission 

infrastructure, but it likewise has not objected to it. We thus do not see how this 

difference between Wisconsin Gas and this proceeding is controlling. Barriers to entry in 

this area can adversely affect rates, and our action to ensure that such barriers in the form 

of federal rights of first refusal do not adversely affect rates is well within the scope of 

actions that we are authorized to take under section 206 of the FPA. The fact that 

Congress expressed a policy regarding competitive sales of natural gas does not affect 

this conclusion. These points also address the objections by Oklahoma Gas and Electric 

Company and Sponsoring PJM Transmission Owners that the Commission has not 

supported the conclusion that competition between potential developers will result in 

more efficient or cost effective solutions or that this conclusion suffices to support 

Commission action under section 206. 

79. Xcel and MISO Transmission Owners Group 2 argue that the Commission has not 

explained why problems created by federal rights of first refusal cannot be dealt with 

through individual complaints. Rights of first refusal create barriers to participation in 
Docket No. RM10-23-001 -67-

the transmission development process. To require nonincumbent transmission developers 

to overcome those barriers solely through individual complaint proceedings, requiring 

litigation each time they seek to engage in the development process would create 

expense, delay, and uncertainty that would serve as a further disincentive to participation. 

That is, they would have to invest in project development and participate in an extensive 

regional transmission planning process, and if the project is then taken over by an 

incumbent transmission developer/provider who exercises a federal right of first refusal, 

they would have to invest still more time and resources in litigation. As long as the 

federal right of first refusal remains in a Commission-approved tariff or agreement, their 

chances of succeeding in litigation would be severely diminished. They would likely 

forego participating in that region in the first place and place their efforts elsewhere. The 

remedy suggested by Xcel and MISO Transmission Owners Group 2 would thus itself act 

as a form of barrier to entry.

80. MISO Transmission Owners 2, Xcel, and MISO argue that the Commission has 

not identified an instance where federal rights of first refusal have led to adverse effects 

on rates, discrimination against a nonincumbent transmission developer, or failure by a 

nonincumbent to invest in a transmission facility. While the Commission did receive 

evidence that nonincumbent transmission developers experience discriminatory 
Docket No. RM10-23-001 -68-

treatment,118 we think the more important point is that the practical effect of a federal 

right of first refusal is to discourage investment by nonincumbent transmission 

developers. We do not think it is surprising that there is limited evidence of exclusion of 

nonincumbent transmission developers in a situation that discourages them from 

proposing projects in the first place. While Sponsoring PJM Transmission Owners 

contrast the evidence of specific discrimination provided in Order No. 888 to support 

open access transmission with the number of specific examples of barriers to 

participation by nonincumbent transmission developers in this proceeding, they fail to 

acknowledge that Order No. 888 and Order No. 1000 involve different factual 

circumstances and bases for Commission action. Order No. 888 dealt with instances of 

undue discrimination in transmission access involving entities that were already 

connected to the transmission grid. Order No. 1000, by contrast, deals as much or more 

with the effect on rates of excluding entities whose ability even to become involved in the 

transmission planning process is being hindered from the outset. 

81. MISO Transmission Owners 2 state that the Commission ignored the example of 

nonincumbent transmission developer participation in CapX2020, which they maintain 

shows that existing construction rights are not a disincentive to investment, at least with 

 118 See LS Power Comments on Proposed Rule at 3.
Docket No. RM10-23-001 -69-

respect to the Midwest ISO.119 However, MISO Transmission Owners 2 do not identify 

any nonincumbent transmission developer that independently proposed a transmission 

project and was able to develop it despite the existence of a federal right of first refusal, 

and initially referred only to certain transmission dependent utilities that had been 

“renters” of the transmission system”120 but that had chosen to invest in and own a 

portion of CapX2020.121 While the Commission supports investment in transmission 

infrastructure by transmission dependent utilities, the existence of a single joint project 

like CapX2020 does not demonstrate that nonincumbent transmission developers are 

treated in a manner that is not unduly discriminatory or preferential. 

82. We disagree with Baltimore Gas & Electric that if our concern is the effect of 

federal rights of first refusal on transmission rates, we should deal with rates directly 

rather than federal rights of first refusal. Barriers to entry affect markets in various ways. 

These include their ability to discourage innovation. Federal rules should not prevent 

consumers from being able to benefit from the full range of advantages that competition 

can provide, which the preservation of barriers to entry does not allow.

 119 Midwest Transmission Owners 2 Petition for Rehearing at 12.

120 Midwest Transmission Owners Reply Comments on Proposed Rule at 14.

121 Midwest Transmission Owners Comments on the Proposed Rule at 37 and 

n.89. Midwest Transmission Owners 2 consists of all the entities that compose Midwest 

Transmission Owners, with the exception of American Transmission Company LLC.
Docket No. RM10-23-001 -70-

83. We also disagree with Baltimore Gas & Electric that our rationale for eliminating 

federal rights of first refusal has no applicability to the transmission owner members of 

PJM because they have relinquished all transmission planning decisions to PJM and thus 

have no economic incentive to discriminate against nonincumbents. Even if the 

transmission owner members of PJM have no economic reason to object to development 

by nonincumbent transmission developers, this does not mean that federal rights of first 

refusal cannot adversely affect transmission rates. In other words, the Commission’s 

rationale for requiring the elimination of federal rights of first refusal is not based solely 

on the economic incentives of incumbent transmission developers/providers; it is also 

based on the belief that expanding the universe of transmission developers offering 

potential solutions can lead to the identification and evaluation of potential solutions to 

regional needs that are more efficient or cost-effective. 

84. These points apply equally to the argument of Sunflower, Mid-Kansas, and 

Western Farmers that it is not in the economic self-interest of public utility transmission 

providers in the SPP region to inhibit projects proposed by nonincumbent transmission 

developers because no state in the SPP region has enacted retail competition. For 

example, the fact that no state in the SPP region would stand for anticompetitive behavior 

by incumbent transmission developers/providers does not ensure that the potentially more 

efficient or cost-effective solutions offered by nonincumbent transmission developers 

will be considered. To do that, it is necessary to have a requirement that they be 
Docket No. RM10-23-001 -71-

considered without having to adjudicate complaints of anticompetitive behavior that 

discourage proposals of alternative solutions.

85. We disagree with Xcel that requiring the elimination of a federal right of first 

refusal for reliability projects constitutes an overly broad remedy. While Xcel may be 

correct that it is less likely that a nonincumbent transmission developer will propose a 

competing transmission project that satisfies only a specific reliability need, a 

nonincumbent transmission developer may decide to propose a transmission project that 

satisfies several regional needs, including a specific reliability need. In that instance, the 

Commission is concerned that if an incumbent transmission developer/provider has the 

ability to assert a federal right of first refusal for a transmission project because it 

addresses a reliability need, then the nonincumbent transmission developer may be 

discouraged from proposing the transmission project that satisfies several regional needs. 

In addition, we note that nothing in Order No. 1000 prevents an incumbent transmission 

developer/provider from choosing to meet a reliability need or service obligation by 

building new transmission facilities that are located solely within its retail distribution 

service territory or footprint and that is not submitted for regional cost allocation.122

86. Ad Hoc Coalition of Southeastern Utilities asserts that the Commission’s 

longstanding treatment of transmission as a natural monopoly undercuts its support for 

 122 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 262.
Docket No. RM10-23-001 -72-

competition in the development of transmission infrastructure, but we see no 

contradiction here. In dealing with transmission as a natural monopoly, the Commission 

has explained that “[t]he monopoly characteristic exists in part because entry into the 

transmission market is restricted or difficult. . . . In addition, as unit costs are less for 

larger lines and networks, transmission facilities still exhibit scale economies.”123 The 

Commission has never found that natural monopoly is antithetical to competition in all 

respects. Rather it has said “it is often better for a single owner (or group of owners) to 

build a single large transmission line rather than for many transmission owners to build 

smaller parallel lines on a non-coordinated basis.”124 This is because “effective 

competition among owners of parallel transmission lines is unlikely, and often 

impossible, with existing practices and technology.”125 This, however, does not mean 

that determining who will be the owner (or group of owners) of a particular line with 

natural monopoly characteristics cannot be done on a competitive basis or that 

competition in this connection would not promote benefits that are similar to the benefits 

 123 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Service by Public Utilities and Recovery of Stranded Costs by Public 

Utilities and Transmitting Utilities, Notice of Proposed Rulemaking and Supplemental 

Notice of Proposed Rulemaking, 60 FR 17662 (April 7, 1995), FERC Stats. &Regs. ¶ 

32,514, at 33,070 (1995).

124 Id.

125 Id.
Docket No. RM10-23-001 -73-

that it produces elsewhere in our economy, in terms of improved facilities, enhanced 

technology, or better transmission solutions generally. 

87. This point provides the answer to the Oklahoma Gas and Electric’s statement that 

nothing Order No. 1000 will result in head-to-head competition between transmission 

service providers and PJM Transmission Owners’ statement that the real issue is not 

competition between transmission service providers but rather which entity will be the 

monopoly owner of a transmission line. These statements overlook the fact that 

competitive forces can be harnessed in a number of ways. In this case, the Commission 

seeks to make it possible for nonincumbent transmission developers to compete in the 

proposal of more efficient or cost-effective transmission solutions. Oklahoma Gas and 

Electric Company states that the choice of new transmission projects will not be made in 

the market but rather in the stakeholder process, but this simply highlights the fact that 

competitive forces can be harnessed in various ways, including through the offering of 

competitive alternatives in a stakeholder process. Oklahoma Gas and Electric Company 

states that choices in the stakeholder process are based on uncertain estimates and inputs, 

but this is true of the transmission planning process whether or not it allows for 

competitive proposals.

88. The fact that incumbent transmission developers/providers may have certain 

advantages, such as rights of way and experience with the area in question, does not 

affect these conclusions. Incumbent transmission developers/providers may in some 
Docket No. RM10-23-001 -74-

situations be well-equipped to prevail in a competitive process, but this is not an 

argument against competition. One cannot presume that an incumbent transmission 

developer/provider will always be better placed to construct and own a project and that 

the transmission planning process therefore will always reach the same result with or 

without a federal right of first refusal, as Baltimore & Electric Company maintains. The 

fact that an incumbent transmission developer/provider may possess certain capabilities 

does not imply that the incumbent transmission developer/provider is more capable than 

any possible nonincumbent transmission developer in all situations. 

89. Nor do the effects of differing corporate structures, rates of return, or the other 

factors mentioned by Sponsoring PJM Transmission Owners affect our conclusion. 

These are all matters that can be considered in the transmission planning process, as can 

the issue of potential other costs and risks that Ad Hoc Coalition of Southeastern Utilities 

and Large Public Power Council propose may arise. Such matters may be relevant to the 

identification of more efficient or cost effective solutions. We do not see how they 

require one to conclude that competition will not promote more efficient or cost-effective 

solutions. 

90. Finally, the nonincumbent reforms of Order No. 1000 are not based on the 

assumption that vertical integration is unduly discriminatory. Southern Companies 

argues that vertical integration provides efficiencies and benefits to consumers, and we 

do not deny that this may be the case in some situations. However, if it is, we would 
Docket No. RM10-23-001 -75-

expect that vertically-integrated public utilities will be well positioned to compete in a 

transmission development process that is open to nonincumbent transmission developers. 

Southern Companies argument against nonincumbent transmission developer 

participation confuses the concept of vertical integration with that of monopoly. The 

existence of vertical integration does not imply that the vertically integrated public utility 

must be a monopoly. The emergence of competitive generation markets makes it no 

longer possible to argue that vertically integrated utilities are natural monopolies in all 

aspects of electric service.

126 In short, vertical integration itself is not unduly 

discriminatory, but there is no basis for claiming that vertical integration requires the 

exclusion of nonincumbent transmission developers. 

 126 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. 

& Regs. ¶ 31,036, at 31,642 (1996) (noting Congressional recognition of “rising costs 

and decreasing efficiencies of utility-owned generating facilities” and also describing the 

emergence of “non-traditional power producers . . . [that following the enactment of the 

Public Utility Regulatory Policies Act of 1978] began to build new capacity to compete 

in bulk power markets”), order on reh’g, Order No. 888-A, 62 FR 12274 (Mar. 14, 

1997), FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 

61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in 

relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 

667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). See also,

Morgan Stanley Capital Group, Inc. v. Public Utility District No. 1 of Snohomish County, 

Washington, 554 U.S. 527, 535-36 (2008) (stating that “[s]ince the 1970's . . . engineering 

innovations have lowered the cost of generating electricity and transmitting it over long 

distances, enabling new entrants to challenge the regional generating monopolies of 

traditional utilities”). 
Docket No. RM10-23-001 -76-

Whether the burdens imposed by the Commission’s reforms 

outweigh the benefits 

91. Next, we address the question of the burdens imposed by the Commission’s 

reforms. The court made clear in both National Fuel and Associated Gas Distributors

that one metric for assessing whether a rule has been adequately justified is whether the 

costs the rule imposes are reasonable in light of the threat identified.127 The Commission 

acknowledged in Order No. 1000 that its new requirements would require adoption and 

implementation of additional processes and procedures, but it noted that in many cases 

public utility transmission providers already engage in processes and procedures of the 

type in question.128 Large Public Power Council argues that the implications of Order

No. 1000 in “creating a mechanism for socializing the cost of new regional transmission 

developments are dramatic, and involve, by the Commission's own reckoning, cost 

shifting for the recovery of potentially hundreds of billions of dollars in transmission 

investment.”129 However, Order No. 1000 requires that the costs of facilities selected in a 

regional transmission plan for purposes of cost allocation be allocated in a way that is 

roughly commensurate with benefits, i.e, allocated in accordance with the requirements 

of cost causation. To the extent that Large Public Power Council’s use of the term 

 127 National Fuel, 468 F.3d at 844; Associated Gas Distributors, 824 F.2d at 1019.

128 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 56.

129 Large Public Power Council at 18. 
Docket No. RM10-23-001 -77-

“socializing” costs is meant to refer to a method of cost allocation that does not conform 

with the principle of cost causation, we disagree with that characterization of Order No. 

1000’s cost allocation requirements. Consequently, we do not see how ensuring that the 

costs of facilities selected in a regional transmission plan for purposes of cost allocation 

are allocated to those who receive benefits from the facilities represents “cost shifting” or 

an undue burden. On the contrary, it is a clear benefit because it ensures that rates for 

those facilities will be just and reasonable and not unduly discriminatory or preferential, 

and it promotes the identification of more efficient or cost-effective transmission 

solutions. Moreover, it is a benefit that is achieved at minimal cost, i.e., the cost of 

adopting and implementing additional procedures, in comparison to the estimated billions 

of dollars of needed transmission investment that current transmission planning and cost 

allocation practices have been frustrating,130 or the estimated $298 billion in investment 

in new transmission facilities that EEI suggests will be required over the period from 

2010 to 2030.131

 130 See Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 38 (discussing Brattle 

Group study contending that a large portion of projects with an estimated total cost of 

over $180 billion will not be built due to overlaps and deficiencies in transmission 

planning and cost allocation processes) .

131 See id. P 44.
Docket No. RM10-23-001 -78-

92. We likewise disagree with Ad Hoc Coalition of Southeastern Utilities’ and 

Southern Companies’ assertion that the interregional transmission coordination reforms 

are contrary to National Fuel because the burdens of such coordination outweigh any 

potential benefits. We note that Order No. 1000 provided a sufficient rationale for the 

need for specific reform of the interregional transmission coordination requirements. 

Order No. 1000 explained that “[c]lear and transparent procedures that result in the 

sharing of information regarding common needs and potential solutions across the seams 

of neighboring transmission planning regions” would help identify interregional 

transmission facilities that could more efficiently or cost-effectively meet the needs of 

each region.132 The Commission further found that Order No. 890’s transmission 

planning requirements “are too narrowly focused geographically” and do not provide for 

adequate analysis of the benefits of interregional transmission facilities in neighboring 

regions.

133 Accordingly, the Commission concluded that the interregional transmission 

coordination reforms should be adopted now and not delayed.

93. We continue to find that we have adequately justified the interregional 

transmission coordination requirements and that, in doing so, we have fully satisfied what 

is required by National Fuel, as that standard is discussed herein. We disagree with the 

 132 Id. P 368.

133 Id. P 369.
Docket No. RM10-23-001 -79-

contention that such requirements are overly burdensome as compared to the benefits. 

The interregional transmission coordination requirements are part of what goes into 

effective transmission planning. These requirements will help public utility transmission 

providers, in consultation with stakeholders, in one transmission planning region to work 

proactively with their counterparts in neighboring regions to identify what may be more 

efficient or cost-effective transmission facilities than the solutions identified in individual 

regional transmission plans. We do not believe these benefits are outweighed by the 

burdens involved, i.e., the cost of the adoption and implementation of procedures 

necessary for interregional transmission coordination, particularly when compared to the 

significant transmission investment expected in the future. Indeed, it may be the case 

that there will be little burden at all for the members of the Ad Hoc Coalition of 

Southeastern Utilities in implementing these requirements, given that they state that there 

is already an “optimization” analysis along the seams and interfaces in the Southeast.134 

Accordingly, we deny rehearing on this issue.

94. We also disagree with Large Public Power Council and Ameren that the 

transmission planning requirements of Order No. 1000 will place unnecessary burdens on 

planning engineers by requiring them to focus on matters other than meeting the needs of 

their native loads or will require a reassessment of prior planning. We see no 

 134 Ad Hoc Coalition of Southeastern Utilities at 65.
Docket No. RM10-23-001 -80-

contradiction between transmission planning for native loads and ensuring that 

transmission plans are consistent with regional or interregional transmission needs. 

Indeed, the native loads of individual entities ultimately benefit from improved regional 

transmission planning and interregional transmission coordination because they benefit 

from improvements to the transmission grid that extend beyond their own local facilities. 

We therefore do not think that any additional burden that Order No. 1000 may create for 

planning engineers outweighs the benefits that we expect Order No. 1000 to provide. In 

addition, the requirements of Order No. 1000 apply only to new transmission facilities, 

and we therefore do not see how they require a reassessment of past planning activities. 

95. We have not, as Sponsoring PJM Transmission Owners contend, ignored costs 

associated with elimination of federal rights of first refusal, specially the need for 

expensive mitigation plans in the event a nonincumbent transmission developer abandons 

a reliability project. We see no reason to expect that the performance of incumbent and 

nonincumbent transmission developers/providers will differ, and as a result, the example 

that Sponsoring PJM Transmission Owners advances is based on conjecture. Moreover, 

selection criteria for project developers are an appropriate means of providing assurances 

that all project developers will be in a position to fulfill their commitments. 

96. Sacramento Municipal Utility District states that Order No. 1000 does not satisfy 

the requirements of reasoned decision-making because it fails to take into account 

whether the cost allocation provisions will discourage rather than facilitate regional 
Docket No. RM10-23-001 -81-

transmission planning. As we have noted already, the Commission continues to find that 

transmission planning is more successful when it is understood upfront who will be 

allocated costs for the facilities in a transmission plan. Regional cost allocation methods 

accomplish this, among other things. The regional participants will decide which 

facilities in the regional transmission plan will have their costs allocated according to a 

method that they select, and which facilities will not. It is thus known how much each 

beneficiary will pay for the first set of facilities when the regional transmission plan is 

formed, and it is known that the latter set of facilities must be supported by the facility 

sponsors alone. Sacramento Municipal Utility District appears to take the position that 

the cost allocation requirements will discourage transmission planning because entities 

will be forced to pay for facilities from which they receive no benefit. We address and 

reject this argument elsewhere in this order.135

Other Issues

97. A number of petitioners raise objections to our demonstrations of the need for 

reform that do not fall under any of the general categories set forth above. 

98. We are not, as Coalition for Fair Transmission Policy asserts, stepping beyond our 

statutory authority and seeking to address every policy problem that faces the industry. 

We have fully explained our statutory authority in Order No. 1000, and we are addressing 

 135 See discussion infra at section IV.
Docket No. RM10-23-001 -82-

only matters that can affect transmission rates in a way that could cause them to become 

unjust and unreasonable, or unduly discriminatory or preferential. We find nothing 

ambiguous about, for example, our reference to such things as the impacts of renewable 

portfolio policies, as Coalition for Fair Transmission Policy maintains. These policies 

affect transmission needs and thus transmission rates, and rather than being ambiguous, 

our reference to them provides a clear and concrete example of how transmission 

planning cannot be fully effective if it does not consider all transmission needs. 

99. We also reject the characterization of our action in Order No. 1000 by Coalition 

for Fair Transmission Policy as commandeering regional transmission planning. The 

transmission planning and cost allocation requirements of Order No. 1000 are focused on 

the transmission planning process, not any substantive outcomes of this process.136 Order 

No. 1000 establishes a set of minimum requirements that regional planning must meet 

and allows considerable flexibility in the implementation of these requirements. 

Establishing flexible minimum requirements for a process cannot be equated with 

commandeering that process.

100. Coalition for Fair Transmission Policy states that the Commission’s authority 

under section 216 of the FPA to site transmission facilities in national interest corridors 

would not have been necessary if it had authority to address all policy problems and 

 136 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 12.
Docket No. RM10-23-001 -83-

commandeer the transmission process. We do not see how the Commission’s limited 

authority under this section is relevant to Order No. 1000. Since we are acting to address 

matters that can have an adverse effect on transmission rates and are not taking any 

control over the transmission planning process itself, we are not taking any actions that 

fall within the scope of the activities authorized in section 216. 

101. In response to NARUC’s concern that compliance with Order No. 1000 may stall 

existing local, regional, and DOE-funded interconnection-wide planning, the 

Commission stated in Order No. 1000 that the compliance filing deadlines it established 

are compatible with the interests of those that intend to develop transmission planning 

processes that take into account the lessons learned through the ARRA-funded 

transmission planning initiatives.137 NARUC states that its reason for concern is the need 

to sort through ambiguities and comply with Order No. 1000. The Commission is 

committed to engaging in outreach and consultation to assist the compliance process. 

NARUC also maintains that the ARRA-funded transmission planning initiatives may 

eliminate the need for the Commission’s reforms, but as we noted in Order No. 1000, 

those initiatives are complementary to, not substitutes for, the reforms in Order No. 1000. 

For example, they do not specifically provide for regional cost allocation or for ongoing 

coordination of planning for interregional transmission facilities, which we concluded is 

 137 Id. P 794
Docket No. RM10-23-001 -84-

necessary to ensure that rates, terms, and conditions of jurisdictional services are just and 

reasonable and not unduly discriminatory or preferential.138 NARUC has not challenged 

this conclusion regarding the ARRA-funded transmission planning initiatives in its 

petition for rehearing.

III. Transmission Planning

A. Regional Transmission Planning Process

102. Order No. 1000 built on the reforms adopted in Order No. 890 to improve regional 

transmission planning. First, Order No. 1000 required each public utility transmission 

provider to participate in a regional transmission planning process that produces a 

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

planning principles.139 Second, Order No. 1000 adopted reforms under which 

transmission needs driven by Public Policy Requirements are considered in local and 

regional transmission planning processes.140 The Commission explained that these 

reforms work together to ensure that public utility transmission providers in every 

transmission planning region, in consultation with stakeholders, evaluate proposed 

 138 Id. P 371.

139 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 68.

140 Id. The Commission explained that Public Policy Requirements are those

established by state or federal laws or regulations, meaning enacted statutes (i.e., passed 

by the legislature and signed by the executive) and regulations promulgated by a relevant 

jurisdiction, whether within a state or at the federal level. Id. at P 2.
Docket No. RM10-23-001 -85-

alternative solutions at the regional level that may resolve the region’s needs more 

efficiently or cost-effectively than solutions identified in the local transmission plans of 

individual public utility transmission providers.141 The Commission noted that, as in 

Order No. 890, the transmission planning requirements in Order No. 1000 do not address 

or dictate which transmission facilities should be either in the regional transmission plan 

or actually constructed, and that such decisions are left in the first instance to the 

judgment of public utility transmission providers, in consultation with stakeholders 

participating in the regional transmission planning process.142

1. Legal Authority for Order No. 1000’s Transmission Planning 

Reforms

a. Final Rule

103. Order No. 1000 concluded that the Commission has the authority under section 

206 of the FPA to adopt the transmission planning reforms. The Commission explained 

that the reforms build on those of Order No. 890, in which the Commission reformed the 

pro forma OATT to, among other things, require each public utility transmission provider 

to have a coordinated, open and transparent regional transmission planning process.143 

The Commission concluded that the reforms adopted in Order No. 1000 are necessary to 

 141 Id.

142 Id. P 68 n.57.

143 Id. P 99.
Docket No. RM10-23-001 -86-

address remaining deficiencies in transmission planning and cost allocation processes so 

that the transmission grid can better support wholesale power markets and thereby ensure 

that Commission-jurisdictional transmission services are provided at rates, terms and 

conditions that are just and reasonable and not unduly discriminatory or preferential.144

104. Order No. 1000 rejected arguments that FPA section 202(a)145 precluded the 

Commission from adopting the transmission planning reforms, explaining that this 

provision requires that the interconnection and coordination, i.e., coordinated operation 

(such as power pooling), of facilities be voluntary and the provision does not mention 

planning.146 The Commission explained that transmission planning is a process that 

occurs prior to the interconnection and coordination of transmission facilities. The 

Commission explained that this is consistent with the Central Iowa Power Coop. v. 

 144 Id.

145 Section 202(a) reads, in relevant part, as follows:

For the purpose of assuring an abundant supply of electric energy 

throughout the United States with the greatest possible economy 

and with regard to the proper utilization and conservation of 

natural resources, the Commission is empowered and directed to 

divide the country into regional districts for the voluntary 

interconnection and coordination of facilities for the generation, 

transmission, and sale of electric energy. . . .

16 U.S.C. 824a(a).

146 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 100-06.
Docket No. RM10-23-001 -87-

FERC decision,147 because the court in that case was presented with a request that the 

Commission require an enhanced level of, or tighter, power pooling, which the court 

found it could not do given “the expressly voluntary nature of coordination under section 

202(a).”148 Section 202(a) was therefore relevant to the problem at issue in Central Iowa

because, unlike Order No. 1000, the operation of the system through power pooling was 

its central subject matter.149 The Commission also found that because section 202(a) 

does not mention transmission planning, it was unnecessary to resort to the legislative 

history of the provision, which nevertheless discussed “planned coordination” of the 

operation of facilities, not the planning process for the identification of transmission 

facilities.150 

105. The Commission also made clear that nothing in Order No. 1000 infringed on 

those matters traditionally reserved to the states, such as matters relevant to siting, 

permitting and construction, as the reforms in Order No. 1000 are associated with the 

processes used to identify and evaluate transmission system needs and potential solutions 

 147 606 F.2d 1156 (D.C. Cir. 1979) (Central Iowa).

148 Id. at 1168.

149 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 102-03.

150 Id. PP 104-05.
Docket No. RM10-23-001 -88-

to those needs.151 Further, the Commission disagreed with commenters suggesting that 

the transmission planning reforms in the Proposed Rule, which were similar to those 

adopted in Order No. 1000, were inconsistent or precluded by, or legally deficient for 

failing to rely on, FPA section 217(b)(4),152 because Order No. 1000 supports the 

development of needed transmission facilities, which ultimately benefits load-serving 

entities.153 

106. Next, the Commission concluded that it could require public utility transmission 

providers to amend their OATTs to provide for the consideration of transmission needs 

driven by Public Policy Requirements. The Commission explained that such 

requirements may modify the need for and configuration of prospective transmission 

facility development and construction, and therefore, the transmission planning process 

 151 Id. P 107.

152 Section 217(b)(4) of the FPA specifies that: 

The Commission shall exercise the authority of the Commission 

under this Act in a manner that facilitates the planning and expansion 

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

entities to satisfy the service obligations of the load-serving entities, 

and enables load-serving entities to secure firm transmission rights 

(or equivalent tradable or financial rights) on a long-term basis for 

long-term power supply arrangements made, or planned, to meet such 

needs. 

16 U.S.C. 824q(b)(4).

153 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 108.
Docket No. RM10-23-001 -89-

and the resulting transmission plans would be deficient if they do not provide an 

opportunity to consider transmission needs driven by Public Policy Requirements.154 The 

Commission also rejected assertions that the transmission planning reforms were 

inconsistent with the Administrative Procedure Act, due process requirements, or 

Commission regulations governing incentive rates.155 The Commission explained that it 

satisfied FPA section 206’s burden, as its review of the record demonstrated that existing 

transmission planning processes are unjust and unreasonable or unduly discriminatory or 

preferential.156 Finally, the Commission addressed concerns raised by non-jurisdictional 

entities regarding issues associated with public power participation in the regional 

transmission planning process.157

107. In the section above on Need for Reform, the Commission has already addressed 

legal arguments surrounding the Commission’s determination that there is substantial 

evidence establishing a need for the package of reforms in Order No. 1000. A number of 

petitioners, however, also seek rehearing of the Commission’s conclusions regarding its 

legal authority to specifically require Order No. 1000’s regional transmission planning 

 154 Id. PP 109-12.

155 Id. PP 113-15.

156 Id. P 116.

157 Id. P 117.
Docket No. RM10-23-001 -90-

and interregional transmission coordination reforms. In general, these arguments, 

addressed below, concern: (1) the Commission’s interpretation of FPA section 202(a); 

(2) the Commission’s statements regarding section 217(b)(4); (3) Order No. 1000’s 

alleged infringement on state regulatory jurisdiction; (4) Order No. 1000’s requirement to 

consider transmission needs driven by Public Policy Requirements; (5) legal issues 

related to interregional transmission coordination; and (6) other legal issues.

b. Order No. 1000’s Interpretation of FPA Section 202(a)

i. Requests for Rehearing and Clarification

108. Several petitioners argue that the Commission erred in concluding that FPA 

section 202(a) permitted the Commission to require public utility transmission providers 

to engage in mandatory regional transmission planning and interregional transmission 

coordination.158 Generally, these petitioners assert that the Commission erred in 

interpreting both the language of the statute and the D.C. Circuit’s Central Iowa decision 

that addressed the scope of section 202(a).159 Petitioners also cite to the D.C. Circuit’s 

 158 See, e.g., Ad Hoc Coalition of Southeastern Utilities; California ISO; 

FirstEnergy Service Company; Large Public Power Council; North Carolina Agencies; 

PPL Companies; Sacramento Municipal Utility District; Southern Companies; and Xcel.

159 While most of the arguments regarding section 202(a) are opposed to the 

Commission’s authority over transmission planning as a general matter, some parties 

raise this argument in the specific context of interregional transmission coordination. All 

of the rehearing requests regarding section 202(a) are addressed here.
Docket No. RM10-23-001 -91-

Atlantic City decision for support for their proposition that transmission planning is to be 

left to the voluntary action of public utilities under section 202(a).160 

109. Many petitioners contend that Order No. 1000’s interpretation of section 202(a) is 

contrary to the plain meaning of the provision. Ad Hoc Coalition of Southeastern 

Utilities argues that Order No. 1000 itself recognizes that transmission planning is an 

aspect of the “coordination of facilities for . . . transmission” because Order No. 1000 

states that “coordination of planning on a regional basis will also increase efficiency 

through the coordination of transmission upgrades.”161 Ad Hoc Coalition of 

Southeastern Utilities also argues that Order No. 1000 states that its interregional 

coordination requirements involve “coordination with regard to the identification and 

evaluation of interregional transmission facilities . . . .”162 FirstEnergy Service Company 

also cites to statements in Order No. 1000 itself, which it argues demonstrates that the 

Commission recognized that transmission planning is an aspect of coordination.163 

 160 Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 12 (D.C. Cir. 2002) (Atlantic City)

161 Ad Hoc Coalition of Southeastern Utilities at 35 (quoting Order No. 1000, 

FERC Stats. & Regs. ¶ 31,323 at P 254 (emphasis added)). See also PPL Companies. 

162 Ad Hoc Coalition of Southeastern Utilities at 35 (quoting Order No. 1000, 

FERC Stats. & Regs. ¶ 31,323 at P 345 n.310 (emphasis added)). PPL Companies also 

point out that Order No. 890 states that “the coordination requirements imposed [therein] 

are intended to address transmission planning issues.” Order No. 890, FERC Stats. & 

Regs. ¶ 31,241 at P 453.

163 FirstEnergy Service Company at 9 (citing Order No. 1000, FERC Stats. & 

(continued...)
Docket No. RM10-23-001 -92-

110. Additionally, Ad Hoc Coalition of Southeastern Utilities disagrees that section 

202(a) only applies to interconnection and operation because section 202(a) discusses 

“interconnection and coordination” but does not mention operation. It also argues that 

interconnection is discussed along with coordination rather than to the exclusion of 

coordination. Thus, it argues that language regarding the “coordination of facilities for . . 

. transmission” encompasses transmission planning. It also argues that the 

interconnection of transmission facilities encompasses transmission planning. 

FirstEnergy Service Company asserts that the natural reading of “coordination” is not 

limited to “coordinated operation,” but also includes “coordinated planning.”164 

FirstEnergy Service Company notes that, while the Commission points to the fact that 

section 202(a) does not mention planning in an effort to avoid this natural reading of 

“coordination,” the logic of the Commission’s argument would mean that “coordinated 

operations” must also be excluded, because section 202(a) does not explicitly mention 

“operations,” a point echoed by California ISO.

 

Regs. ¶ 31,323 (stating that Order No. 1000 “improves coordination between neighboring 

transmission planning regions”)). FirstEnergy Service Company further argues that 

Order No. 1000 elsewhere uses “coordination” to refer to coordinated planning between 

regions. 

164 FirstEnergy Service Company at 9 (quoting Wolverine Power Co. v. FERC, 

963 F.2d 446, 454 (D.C. Cir. 1992); U.S. v. Wells, 519 U.S. 482, 483 (1997)).
Docket No. RM10-23-001 -93-

111. Ad Hoc Coalition of Southeastern Utilities argues that good utility practice 

compels the conclusion that coordination and interconnection closely involve system 

planning, asserting that for transmission systems to be interconnected and operated in a 

reliable manner, they must be planned in a coordinated manner to avoid serious reliability 

consequences. FirstEnergy Service Company states that the Commission cites no 

authority for the proposition that section 202(a) focuses on power pooling, but asserts 

that, even if power pools were the focus of section 202(a), the fact that the first power 

pool was formed to realize the benefits and efficiencies possible by interconnecting to 

share generating resources involves at least a limited form of coordinated planning. 

112. Sacramento Municipal Utility District argues that Congress left the issue of 

regional planning to the voluntary decision of the entities involved and only once they 

elect to do so would the Commission have authority to determine whether the terms of 

their arrangements are just and reasonable and not unduly discriminatory.165 It also 

argues that if Congress intended that the Commission should encourage the coordination 

of transmission operations, there is no logical reason that it did not also intend that it 

encourage transmission planning, which further means that it did not intend that the 

Commission could mandate transmission planning. Moreover, PPL Companies assert 

 165 Sacramento Municipal Utility District at 23 (citing Central Iowa, 606 F.2d at 

1167-68).
Docket No. RM10-23-001 -94-

that in all the revisions Congress made to the FPA in the Energy Policy Act of 2005,166 it 

did not mandate regional planning and left section 202(a) in place without changes to that 

provision’s voluntary nature. 

113. Petitioners also argue that the Commission misinterpreted Central Iowa, asserting 

that the court in that case understood that coordination included transmission planning.167 

FirstEnergy Service Company states that Central Iowa described coordination as 

including planning and described various degrees and methods of regional 

coordination.168 Similarly, North Carolina Agencies note that Central Iowa quoted the 

Commission’s own statement that “coordination is joint planning and operation of bulk 

power facilities by two or more electric systems for improved reliability and increased 

efficiency. . ..” They also argue that Central Iowa’s statement that the Commission could 

not have mandated the power pooling agreement means that the Commission could not 

have mandated the adoption of coordinated transmission planning.169 

 166 Energy Policy Act of 2005, Pub. L. No. 109-58, §§ 1261 et seq., 119 Stat. 594 

(2005) (EPAct 2005).

167 See, e.g., FirstEnergy Service Company; North Carolina Agencies; Large 

Public Power Council; Sacramento Municipal Utility District; Ad Hoc Coalition of 

Southeastern Utilities; and Southern Companies.

168 FirstEnergy Service Company at 11 (citing Central Iowa, 606 F.2d at 1168, 

n.36).

169 North Carolina Agencies at 7-8 (citing Central Iowa, 606 F.2d at 1168, n.36).
Docket No. RM10-23-001 -95-

114. Large Public Power Council also asserts that the court in Central Iowa found that 

the Commission’s involvement in transmission planning rests on the voluntary 

cooperation of utilities subject to the statute. Sacramento Municipal Utility District 

contends that the Commission’s assertion that Central Iowa meant only to refer to the 

operation of transmission facilities when it said “voluntary power pooling” rather than 

planning of their construction is not credible, noting that the court explicitly stated that 

one type of pooling arrangement is designed to achieve certain goals, “plus the 

economies of joint planning and construction of generation and transmission facilities.” 

Ad Hoc Coalition of Southeastern Utilities points to legislative history cited in Central 

Iowa stating that Congress “is confident that enlightened self-interest will lead the 

utilities to cooperate...in bringing about the economies which can alone be secured 

through planned coordination.”170 It also states that Central Iowa noted that nongenerating distribution systems “could attend MAPP meetings at which long-range plans 

are discussed” and it points to Central Iowa’s rejection of calls to enlarge the scope of the 

power pooling agreement because it “would be inconsistent with Congress’ intent to 

promote planned coordination of electric systems.”171

 170 Ad Hoc Coalition of Southeastern Utilities at 30 (citing Central Iowa, 606 F.2d 

at 1162 (quoting S. Rep. No. 74-62)).

171 Ad Hoc Coalition of Southeastern Utilities at 39 (quoting Central Iowa, 660 

F.2d at 1165, 1170).
Docket No. RM10-23-001 -96-

115. Other petitioners also assert that the legislative history of section 202(a), as well as 

the Commission’s own precedent, undermine Order No. 1000’s interpretation of that 

provision.172 North Carolina Agencies emphasize that Congress rejected arguments by 

the Federal Power Commission that it should be empowered to mandate such 

coordination when it adopted section 202(a)’s requirements. They argue that section 

202(b)173 also reveals that Congress purposefully limited the Commission’s authority to 

require coordination by enabling it only to order the interconnection of facilities and the 

sale/exchange of electricity. Ad Hoc Coalition of Southeastern Utilities and Southern 

Companies point out that the solicitor of the Federal Power Commission testified before 

Congress that the express intent in drafting section 202(a) was to facilitate regional 

 172 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Large Public Power 

Council; Sacramento Municipal Utility District; and Southern Companies.

173 FPA section 202(b) provides, in part: 

Whenever the Commission, upon application...and after 

notice...and after opportunity for hearing, finds such action 

necessary or appropriate in the public interest it may by order direct 

a public utility...to establish physical connection of its transmission 

facilities with the facilities of one or more other persons engaged in 

the transmission or sale of electric energy, to sell energy to or 

exchange energy with such persons: Provided, That the Commission 

shall have no authority to compel the enlargement of generating 

facilities for such purposes, nor to compel such public utility to sell 

or exchange energy when to do so would impair its ability to render 

adequate service to its customers. 

16 U.S.C. § 824a(b).
Docket No. RM10-23-001 -97-

planning. Petitioners also cite to Federal Power Commission policy statements regarding 

data collection that make statements such as “[l]ong-range planning is an indispensable 

element to the accomplishment of the objectives of [s]ection 202(a)” and that achieving 

the goals of section 202(a) “requires coordinated efforts on an industry[-]wide basis, at 

both the regional and national levels, to enhance reliability and adequacy of service.”174 

116. Ad Hoc Coalition of Southeastern Utilities points to the 1970 National Power 

Survey, which stated that “coordination is joint planning and operation of bulk power 

facilities by two or more electric systems for improved reliability and increased 

efficiency which would not be attainable if each system acted independently.”175 

Sacramento Municipal Utility District argues that the notion that section 202(a) does not 

include transmission planning, or that transmission planning is not considered part of the 

coordination of electric systems, would surprise those who recall the Federal Power 

 174 Ad Hoc Coalition of Southeastern Utilities at 40 (quoting Reliability and 

Adequacy of Electric Service—Reporting of Data, Order No. 838-4, 56 FPC 3547, 3548 

(1976); Reliability and Adequacy of Electric Service—Reporting of Data, Order No. 383, 

41 FPC 846 (1969)); Southern Companies at 39-40; Large Public Power Council at 19-

20.

175 Ad Hoc Coalition of Southeastern Utilities at 37. Ad Hoc Coalition of 

Southeastern Utilities also states that the Commission’s interpretation of Central Iowa is 

at odds with former Commissioner Vicky A. Bailey’s statement that “Congress...was 

motivated by the desire to leave the coordination and joint planning of utility systems to 

be to the voluntary judgment of individual utilities.” Ad Hoc Coalition of Southeastern 

Utilities at 40 (quoting Regional Transmission Organizations, Order No. 2000, FERC 

Stats. & Regs. ¶ 31,089 (Bailey, Comm’r. concurring)).
Docket No. RM10-23-001 -98-

Commission’s work with regional reliability councils in the decades following the 

Northeast blackout of 1965. It also asserts that the Commission’s interpretation cannot 

be squared with the 1993 Policy Statement Regarding Regional Transmission Groups, 

where the Commission recognized it lacked authority to mandate the formation of 

regional transmission organizations.176 

117. Some petitioners also cite to the D.C. Circuit’s Atlantic City decision. FirstEnergy 

Service Company quotes Atlantic City’s conclusion that the Commission’s “expansive 

reading of its section 203 jurisdiction could not be reconciled with section 202, which has 

been definitively interpreted to make clear that Congress intended coordination and 

interconnection arrangements be left to the voluntary action of the utilities.”177 Ad Hoc 

Coalition of Southeastern Utilities claims that Atlantic City reinforces that section 202(a) 

encompasses transmission planning, noting that the court held that section 202(a) applied 

to an ISO arrangement, which encompassed transmission planning, and therefore its 

voluntary nature precluded the Commission from requiring transmission owners to make 

a filing under section 203 before they could leave the ISO.178 Southern Companies state 

 176 Sacramento Municipal Utility District at 25 (citing Policy Statement Regarding 

Regional Transmission Groups, FERC Stats. & Regs. ¶ 30,967 at 30,870 & 30,872 

(1993) (RTG Policy Statement)).

177 First Energy Companies at 7 (citing Atlantic City, 295 F.3d at 12).

178 Ad Hoc Coalition of Southeastern Utilities at n.117 (citing Atlantic City, 295 

(continued...)
Docket No. RM10-23-001 -99-

Order No. 1000 conceded that the interregional coordination required constitutes the 

“coordination of facilities. . .for transmission.”179 Thus, Southern Companies argue that 

Order No. 1000, by specifying that public utility transmission providers adopt identical 

terms and conditions in their respective OATTs, requires the functional equivalent of 

mandatory coordination agreements despite the court’s decision in Atlantic City that the 

Commission cannot require adoption of coordination agreements.180

118. Southern Companies also assert that the design of the FPA is one of specifically 

conferred powers, not broad sweeping authority.181 They add that regional transmission 

planning is voluntary under section 202(a) and note the Commission did not invoke its 

limited authority under section 216. Southern Companies also assert that the 

Commission’s broader plenary authority over interstate transmission facilities set forth in 

FPA section 201 cannot be construed to allow the Commission to indirectly regulate 

 

F.3d at 11-14).

179 Southern Companies at 85 (citing Order No. 1000, FERC Stats. & Regs. ¶ 

31,323 at P 345 n.310; 16 U.S.C. § 824a(a)).

180 Southern Companies at 85 (citing Atlantic City, 295 F.3d at 12 (D.C. Cir. 

2002)). 

181 Southern Companies at 101 (citing Otter Tail Power Co. v. US, 410 U.S. 366, 

374 (1973) (stating that Part II of the FPA does not involve pervasive regulatory scheme 

over any or all activities that could have an effect on transmission rates or services)).
Docket No. RM10-23-001 -100-

matters incident to primary state jurisdiction over transmission facility necessity, siting, 

and construction.182

119. In addition, Large Public Power Council disagrees with the Commission’s 

statement in Order No. 1000 that Order No. 890 serves as precedent for the exercise of 

mandatory authority over transmission planning because jurisdictional and nonjurisdictional utilities voluntarily complied with the Order No. 890 reforms, leaving no 

opportunity for judicial review. Accordingly, Large Public Power Council argues the 

question of whether the Commission has acted outside of its authority may always be 

raised.183

120. Finally, Ad Hoc Coalition of Southeastern Utilities asserts that even if section 

202(a) does not encompass transmission planning, nothing in the FPA provides the 

Commission with any authority in this area. It reiterates that section 217(b)(4) is clear 

that the Commission is charged with facilitating transmission planning to meet native 

load, and it adds that nothing else in the statute suggests that the Commission has 

authority over this area.

 182 Southern Companies at 102 (citing 16 U.S.C. § 824(b)).

183 Large Public Power Council at 21 (citing Order No. 1000, FERC Stats. & Regs. 

¶ 31,323 at P 99).
Docket No. RM10-23-001 -101-

ii. Commission Determination

121. We deny rehearing. The arguments provided in the various requests for rehearing 

on the Commission’s interpretation of FPA section 202(a) do not persuade us that the 

Commission’s interpretation is at odds with existing precedent or that it does not 

represent a reasonable interpretation of the statute. The arguments raised on rehearing 

largely repeat or further elaborate upon points that the Commission rejected in Order No. 

1000. For ease of reference in the following discussion, we restate here our interpretation 

of section 202(a).

122. Section 202(a) reads, in relevant part, as follows:

For the purpose of assuring an abundant supply of electric 

energy throughout the United States with the greatest possible 

economy and with regard to the proper utilization and 

conservation of natural resources, the Commission is 

empowered and directed to divide the country into regional 

districts for the voluntary interconnection and coordination of 

facilities for the generation, transmission, and sale of electric 

energy. . . . 184

123. As the Commission explained in Order No. 1000, section 202(a) requires that the 

interconnection and coordination, i.e., the coordinated operation, of facilities be 

voluntary. It neither mentions planning nor implicitly establishes limits on the 

Commission’s jurisdiction with respect to transmission planning. The Commission 

explained that transmission planning is a process that occurs prior to the interconnection 

 184 16 U.S.C. 824(a) (2006).
Docket No. RM10-23-001 -102-

and coordination of transmission facilities. The transmission planning process itself does 

not create any obligations to interconnect or operate in a certain way. Thus, the 

Commission found that when establishing transmission planning process requirements, it 

is in no way mandating or otherwise impinging upon matters that section 202(a) leaves to 

the voluntary action of public utility transmission providers.185 As explained below, this 

point is reinforced by the way that section 202(a) presents the matters that it does address 

in a specific sequence. 

124. First, section 202(a) empowers the Commission to divide the country into regional 

districts. If the Commission takes that step, the statute then envisions voluntary 

interconnection of facilities within those districts, after which occurs the voluntary 

coordination of those facilities, something which can occur only after the facilities are 

interconnected. This sequence leads to the inference that the “coordination of facilities” 

refers to their operational coordination, the only relevant form of coordination once 

facilities are interconnected.

125. The planning of new transmission facilities occurs before they can be 

interconnected, and for this reason any transmission planning relevant to these facilities 

occurs prior to those matters that the statute mandates be voluntary. The requirements of 

Order No. 1000 explicitly pertain only to the coordination of transmission planning, not 

 185 See Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 100-01.
Docket No. RM10-23-001 -103-

the coordination of operations of generation and transmission facilities. In short, Order 

No. 1000 deals with the coordination of a process that is separate and distinct from, and 

that is completed prior to, the coordination of facilities that is the concern in section 

202(a). For this reason, the transmission planning requirements of Order No. 1000 fall 

outside the scope of section 202(a) because they apply to matters that occur prior to any 

actions that fall within its scope.

126. Our task here is to provide a reasonable interpretation of section 202(a),186 and we 

have done that. Our reading of the statute follows the direct flow of the statutory 

language, and in that way, it conforms with “the cardinal rule that ‘[s]tatutory language 

must be read in context [since] a phrase ‘gathers meaning from the words around it.’’”187 

It draws the most reasonable inference from the absence of any mention of planning, i.e., 

that Congress did not intend section 202(a) to apply to the planning of new transmission 

facilities. It also is consistent with the intent of Congress, which was the promotion of 

the economic use of resources through power pooling, as we discuss herein.188

 186 Chevron U.S.A. v. Natural Resources Defense Council, 467 U.S. 837, 842-45 

(1984) (Chevron).

187 General Dynamics Land Sys., Inc. v. Cline, 540 U.S. 581, 596 (2004). (quoting 

Jones v. United States, 527 U.S. 373, 389, (1999) (quoting Jarecki v. G. D. Searle & Co., 

367 U.S. 303, 307 (1961))).

188 See discussion infra at P 134.
Docket No. RM10-23-001 -104-

127. The arguments that have been raised on rehearing against this interpretation of 

section 202(a) fall into two broad categories. The first involves claims concerning the 

nature of planning. The argument that petitioners advance is that planning by its nature is 

inherently inseparable from the interconnection and coordination of facilities mentioned 

in the statute. These arguments assert that the nature of planning is such that the 

requirement that it be voluntary either is found directly in the plain meaning of the 

language of the statute or is clearly implied by that language. The second class of 

arguments involves the claim that a number of court cases involving section 202(a), in 

particular Central Iowa, demonstrate that the transmission planning requirements of 

Order No. 1000 violate the statute. Many petitioners also point to Commission orders 

and studies that they claim support the same conclusion. 

128. The first class of arguments can be summarized as follows: planning is necessary 

to interconnect and coordinate facilities; section 202(a) prohibits the Commission from 

requiring the interconnection and coordination of facilities; therefore, section 202(a) 

prohibits the Commission from requiring anything pertaining to new transmission facility 

planning. For example, Ad Hoc Coalition of Southeastern Utilities argues that 

transmission planning is an aspect of the coordination of facilities, and therefore, if the 

interconnection and coordination of transmission facilities must be voluntary, 
Docket No. RM10-23-001 -105-

transmission planning alone also must be coordinated voluntarily. A number of other 

petitioners make similar arguments.189

129. While it is true that facilities must be planned before they can be interconnected 

and coordinated, we find that this fact proves nothing regarding the scope of section 

202(a). The fact that many significant undertakings require planning does not mean that 

the planning process is indistinct and inseparable from the implementation of plans and 

subsequent operations. For instance, there is a significant difference between planning a 

trip and taking it. Likewise, the act of planning the transmission grid and the act of 

coordinating facilities in their operations are two quite different things. In the case of 

transmission facilities, planning involves the consideration of various alternatives using 

economic and engineering analysis, whereas the operation of interconnected facilities 

involves operational cooperation, such as coordinated dispatch, among other things. We 

thus disagree with the various petitioners who argue that the “coordination of facilities. . . 

for transmission” necessarily encompasses transmission planning. The latter must be 

completed before the former can occur. Moreover, planning is an extremely general 

concept, which means that in practice there are many different types of planning. A plan 

for the coordination of facilities for the generation, transmission, and sale of electric 

energy is an operational plan for facilities already in existence. Such a plan differs from 

 189 See, e.g., PPL Companies; and Southern Companies.
Docket No. RM10-23-001 -106-

a plan for the development of new transmission facilities, which is all that is at issue 

under Order No. 1000. 

130. In addition, to plan is not to mandate some action that occurs beyond the planning

process. Between planning and the implementation of a plan stands a decision to proceed 

or not to proceed with some or all of the planning proposals. We thus disagree with 

North Carolina Agencies that the transmission planning process itself creates obligations 

regarding interconnection or operation. 

131. FirstEnergy Service Company states that one must begin with the literal terms of 

the statute and maintains that when one does, one finds that the natural reading of 

“coordination” includes both coordinated planning and coordinated operation. While we 

agree with FirstEnergy Service Company on the starting point of statutory interpretation, 

one cannot stop there. It is a “fundamental principle of statutory construction (and, 

indeed, of language itself) that the meaning of a word cannot be determined in isolation, 

but must be drawn from the context in which it is used.”190 Section 202(a) does not use 

the term “coordination” in isolation but rather in the phrase “coordination of facilities.” 

The language found in section 202(a) does not include any terms such as plan or planning 

or any synonyms for such terms. We disagree that the “natural reading” of 

 190 Deal v. United States, 508 U.S. 129, at 132 (1993).
Docket No. RM10-23-001 -107-

“coordination” in the phrase “coordination of facilities” requires one to conclude that the 

phrase means both “coordination of facilities” and “coordination of planning.” 

132. FirstEnergy Service Company defends its “natural” reading of the term 

“coordination” in section 202(a) by pointing to the various uses that the Commission has 

made of the term in Order No. 1000, including statements on how the planning 

requirements of Order No. 1000 promote coordination among planning regions. Ad Hoc 

Coalition of Southeastern Utilities and PPL Companies make similar arguments. We 

reject these arguments because, as used by the Commission in those instances, 

“coordination” simply means “joint cooperation,” not coordination as petitioners argue. 

The word “coordination,” like “planning,” is extremely general in its scope. Its meaning 

in one context, such as section 202(a), does not suggest or imply that it has the same 

meaning in every other context, such as Commission references to the coordination of 

new transmission planning. As noted above, “the meaning of a word cannot be 

determined in isolation, but must be drawn from the context in which it is used.”191 In 

the case of Order No. 1000, the use of the term “coordination” in connection with new 

requirements is restricted to interregional transmission coordination. We see no 

connection between the coordination between regions and the coordination of facilities 

referred to in section 202(a).

 191 Deal v. United States, 508 U.S. at 132.
Docket No. RM10-23-001 -108-

133. Additionally, Ad Hoc Coalition of Southeastern Utilities overlooks this point 

when it argues that Order No. 1000 found that its interregional transmission coordination 

requirements involve “coordination with regard to the identification and evaluation of 

interregional transmission facilities . . . .”192 The quoted language is taken out of context 

as the footnote in Order No. 1000 from which it is drawn is intended to make clear that 

the Commission draws a distinction between the interregional transmission coordination 

it is requiring in Order No. 1000 and the type of coordination at issue in section 202(a). 

The full footnote is as follows: “[w]e note that our use of the term ‘coordination’ with 

regard to the identification and evaluation of interregional transmission facilities is 

distinct from the type of coordination of system operations discussed in connection with 

section 202(a) of the FPA.”193 FirstEnergy Service Company also claims support for its 

argument in the statement in Order No. 1000 that its interregional planning reforms 

would “improve coordination among public utility transmission planners with respect to 

the coordination of interregional transmission facilities.”194 This argument, however, 

fails for the same reason. The language from Order No. 1000 cited immediately above 

 192 Ad Hoc Coalition of Southeastern Utilities at 35 (quoting Order No. 1000, 

FERC Stats. & Regs. ¶ 31,323 at P 345 n.310 (emphasis added)). 

193 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 345 n.310 (emphasis 

added). 

194 Id. P 345.
Docket No. RM10-23-001 -109-

makes clear that the Commission distinguished its use of the word “coordination” with 

regard to interregional coordination of new transmission planning in Order No. 1000 

from the meaning of the word “coordination” in section 202(a). 

134. We also disagree with FirstEnergy Service Company that the Commission cites no 

authority for the proposition that power pools and operational activities were the focus of 

section 202(a). Central Iowa supports the Commission’s view.195 Moreover, the 

standard that the Commission must satisfy in advancing an interpretation of section 

202(a) is that it be a reasonable interpretation.196 The Commission’s interpretation is a 

reasonable one, given that the provision seeks the promotion of the “interconnection and 

coordination of facilities for the generation, transmission, and sale of electric energy,” 

i.e., existing resources of public utility systems, for the purpose of promoting “the 

greatest possible economy and with regard to the proper utilization and conservation of 

natural resources.”197 Such economizing of resources is the purpose of a power pool. 

This is precisely the point made in the secondary literature that the court quoted in 

 195 See, e.g., Central Iowa, 606 F.2d at 1160-62 (stating that the agreement at issue 

is designed to promote reliable and economical operation of the interconnected electric 

network in the mid-continent area). 

196 Chevron U.S.A. v. Natural Resources Defense Council, 467 U.S. 837, 842-45 

(1984) (Chevron).

197 16 U.S.C. 824a(a).
Docket No. RM10-23-001 -110-

Central Iowa, which reinforces the point that the case supports the Commission’s 

interpretation.198 

135. Sacramento Municipal Utility District argues that if Congress intended that the 

Commission should encourage the coordination of transmission operations, there is no 

logical reason that it did not also intend that the Commission encourage transmission 

planning, which further means that it did not intend that the Commission could mandate 

transmission planning. On the contrary, there is no logical basis for this conclusion. 

Section 202(a) deals with the coordination of facilities, i.e., facilities already in existence, 

whereas Order No. 1000 deals with the planning of new transmission facilities. While 

facilities must be planned before they can be built, and built before they can be 

coordinated, it does not logically follow that encouragement of the coordination of 

existing facilities entails encouraging the planning of new facilities, which, if built, could 

be coordinated. There is thus no logical basis for concluding that Congress intended 

anything at all with regard to planning of new transmission facilities.

136. Similar considerations apply to the argument that the plain meaning of section 

202(a) requires one to conclude that joint planning must be voluntary. The basic 

principle underlying the plain meaning rule is that in interpreting a statute, “we start –

 198 Central Iowa, 606 F.2d at n.16.
Docket No. RM10-23-001 -111-

and if it is ‘sufficiently clear in its context,’ end – with the plain language of the 

statute.”199 To end with the plain language of the statute means that:

. . . when words are free from doubt they must be taken as the 

final expression of the legislative intent, and are not to be 

added to or subtracted from by considerations drawn from 

titles or designating names or reports accompanying their 

introduction, or from any extraneous source. In other words, 

the language being plain, and not leading to absurd or wholly 

impracticable consequences, it is the sole evidence of the 

ultimate legislative intent.200

Section 202(a) makes no mention of transmission plans, planning new transmission, or 

any planning at all. Therefore, the plain meaning rule does not support petitioners’ 

argument. Petitioners’ reading of section 202(a) is not a required interpretation of the 

statute.

137. For instance, Ad Hoc Coalition of Southeastern Utilities argues that the 

coordination of facilities for transmission encompasses transmission planning. This is an 

argument based on inference, not plain meaning, and “[i]nterpreting the intent of 

Congress from the inferential meaning of its statutes is a far different exercise . . . from 

looking at the plain meaning of a statute for an express provision. . . .”201 To argue that a 

 199 Lutheran Hosp. of Indiana, Inc. v. Business Men’s Assur. Co., 51 F.3d 1308, 

1312 (7th Cir. 1995) (quoting Ernst & Ernst v. Hochfelder, 425 U.S. 185, 201 (1976)).

200 Caminetti v. United States, 242 U.S. 470, 490 (1917).

201 Breuer v. Jim's Concrete of Brevard, Inc., 292 F.3d 1308, 1309 (11th Cir. 

2002), aff’d, 538 U.S. 691 (2003). 
Docket No. RM10-23-001 -112-

statute requires a particular result based on an inference, the inference must be a 

necessary one, not simply one that is possible.202 That the interpretation proposed by 

petitioners is not a necessary one is demonstrated by the existence of other, and in our 

view, more reasonable interpretations such as the one advanced in Order No. 1000. We 

are required only to present a reasonable interpretation,203 and we believe that we have 

done so.

138. Nevertheless, Ad Hoc Coalition of Southeastern Utilities and Southern Companies 

further maintain that the Federal Power Commission assisted Congress in drafting the 

FPA with the express intent of facilitating regional planning. They argue that the 

legislative history of the statute demonstrates this and undercuts the Commission’s 

position that the “planned coordination” mentioned in the legislative history refers only to 

the coordination of facility operations. However, the evidence on which Ad Hoc 

Coalition of Southeastern Utilities and Southern Companies base their argument –

statements made in Congressional hearings by the Federal Power Commission’s solicitor 

and drafting representative, Dozier A. DeVane – does not support their conclusion and is, 

at best, irrelevant to the point they seek to make.

 202 Kirkhuff v. Nimmo, 683 F.2d 544, 549 (D.C. Cir. 1982); Safarik v. Udall, 304 

F.2d 944, 948 (D.C. Cir. 1962); 2B Sutherland Statutory Construction § 55:3 (7th ed.).

203 Chevron, 467 U.S. at 842-45.
Docket No. RM10-23-001 -113-

139. It is important to note that Mr. DeVane was commenting on an early draft of the 

FPA that differs in fundamental respects from the version that eventually became law. 

Specifically, the draft in question created an obligation for all public utilities “to furnish 

energy to, exchange energy with, and transmit energy for any person upon reasonable 

request therefore. . . .”204 The draft also required public utilities to receive a certificate of 

public convenience and necessity before constructing or operating new jurisdictional 

facilities or abandoning facilities other than through retirement in the normal course of 

business.205 In short, the draft statute was to require sales and exchanges of energy that 

are central to pooling operations, and the Commission was to have direct oversight over 

the development of the transmission grid through the approval of new facilities prior to 

construction. As Ad Hoc Coalition of Southeastern Utilities and Southern Companies 

 204 Hearing on H.R. 5423 Before the House Interstate & Foreign Commerce 

Comm. 74th Cong. 32 (1935).

205 Id. The language on certificates of public convenience and necessity is found 

in section 204(a) of the draft statute, which provided that: 

No public utility shall undertake the construction or extension 

of any facilities subject to the jurisdiction of the Commission, 

or acquire or operate any such facilities, or extension thereof, 

or engage in production or transmission by means of any such 

new or additional facilities or receive energy from any new 

source, unless and until there shall first have been obtained 

from the Commission a certificate that the present or future 

public convenience and necessity require or will require such 

new construction, or operation or additional supply of electric 

energy. . . .
Docket No. RM10-23-001 -114-

note, Mr. DeVane considered these sections to be among those that were “absolutely 

necessary to effectively carry out regional planning.”206 Thus, even if Ad Hoc Coalition 

of Southeastern Utilities and Southern Companies are correct that the Federal Power 

Commission draft of the FPA expressed an intent to facilitate planning, that intent is not 

expressed in the statute itself since provisions that the Federal Power Commission 

representative considered to be essential to the goal were not included in the statute. 

Moreover, given the fact that the Commission would have had oversight over the 

transmission development process through the power to issue certificates of public 

convenience and necessity, we think that Mr. DeVane meant by “planning” the planning 

and promotion of enhanced power pooling under active Commission supervision, 

something very different from the matters at issue in this proceeding. We thus do not 

agree with Ad Hoc Coalition of Southeastern Utilities and Southern Companies that the 

legislative history of the FPA contradicts the Commission’s interpretation of section 

202(a) of the statute.

140. This brings us to the second class of arguments advanced by petitioners, those that 

rely on sources such as court cases dealing with section 202(a), as well as Commission 

orders and reports. Petitioners who advance such arguments on rehearing focus on 

 206 Ad Hoc Coalition of Southeastern Utilities at 41 (quoting Hearing on H.R. 

5423 Before the House Interstate & Foreign Commerce Comm. 74th Cong. 560 (1935)); 

Southern Companies at 40 (quoting the same text). 
Docket No. RM10-23-001 -115-

Central Iowa. As the Commission noted in Order No. 1000, Central Iowa dealt with a 

claim that the Commission should have used its authority under section 206 of the FPA to 

compel greater integration of the utilities within the Mid-Continent Area Power Pool 

(MAPP) than was specified in the MAPP agreement. Those who took this position in the 

Commission proceeding at issue in Central Iowa sought to have the Commission require 

MAPP participants “to construct larger generation units and engage in single system 

planning with central dispatch.”207 The court held that given “the expressly voluntary 

nature of coordination under section 202(a),” the Commission was not authorized to grant 

that request.208

141. The court in Central Iowa was thus presented with a request that the Commission 

require an enhanced level of, or tighter, power pooling. Section 202(a) was relevant to 

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

pooling is its central subject matter. Order No. 1000, however, is focused on the process 

of planning new transmission, which is distinct from any specific system operations. 

Nothing in Order No. 1000 is tied to the characteristics of any specific form of system 

operations, and nothing in it requires any changes in the way existing operations are 

conducted. Order No. 1000 requires compliance with certain general principles within 

 207 Central Iowa, 606 F.2d at 1166. 

208 Id. at 1168. 
Docket No. RM10-23-001 -116-

the transmission planning process regardless of the nature of the operations to which that 

process is attached. The court’s interpretation of section 202(a) with respect to system 

operations is therefore not applicable.209

142. Many of the arguments that petitioners make based on their reading of Central 

Iowa attempt to demonstrate that regional transmission planning must be voluntary 

because the court in various ways noted the importance of planning for the 

interconnection and coordination of facilities. Large Public Power Council maintains that 

the court in Central Iowa believed that planning was an intimate part of the authority 

addressed in section 202(a) based on the court’s reference to a passage in the legislative 

history discussing “the economies which alone can be secured through . . . planned 

coordination.”210 Several petitioners also point to the court’s use of the definition of 

“coordination” set forth in the Commission’s 1970 National Power Survey. This 

definition states that “coordination is joint planning and operation of bulk power facilities 

by two or more electric systems for improved reliability and increased efficiency which 

would not be attainable if each system acted independently.” Large Public Power 

Council also cites the court’s reference to a passage from the 1970 National Power 

 209 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at 103.

210 Large Public Power Council at 20 (quoting S Rep. No. 74-621 at 49 (1935), as 

cited by Central Iowa, 606 F.2d at 1162).
Docket No. RM10-23-001 -117-

Survey that states that the “[r]eduction of installed reserve capacity is made possible by 

mutual emergency assistance arrangements and associated coordinated transmission 

planning.”211

143. As explained in Order No. 1000, section 202(a) does not mention “planning,” and 

we have determined that section 202(a) was not intended to address the process of 

planning new transmission facilities that is the subject of this proceeding. Moreover, the 

cited legislative history does not refer to the new transmission planning process that is the 

subject of Order No. 1000. Instead, the legislative history refers to “planned 

coordination,” i.e., to the pooling arrangements and other aspects of system operation that 

are the underlying focus of section 202(a). It is in this sense that Central Iowa must be 

understood when it refers to engaging “voluntarily in power planning arrangements.” 

The “planned coordination” mentioned in the legislative history cited in Central Iowa

means “planned coordination” of the operation of existing facilities, not the planning 

process for the identification of new transmission facilities. In short, neither Central 

Iowa nor the legislative history cited in that case involves or applies to the planning 

process for new transmission facilities. Rather, they deal with the coordinated, i.e., 

shared or pooled, operation of facilities after those facilities are identified and developed. 

 211 Large Public Power Council at 21 (quoting 1970 National Power Survey, p. I17-1, as cited by Central Iowa, 606 F. 2d at n.23).
Docket No. RM10-23-001 -118-

By contrast, Order No. 1000 deals with the process for planning new transmission 

facilities, a separate and distinct set of activities that occur before new transmission 

facility construction and before the generation and transmission operational activities that 

are the subject of section 202(a).212

144. Additionally, we note that in referring to “the economies which alone can be 

secured through . . . planned coordination,” the legislative history is referring to the 

economies that arise through the coordination of facilities in power pool operations. The 

legislative history states that Part II of the FPA “seeks to bring about the regional 

coordination of the operating facilities of the interstate utilities.”213 Planned coordination 

in facility operations generally involves utilizing the lowest cost generation facilities 

available at any particular time and reducing installed reserve capacity. The new 

transmission planning required by Order No. 1000 is intended to ensure that transmission 

planning processes consider and evaluate possible transmission alternatives and produce 

transmission plans that can meet transmission needs more efficiently and cost-effectively. 

Nothing in the coordinated new transmission planning process envisioned by Order No. 

1000 requires or inevitably leads to the coordinated operation of existing generation and

 212 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 105.

213 S.Rep.No.621, 74th Cong., 1st Sess. 4 (1935).
Docket No. RM10-23-001 -119-

transmission facilities and coordinated sales of electric energy in pooling operations 

envisioned in the legislative history of section 202(a). 

145. Moreover, the fact that the legislative history describes the coordination of 

facilities that Congress had in mind as “planned” does not make the planning 

requirements in Order No. 1000 part of what was under discussion in the legislative 

history. As noted above, planning is an extremely general concept. The broad range of 

activities that involve planning cannot be deemed to be intrinsically related to each other 

simply by virtue of having a characteristic in common that virtually all business, 

commercial, and industrial activities share. 

146. Additionally, nothing anyone cites to in the 1970 National Power Survey suggests 

that its definition of the term “coordination” is intended as an interpretation of the term 

“coordination” for purposes of section 202(a). Moreover, if “coordination” means, as the 

1970 National Power Survey defines it to mean, “joint planning and operation of bulk 

power facilities” (emphasis supplied), then joint planning alone, which is only one 

element of the definition, is not coordination under this definition. Therefore, Order No. 

1000 does not require coordination under this definition because it does not require one 

of the essential elements of the definition (i.e., it does not require joint operation). We 

thus see no basis to conclude that the definition of “coordination” in the 1970 National 

Power Survey or use of the definition by the court in Central Iowa demonstrates that the 
Docket No. RM10-23-001 -120-

phrase “coordination of facilities” in section 202(a) also means “coordination of 

planning.” 

147. The language from the 1970 National Power Survey that Large Public Power 

Council cites also does not demonstrate that planning is necessarily part of the authority 

addressed in section 202(a). This language simply points out that coordinated 

transmission planning can play a role in reducing the amount of installed reserve capacity 

needed. The coordination of plans for new transmission can have many beneficial 

effects, but the argument that one of these effects brings it within the function addressed 

in section 202(a) because it is something that the section requires to be voluntary is 

another example of a failure to distinguish between new transmission planning and the 

implementation of plans for other purposes. The statement from the 1970 National 

Power Survey does not show that planning is an integral part of the authority addressed in 

section 202(a) because nothing in it shows how the planning requirements of Order No. 

1000 have the effect of requiring either the interconnection or the coordination of 

facilities.

148. Additionally, Sacramento Municipal Utility District argues that the court in 

Central Iowa did not mean to refer only to facility operations when referring to voluntary 

power pooling because it noted that some forms of pooling are designed to achieve 

certain goals, plus economies of joint planning and construction of generation and 

transmission facilities. This fact does not make joint planning by itself, which is the 
Docket No. RM10-23-001 -121-

subject of Order No. 1000, a form of power pooling or demonstrate that something falls 

within the scope of section 202(a) simply because it is something that some power pools 

have decided to do.

149. Sacramento Municipal Utility District also cites Central Iowa as support for the 

argument that the Commission’s authority is limited to determining whether the terms of 

any voluntary agreements to plan together are just and reasonable and not unduly 

discriminatory or preferential. In fact, however, Central Iowa does not support 

Sacramento Municipal Utility District’s argument. In that case, the court approved 

Commission action requiring joint planning where one group of public utilities refused to 

agree to plan together with another group. Specifically, the MAPP agreement separated 

MAPP members into different classes based on the size of their systems and allowed 

members of the class with larger, but not those with smaller, systems to have access to 

the planning function. Those not admitted objected, and the Commission found the size 

criterion irrelevant and unduly discriminatory and required the admission of the 

previously excluded systems.214 

150. In other words, Central Iowa involved a situation where a power pool voluntarily 

agreed to joint planning and operation, but allowed only some members to participate in 

 214 Mid-Continent Area Power Pool Agreement, Opinion No. 806, 58 F.P.C. 2622, 

2631-36 (1977) (MAPP Agreement Order).
Docket No. RM10-23-001 -122-

planning. The Commission found that it was unduly discriminatory to allow only some 

members to participate in planning, directed MAPP to allow all members to participate in 

planning, and the Court affirmed that decision.215 While Sacramento Municipal Utility 

District contends Central Iowa limits the Commission’s ability to create planning 

requirements to the circumstances there, nothing in the Court’s opinion supports this. 

Rather the opinion shows that the Court focused on and affirmed the Commission on the 

specific facts before it. Whether the Commission can mandate planning in other 

circumstances, such as those here, was neither considered by nor ruled on by the Court. 

For these reasons, we also disagree with North Carolina Agencies that the court’s 

statement in Central Iowa that the Commission could not have mandated the adoption of 

the MAPP agreement means that the Commission could not have mandated coordinated 

transmission planning. The court specifically approved a Commission mandate of joint 

planning. 

151. We also disagree with Sacramento Municipal Utility District that the 

Commission’s action in the order underlying Central Iowa was proper only because the 

planning provisions of the MAPP agreement were “the voluntary decision of the entities 

involved,”216 i.e., the voluntary decision of those MAPP members that had agreed to 

 215 Central Iowa, 606 F.2d at 1170-72. 

216 Sacramento Municipal Utility District at 23.
Docket No. RM10-23-001 -123-

engage in planning with some MAPP members but not with others. Rather, the 

Commission imposed the requirement in the absence of any substantive agreement to the 

requirement among the parties affected, because the practices at issue were matters that 

were subject to the Commission’s jurisdiction under sections 205 and 206 of the FPA.217 

That is, the Commission’s authority arises from the fact that planning is a practice that 

affects rates, and the Commission has a duty under sections 205 and 206 of the FPA to 

ensure that such practices are just and reasonable and not unduly discriminatory or 

preferential. Indeed, this is the very same authority upon which the Commission relies in 

adopting the transmission planning reforms in Order No. 1000. This point also supplies 

our response to Ad Hoc Coalition of Southeastern Utilities’ claim that even if section 

202(a) does not encompass transmission planning, nothing in the FPA gives the 

Commission any authority in this area. 

152. Regarding Ad Hoc Coalition of Southeastern Utilities’ argument that the 

Commission’s interpretation of Central Iowa is at odds with former Commissioner Vicky 

A. Bailey’s statement that “Congress...was motivated by the desire to leave the 

coordination and joint planning of utility systems to be to the voluntary judgment of 

individual utilities,”218 we note that she made this statement in an opinion in which she 

 217 Central Iowa at 1170; MAPP Agreement Order, 58 F.P.C. at 2636-37.

218 Ad Hoc Coalition of Southeastern Utilities at 40 (quoting Regional 

(continued...)
Docket No. RM10-23-001 -124-

concurred in part and dissented in part. Neither concurring opinions nor dissenting 

opinions constitute binding precedent,219 and Commissioner Bailey’s statement thus does 

not call into question the validity of our actions here.

153. We also find nothing in Atlantic City that is relevant to the issue of the 

Commission’s authority to establish transmission planning requirements. In Atlantic 

City, the court held that the Commission could not require a transmission-owing public 

utility to obtain authorization under section 203 of the FPA before withdrawing from an 

ISO. The court reasoned that section 203 applies only to situations where a public utility 

sells, leases, or otherwise disposes of jurisdictional assets, and the transfers of control 

over such facilities that occurred when a public utility joined or departed from an ISO did 

not rise to the level of such a transaction. The court also concluded that the 

Commission’s position that approval under section 203 is required could not be 

reconciled with the requirement of section 202(a) that arrangements for the 

interconnection and coordination of facilities be voluntary. The court nowhere stated or 

implied that these voluntary arrangements also covered planning matters. Indeed, the 

court’s main point was that section 202(a) “does not provide [the Commission] with any 

 

Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (Bailey, 

Comm’r. concurring in part and dissenting in part)).

219 Maryland v. Wilson, 519 U.S. 408, 412–13 (1997) (acknowledging that a 

concurring opinion does not constitute binding precedent).
Docket No. RM10-23-001 -125-

substantive powers ‘to compel any particular interconnection or technique of 

coordination.’”220 Nothing in Order No. 1000 compels “any particular interconnection or

technique of coordination” or indeed any interconnection or coordination of facilities at 

all.

154. Some petitioners maintain that Atlantic City demonstrates that the Commission 

cannot impose planning requirements because the ISO agreement at issue in that case 

encompassed transmission planning. However, the fact that section 202(a) has 

applicability to some aspects of an agreement does not mean that it has applicability to all 

aspects. The claim to the contrary is based on the idea that every kind of transmission 

planning is inseparable from the interconnection and coordination of facilities, a claim 

that we reject. In addition, it is clear from the context in which the court raised section 

202(a) in Atlantic City that it was not making any statements that are relevant to 

transmission planning.

155. As noted above, the issue before the Atlantic City court was whether the transfer 

of control over jurisdictional facilities that occurred when a public utility entered or left 

an ISO was a jurisdictional transfer for purposes of section 203 of the FPA. For purposes 

of section 202(a), such a transfer constitutes a decision either to coordinate facilities 

 220 Atlantic City, 295 F.3d at 12 (quoting Duke Power Co. v. Federal Power 

Comm’n, 401 F.2d 930, 943 (D.C. Cir. 1968)). 
Docket No. RM10-23-001 -126-

through the ISO or to withdraw from such a coordination arrangement, i.e., to turn 

operational authority over to an ISO or to reclaim that authority from the ISO. Neither 

joint nor coordinated new transmission planning involves any transfer of control over any 

facilities, which makes clear that the court in Atlantic City was not addressing issues 

pertinent to transmission planning. We thus disagree with Southern Companies that the 

transmission planning requirements of Order No. 1000 constitute the functional 

equivalent of a coordination agreement that the court in Atlantic City found must be 

voluntary. 

156. We also disagree with PPL Companies that the lack of a mandate on regional 

transmission planning in the Energy Policy Act of 2005 and the fact that Congress made 

no changes to section 202(a) has any significance for Order No. 1000. Section 202(a) 

does not mention transmission planning. With respect to the Energy Policy Act of 2005, 

which does not address regional transmission planning, we note that the Supreme Court 

has observed that “[t]he search for significance in the silence of Congress is too often the 

pursuit of a mirage.”221 

157. Sacramento Municipal Utility District maintains that the Commission’s work with 

regional reliability councils in the decades following the Northeast blackout of 1965 

 221 Sampson v. Murray, 415 U.S. 61, 78 (1974) (quoting Scripps-Howard Radio v. 

F.C.C., 316 U.S. 4, 11 (1942)).
Docket No. RM10-23-001 -127-

contradicts its interpretation of section 202(a). To demonstrate this point, Sacramento 

Municipal Utility District quotes a long passage from a 1993 proposed rule dealing with 

information to be filed by transmitting utilities providing information on potentially 

available transmission capacity and known constraints.222 The passage in question 

includes a number of statements that point out the importance of planning for the 

development of coordinated systems. However, this passage does not mention section 

202(a) or the Commission’s jurisdiction, and nothing in the document from which it is 

drawn states anything, either explicitly or implicitly, that allows one to conclude that 

transmission planning either is or is not something that can be subject to Commission 

requirements.

158. Finally, the same conclusion applies to the Commission policy statements on data 

collection that petitioners cite. None of these policy statements includes any analysis of 

the scope of section 202(a). They do mention the importance of planning for achieving 

the goals of section 202(a), but such statements do not speak to what the Commission can 

require with respect to planning. Indeed, since they require reporting of information 

relevant to planning, one can just as easily infer that they pertain to matters where the 

Commission can establish requirements.

 222 New Reporting Requirement Under the Federal Power Act and Changes to 

Form No. FERC-714, FERC Stats. & Regs, Proposed Regulations ¶ 32,685 at 32,688 

(1993).
Docket No. RM10-23-001 -128-

c. Role of FPA Section 217(b)(4)

i. Requests for Rehearing and Clarification

159. Some petitioners contend that the transmission planning reforms in Order No. 

1000 ignore or run counter to the requirements of FPA section 217(b)(4).223 Similarly, 

several petitioners raise concerns that Order No. 1000’s requirement that public utility 

transmission providers, in consultation with stakeholders, consider transmission needs 

driven by Public Policy Requirements is prohibited by section 217(b)(4).224 Finally, 

some petitioners argue that the Commission erred in not finding that section 217(b)(4) is 

a Public Policy Requirement for purposes of Order No. 1000.225

160. With respect to whether Order No. 1000’s transmission planning reforms are 

inconsistent with section 217(b)(4), PPL Companies argue that Order No. 1000 

 223 See, e.g., PPL Companies; Southern Companies; Ad Hoc Coalition of 

Southeastern Utilities; and North Carolina Agencies. Ad Hoc Coalition of Southeastern 

Utilities and Southern Companies argue that Congress added section 217 in response to 

the Commission’s Standard Market Design (SMD) proposal in Docket No. RM01-12-

000. They assert that many considered this proposal as an intrusion on utilities’ ability 

plan to meet their native load. 

224 See, e.g., Large Public Power Council; Southern Companies; Ad Hoc Coalition 

of Southeastern Utilities.

225 See, e.g., Ad Hoc Coalition of Southeastern Utilities; APPA; Large Public 

Power Council; National Rural Electric Coops; and Transmission Access Policy Study 

Group. 
Docket No. RM10-23-001 -129-

undermines the intent of section 217 by stating that all planning improvements will assist 

load-serving entities. 

161. Transmission Dependent Utility Systems ask the Commission to clarify that 

regional and interregional transmission planning processes will abide by section 

217(b)(4) by optimizing solutions for transmission to allow long-term firm access to 

economically-priced long-term energy supplies by all load-serving entities to best satisfy 

their service obligations. Transmission Dependent Utility Systems therefore seek 

clarification or rehearing that coordination of reliability and economic planning includes 

identifying optimal solutions to congestion, to ensure that load-serving entities’ 

reasonable needs are met under FPA section 217(b)(4). They argue that once a 

transmission customer identifies an interregional transmission need, the interregional 

coordination process should consider this even if no developer has proposed an 

interregional solution and the public utility transmission providers themselves have not 

identified a potential interregional solution.

162. APPA and National Rural Electric Coops argue that Order No. 1000 incorrectly 

concludes that section 217(b)(4) does not provide a preference to load-serving entities, 

explaining that in Order No. 681, the Commission stated that section 217(b)(4) provided 

such a preference.226 Meanwhile, Coalition for Fair Transmission Policy states that, 

 226 APPA at 10-11 (citing Long-Term Firm Transmission Rights in Organized 

(continued...)
Docket No. RM10-23-001 -130-

rather than seeking a preference, entities are requesting a reasonable safeguard against 

planning process results that breach an unambiguous statutory prescription. It adds that 

Order No. 1000’s dismissal of requests for section 217(b)(4) protection in the regional 

transmission process is insufficient in light of Congress’ directive to enable load-serving 

entities to fully implement their resource decisions made under state authority.

163. NARUC argues that the planning process should require integrated resource plans 

or enacted state energy policies to be properly incorporated in the regional and 

interregional plans. NARUC states that while Order No. 1000 purports to respect 

integrated resource planning, it denies requests to have the planning process follow the 

requirement in FPA section 217(b)(4) for bottom-up transmission planning based on the 

needs of load-serving entities. It contends that this leaves the process open to potential 

top-down planning that might abrogate state integrated resource plans or other electricity 

policies enacted by state legislatures or regulators. Finally, NARUC seeks clarification 

that the Commission does not intend to leverage regional and interregional transmission 

plans that emerge from Order No. 1000 or the forthcoming compliance processes to 

 

Electricity Markets, Order No. 681, FERC Stats. & Regs. ¶ 31,226, at P 319, 320 (2006) 

(stating that “a broader preference for load-serving entities in general vis-à-vis non-loadserving entities is fully supported by the statute” and that “we believe section 217 of the 

FPA provides a general ‘due’ preference for load-serving entities”)); National Rural 

Electric Coops at 9-10 (citing same).
Docket No. RM10-23-001 -131-

infringe upon state siting authority or exceed the Commission’s backstop siting authority 

under FPA section 216.

164. Other petitioners raise concerns about the relationship between section 217(b)(4) 

and Order No. 1000’s requirement that public utility transmission providers consider 

transmission needs driven by Public Policy Requirements. Large Public Power Council 

argues that the requirement that public utility transmission providers consider 

transmission needs driven by Public Policy Requirements runs counter to FPA section 

217(b)(4). It argues that imposing such a requirement would result in reconsideration by 

regional planners of the same matters that resulted in the transmission demand 

projections by load-serving entities, and is likely to lead to skewed decision-making, 

reflecting political value judgments and stakeholder business plans. Southern Companies 

also assert that these requirements violate section 217(b)(4) by hampering their ability to 

expand the transmission system to meet the needs of their native load by making the 

transmission planning process more bureaucratic and inefficient.

165. Several petitioners assert that the Commission erred in not stating specifically that 

FPA section 217(b)(4) is a Public Policy Requirement that must be considered in the 

transmission planning process.227 APPA states that this provision is a specific legal 

 227 See, e.g., Ad Hoc Coalition of Southeastern Utilities; APPA; Large Public 

Power Council; National Rural Electric Coops; and Transmission Access Policy Study 

Group.
Docket No. RM10-23-001 -132-

directive regarding transmission planning enacted by Congress and imposed on the 

Commission. Transmission Access Policy Study Group explains that the intent of section 

217(b)(4) is to protect all load-serving entities, including transmission dependent utilities, 

and therefore, failure to include it as a public policy that must be considered in planning 

sends the message that planning to meet the reasonable needs of transmission dependent 

load-serving entities is optional in the planning process. Transmission Access Policy 

Study Group asserts that treating such entities as simply stakeholders whose needs may 

or may not be considered in the planning process violates section 217(b)(4)’s directive to 

the Commission to help meet load-serving entities’ needs. Ad Hoc Coalition of 

Southeastern Utilities states that section 217, as the only passage in the FPA that 

explicitly addresses planning, imposes on the Commission an obligation of a higher order 

than furthering other public policies not mentioned in the Commission’s organic statute. 

Ad Hoc Coalition of Southeastern Utilities contends that Order No. 1000 fails to facilitate 

planning to meet native load because it compels load-serving entities to participate in 

planning processes in which their obligations to serve native load are considered as just 

one among many public policies goals that may be advanced by stakeholders. Large 

Public Power Council agrees.

166. Other petitioners argue that the Commission’s nonincumbent reforms violate 

section 217(b)(4) by making it more difficult for them to meet their obligations to serve 
Docket No. RM10-23-001 -133-

native load.228 Southern Companies assert that not only does the Commission lack 

authority to impose Order No. 1000’s nonincumbent transmission developer 

requirements, but, to the extent it makes it more difficult for Southern Companies to 

expand their transmission system to meet their native load service obligations, those 

requirements are prohibited by section 217(b)(4). 

167. As for the regional planning process, MISO Transmission Owners Group 2 argues 

that eliminating the federal rights of first refusal will discourage robust participation in 

regional transmission planning. It asserts that eliminating the federal right of first refusal 

provides an incentive for incumbent public utilities with state-imposed retail service 

obligations that have local transmission planning processes to rely on their local process 

rather than the regional process to expand their transmission systems to serve their 

customers and comply with state mandates. It argues the same is true for incumbent 

public utility transmission providers that are NERC-registered entities that must construct 

transmission facilities to satisfy reliability standards or avoid NERC penalties. 

According to MISO Transmission Owners Group 2, this will result in the type of divided, 

inefficient, and potentially duplicative transmission expansion process that Order No. 

1000 purports to discourage, and will create an unreasonable incentive for utilities with 

local planning processes to favor local projects when a regional solution is warranted.

 228 See, e.g., Baltimore Gas & Electric; and Southern Companies.
Docket No. RM10-23-001 -134-

ii. Commission Determination

168. We deny rehearing. We continue to find that the transmission planning reforms 

required by Order No. 1000 are consistent with the Commission’s obligations under FPA 

section 217(b)(4). Section 217(b)(4) directs the Commission to exercise its authority 

under the FPA: 

in a manner that facilitates the planning and expansion of transmission 

facilities to meet the reasonable needs of load-serving entities to satisfy the 

service obligations of the load-serving entities, and enables load-serving 

entities to secure firm transmission rights (or equivalent tradable or 

financial rights) on a long-term basis for long-term power supply 

arrangements made, or planned, to meet such needs.229 

We believe that the regional transmission planning reforms required by Order No. 1000 

are consistent with this mandate because they will enhance the transmission planning 

process for all interested entities, including load-serving entities. We expect that loadserving entities and their customers, like other interested parties, will benefit from a 

regional planning process that identifies transmission solutions that are more efficient or 

cost-effective than what may be identified in the local transmission plans of individual 

public utility transmission providers. For example, we expect that the planning process 

required by Order No. 1000 will help identify efficient or cost-effective transmission 

projects that address the transmission needs of load-serving entities and their customers, 

 229 16 U.S.C. 824q(b)(4) (2006).
Docket No. RM10-23-001 -135-

whether they are driven by reliability, economics, or public policy requirements.

169. The Commission’s discussion of the relationship between section 217(b)(4) and 

the transmission planning reforms undertaken in Order Nos. 890 and 890-A further 

demonstrate that the Order No. 1000 regional transmission planning reforms are 

consistent with, and not prohibited by, section 217(b)(4).230 In Order No. 890-A, the 

Commission explained that “[t]ransmission planning activities are within our jurisdiction 

and, therefore, we have a duty under FPA section 206 to remedy undue discrimination in 

this area and a further obligation under FPA section 217 to act in a way that facilitates the 

planning and expansion of facilities to meet the reasonable needs of LSEs [load-serving 

entities].”231 We believe that the discussions in Order Nos. 890 and 890-A apply with 

equal force here.232 Contrary to some petitioners’ arguments, section 217(b)(4) does not 

limit or prohibit the transmission planning reforms required by Order No. 1000; rather, it 

directs the Commission to take action to facilitate the planning and expansion of 

 230 In Order No. 890, the Commission explained that section 217(b)(4) supported 

the transmission planning reforms therein. See Order No. 890, FERC Stats. & Regs. ¶ 

31,241 at P 436. Order No. 1000’s regional transmission planning reforms require public 

utility transmission providers to, among other things, adopt Order No. 890 transmission 

planning principles as part of their regional transmission planning process. Order No. 

1000, FERC Stats. & Regs. ¶ 31,323 at PP 150-52.

231 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 172.

232 The Commission discusses its jurisdiction with respect to transmission 

planning in this rule. See Order No. 1000, Stats. & Regs. ¶ 31,323 at section III.A.2; see 

also discussion supra at section III.A.1.
Docket No. RM10-23-001 -136-

transmission facilities to meet the reasonable needs of load-serving entities. While each 

transmission planning region may conclude that different approaches are best suited to 

accommodate those needs, we find that the framework we set forth in Order No. 1000 

will assist in accomplishing the requirements of section 217(b)(4).

170. As the Commission explained in Order No. 1000, the reforms adopted therein 

build on the requirements of Order No. 890 and further facilitate open and transparent 

transmission planning to, a goal that does not conflict with FPA section 217. Indeed, the 

Commission explained that Order No. 1000 is consistent with section 217, because it 

supports the development of needed transmission facilities that benefit load-serving 

entities. The Commission pointed out that the fact that the Order No. 1000 transmission 

planning reforms serve the interests of other stakeholders as well does not place the 

Commission’s action in conflict with section 217.233 Nothing in Order No. 1000 is 

intended to prevent or restrict a load-serving entity from fully implementing resource 

decisions made under state authority. Rather, the Commission’s expectation is that Order 

No. 1000 will facilitate the evaluation of potential transmission facilities needed to 

accommodate such resource decisions.

171. We find that assertions made by APPA and National Rural Electric Coops that 

section 217(b)(4) establishes a preference for load-serving entities are too broad. APPA 

 233 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 108.
Docket No. RM10-23-001 -137-

and National Rural Electric Coops state that Order No. 681, in which the Commission 

promulgated regulations under section 217(b)(4) regarding long-term firm transmission 

rights, expressly noted such a preference. However, Order No. 681 made this point in the 

context of securing long-term firm transmission rights supported by existing transmission 

capacity, which was the subject of that rulemaking proceeding, but not in the broader 

context of planning new transmission capacity. Specifically, Order No. 681 established a 

guideline that provided:

Load-serving entities must have priority over non-loadserving entities in the allocation of long-term firm 

transmission rights that are supported by existing transmission 

capacity. The transmission organization may propose 

reasonable limits on the amount of existing transmission 

capacity used to support long-term firm transmission rights.234

172. We do not find this statement inconsistent with the reforms in Order No. 1000, 

which address the planning and cost allocation for new transmission.235 In any event, as 

discussed above, we find that Order No. 1000’s transmission planning reforms will aid, 

not hinder, load-serving entities in meeting their reasonable transmission needs. Thus, 

 234 Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 325.

235 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 65 (the requirements of 

Order No. 1000 are “intended to apply to new transmission facilities, which are those 

transmission facilities that are subject to evaluation, or reevaluation as the case may be, 

within a public utility transmission provider’s local or regional transmission planning 

process after the effective date of the public utility transmission provider’s filing adopting 

the relevant requirements” in Order No. 1000).
Docket No. RM10-23-001 -138-

nothing in Order No. 1000’s transmission planning reforms conflicts with the existing 

requirements of Order No. 681 regarding the availability of long-term firm transmission 

rights in organized electricity markets.

173. In addition, by requiring that transmission needs driven by Public Policy 

Requirements be considered in local and regional transmission planning processes, our 

expectation is that such a requirement will assist load-serving entities and others in better 

meeting their transmission needs. For this same reason, we allow but do not require that 

the coordination of reliability and economic transmission planning include identifying 

optimal solutions to congestion to ensure that load-serving entities’ needs are met under 

section 217(b)(4), as suggested by Transmission Dependent Utility Systems. 

174. We also disagree with Coalition for Fair Transmission Policy’s contention that 

Order No. 1000 may not allow load-serving entities to implement their states’ resource 

decisions. As discussed in the following section, nothing in Order No. 1000 conflicts or 

interferes with the states’ integrated resource planning processes. Accordingly, and for 

the reasons discussed above, we do not believe that Order No. 1000’s requirements 

conflict with section 217, as some petitioners maintain. 

175. We also disagree with petitioners such as Large Public Power Council that the 

consideration of transmission needs driven by Public Policy Requirements runs counter 

to section 217(b)(4). First, as we stated above, we find that Order No. 1000 will enhance, 

not impede, meeting the needs of load-serving entities. We also believe that these 
Docket No. RM10-23-001 -139-

specific reforms may assist load-serving entities in meeting their transmission needs, 

especially because many, if not all, of the Public Policy Requirements will likely impose 

legal obligations on load-serving entities. Therefore, we see nothing inconsistent 

between these reforms and section 217(b)(4). 

176. We affirm Order No. 1000’s conclusion that we will not prescribe any statutes and 

regulations as Public Policy Requirements for purposes of Order No. 1000, including 

section 217(b)(4). We explained that we would not pick and choose any federal or state 

law or regulation as a Public Policy Requirement. Rather, it will be up to public utility 

transmission providers, in consultation with stakeholders, to develop a process that 

considers transmission needs driven by Public Policy Requirements. 

177. Further, we disagree with NARUC’s assertion that, while Order No. 1000 purports 

to support integrated resource planning, its requirements are contrary to section 

217(b)(4)’s requirement of a bottom-up transmission planning process. First, by its 

terms, section 217(b)(4) does not require a bottom-up transmission planning process, as 

NARUC claims. Rather, section 217(b)(4) requires the Commission to exercise its 

authority to facilitate the planning and expansion of transmission facilities to assist loadserving entities in meeting their reasonable transmission needs and to secure long-term 

firm transmission rights. It does not speak at all to how transmission planning processes 

should be established. Second, regardless of whether a regional transmission planning 

process is termed bottom-up or top-down, we emphasize that nothing in any of Order No. 
Docket No. RM10-23-001 -140-

1000’s requirements interferes with states’ authority to require integrated resource 

planning or utilities’ obligation to comply with such requirements, as discussed herein.

178. We disagree with petitioners that argue that Order No. 1000’s nonincumbent 

transmission developer reforms are prohibited by, or inconsistent with, section 

217(b)(4).236 Contrary to Southern Companies’ contention, these reforms do not make it 

more difficult for incumbent transmission providers to serve native load. Indeed, we 

believe just the opposite to be the case, for as found in Order No. 1000, the Commission 

believes that greater participation by transmission developers in the transmission 

planning process may lower the cost of new transmission facilities, enabling more 

efficient or cost-effective deliveries by load-serving entities and increased access to 

resources.237 Accordingly, we expect that incumbent transmission providers will 

ultimately benefit from these reforms because they support the identification of more 

efficient or cost-effective transmission solutions, thereby improving their ability to meet 

the reasonable needs of load-serving entities to satisfy their load serving obligations.

179. We also disagree with MISO Transmission Owners Group 2 that these reforms 

will necessarily encourage incumbent transmission providers to favor local transmission 

 236 Other issues regarding Order No. 1000’s nonincumbent reforms are discussed 

in section III.B, infra.

237 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 291. 
Docket No. RM10-23-001 -141-

planning and local transmission projects over regional transmission planning and regional 

transmission solutions. While nothing in Order No. 1000 prohibits an incumbent 

transmission provider from proposing a local transmission solution to satisfy a reliability 

need or service obligation, we are not persuaded that allowing incumbent transmission 

providers to choose among these options will lead to less robust regional transmission 

planning. There are a variety of factors that incumbent transmission providers must 

consider when deciding whether to propose a local transmission facility instead of relying 

on a transmission facility selected in the regional transmission plan for purposes of cost 

allocation. We also believe, as discussed in Order No. 1000 and herein, that the 

nonincumbent transmission developer reforms will lead to more competition among 

developers, which in turn will lead to the identification of more efficient and costeffective transmission facilities. Accordingly, we are not persuaded that the elimination 

of a federal right of first refusal will necessarily will lead to inefficient or duplicative 

transmission planning processes.

d. Effect on Integrated Resource Planning and State 

Authority Over Transmission Siting, Permitting, and 

Construction

i. Requests for Rehearing and Clarification 

180. Several state regulators and others claim that Order No. 1000 improperly intrudes 

on authority over matters traditionally reserved to the states, such as integrated resource 
Docket No. RM10-23-001 -142-

planning and the construction and siting of transmission facilities.238 North Carolina 

Agencies and Southern Companies argue that, in contrast to the extensive jurisdiction 

over transmission planning historically exercised by the states, the FPA grants the 

Commission little, if any, authority in this area. Florida PSC and Georgia PSC also state 

that FPA section 201(a) limits the Commission’s authority to regulate interstate 

transmission and wholesale power sales to only those matters that are not subject to state 

regulation, and that the Commission provided no evidence of discrimination to support 

preempting state authority over transmission planning.239

181. Several petitioners argue that Order No. 1000’s planning reforms will disrupt, and 

potentially preempt, a state’s integrated resource planning.240 For example, Georgia PSC 

states that if regional and interregional transmission planning and coordination 

requirements result in a previously unidentified transmission project being included in a 

Commission-regulated process, that result will disrupt and skew existing state-regulated 

 238 See, e.g., NARUC; Florida PSC; Alabama PSC; Georgia PSC; Kentucky PSC; 

North Carolina Agencies; Large Public Power Council; Ad Hoc Coalition of 

Southeastern Utilities; Southern Companies; and Coalition for Fair Transmission Policy.

239 In relevant part, FPA section 201(a) provides that federal regulation over the 

interstate transmission and wholesale sale of electric energy only “extend[s] to those 

matters which are not subject to regulation by the States.” 16 U.S.C. 824(a).

240 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Alabama PSC; Georgia 

PSC; and Southern Companies.
Docket No. RM10-23-001 -143-

transmission and integrated resource planning processes, and will undermine its ability to 

effectively regulate bundled retail service. 

182. Similarly, Alabama PSC contends that least-cost, reliable solutions identified for 

its ratepayers through integrated resource planning will be subordinated to the solutions 

identified for the region under the Commission-administered process, with no assurance 

that this regional solution will hold local ratepayers harmless. NV Energy also asserts 

that inclusion of alternative transmission and non-transmission proposals in the regional 

or interregional plan could trump a transmission facility in a local plan, rendering the 

state’s integrated resource planning process meaningless.241 NV Energy contends that 

this could lead to “forum shopping,” particularly in the case of considering Public Policy 

Requirements, and that states may be reluctant to approve the siting of facilities that are 

the result of a process of exclusion or substitution of facilities that they deem necessary 

and appropriate in their integrated resource planning processes.242 NV Energy thus 

seeks clarification that for any facilities included in a “local” plan, those facilities are not 

subject to “de novo” review at the regional or interregional level unless the transmission 

provider voluntarily subjects the facilities to an alternative review or the facilities are 

 241 See also Coalition for Fair Transmission Policy at 27 (citing Order No. 1000, 

FERC Stats. & Regs. ¶ 31,323 at P 154).

242 NV Energy at 7-8. 
Docket No. RM10-23-001 -144-

proposed by the transmission provider for regional cost allocation and they are so 

chosen.243 Coalition for Fair Transmission Policy seeks clarification that regional 

transmission planning processes and interregional transmission coordination do not have 

the ability or authority to affect or change resource decisions made by entities with 

responsibility to meet public policy requirements and the transmission needs that they 

have identified associated with those resource decisions, except with the voluntary 

agreement of those responsible entities.

183. Kentucky PSC argues that Order No. 1000 infringes on state jurisdiction over 

integrated resource planning through its failure to require transmission planning and cost 

allocation processes to allow for the unique role of state regulators in determining which 

projects will be constructed and who will pay for them. Kentucky PSC notes that in 

Kentucky, only the state legislature can decide if in-state utilities must use certain 

proportions of various types of energy resources. It maintains that a decision to develop a 

transmission facility might de facto make decisions about types and locations of 

generation resources. Kentucky PSC also argues that Order No. 1000 erred regarding the 

consideration of non-transmission alternatives, asserting that such matters are within the 

exclusive province of state-regulated integrated resource planning.244

 243 NV Energy at 9.

244 See also Alabama PSC at 3-4.
Docket No. RM10-23-001 -145-

184. Some petitioners, such as Ad Hoc Coalition of Southeastern Utilities, argue that 

regional cost allocation determinations under Order No. 1000 will have a preemptive 

effect on decisions made at the state level. Ad Hoc Coalition of Southeastern Utilities 

asserts that if ratepayers must pay for a nonincumbent’s transmission line chosen in the 

regional planning process, it would be difficult for the incumbent owner to pursue an 

alternate project, resulting in the indirect regulation of actual transmission planning 

decisions, including siting, construction, permitting, and resource planning decisions. It 

states that the Commission is prohibited from doing indirectly what it is prohibited from 

doing directly.245 Ad Hoc Coalition of Southeastern Utilities also states that if the 

Commission states on rehearing that it does not regulate substantive planning, then it 

should explain the ramifications of a transmission provider not implementing the regional 

transmission plan. Southern Companies raise the same argument, emphasizing that the 

decision to fund transmission projects determines the projects to be pursued. 

185. Ad Hoc Coalition of Southeastern Utilities assert that Order No. 1000’s regional 

and interregional processes will likely result in more long distance transmission lines, 

which could prove to be disruptive to a bottom-up integrated resource planning process 

due to its significant impacts on bulk power flows. 

 245 Ad Hoc Coalition of Southeastern Utilities at 43-44 (citing generally Towns of 

Concord, Norwood, and Wellesley, Mass. V. FERC, 955 F.2d 67, 71 n.2 (D.C. Cir. 

1992)).
Docket No. RM10-23-001 -146-

ii. Commission Determination

186. As we stated in Order No. 1000, nothing therein is intended to preempt or 

otherwise conflict with state authority over the siting, permitting, and construction of 

transmission facilities or over integrated resource planning and similar processes. Order

No. 1000 explained that “nothing in this Final Rule involves an exercise of siting, 

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

requirements of this Final Rule, like those of Order No. 890, are associated with the 

processes used to identify and evaluate transmission system needs and potential solutions 

to those needs.” Order No. 1000 concluded that “[t]his in no way involves an exercise of 

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

including integrated resource planning, or authority over such transmission facilities.”246

187. We affirm that conclusion here. In so finding, we recognize, as we did in Order 

No. 1000, that the states have a significant jurisdictional role in the siting, permitting, and 

construction of transmission facilities, and that many states require public utility 

transmission providers to undertake and implement integrated resource plans. However, 

as we explain below, the Commission may undertake Order No. 1000’s reforms without 

intruding on state jurisdiction.

 246 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 107. 
Docket No. RM10-23-001 -147-

188. At the outset, it is important to recognize that Order No. 1000’s transmission 

planning reforms are concerned with process; these reforms are not intended to dictate 

substantive outcomes, such as what transmission facilities will be built and where.247 We 

recognize that such decisions are normally made at the state level.248 Rather, Order No. 

1000’s transmission planning reforms are intended to ensure that there is an open and 

transparent regional transmission planning process that produces a regional transmission 

plan. If public utility transmission providers’ regional transmission processes satisfy 

these requirements, then they will be in compliance with Order No. 1000’s regional 

transmission planning requirements. Thus, contrary to arguments raised by some state 

regulators and others, Order No. 1000’s transmission planning reforms respect the 

jurisdictional authority of the states regarding the siting, permitting, and construction of 

transmission facilities. 

189. In support of their contention that Order No. 1000 infringes on state authority, 

North Carolina Agencies claim that the SMD White Paper expressly acknowledged that 

 247 Id. P 113 (“This Final Rule is focused on ensuring that there is a fair regional 

transmission planning process, not substantive outcomes of that process.”) (emphasis in 

original).

248 The Commission has limited backstop transmission siting authority under 

section 216 of the FPA. However, that limited authority is not at issue in this proceeding. 

In response to NARUC, we clarify that nothing in Order No. 1000 is intended to leverage 

the regional transmission planning or interregional transmission coordination reforms to 

exceed the Commission’s section 216 backstop authority.
Docket No. RM10-23-001 -148-

the planning aspects of the SMD proposal infringed on state jurisdiction over 

transmission planning. The content of the SMD White Paper is not relevant to this 

proceeding.249 There is nothing in Order No. 1000 that preempts state authority 

regarding transmission planning, including authority over the siting, permitting, and 

construction of transmission facilities.

190. By requiring public utility transmission providers to participate in an open and 

transparent regional transmission planning process that that leads to the development of a 

regional transmission plan, the Commission has facilitated the identification and 

evaluation of transmission solutions that may be more efficient or cost-effective than 

those identified and evaluated in the local transmission plans of individual public utility 

transmission providers.250 This will provide more information and more options for 

consideration by public utility transmission providers and state regulators and, therefore, 

can hardly be seen as detrimental to state-sanctioned integrated resource planning. Of 

course, we recognize that a regional transmission planning process may not identify any 

 249 In addition, what North Carolina Agencies actually cite to is a brief summary of 

arguments that the SMD White Paper proceeds to address.

250 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 146 (“We determine that 

such [regional] transmission planning will expand opportunities for more efficient and 

cost-effective transmission solutions for public utility transmission providers and 

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

Commission-jurisdictional services are just and reasonable and not unduly discriminatory 

or preferential.”).
Docket No. RM10-23-001 -149-

such transmission facilities and, even where more efficient or cost-effective transmission 

solutions are identified and selected in the regional transmission plan for purposes of cost 

allocation, such solutions may not ultimately be constructed should the developer not 

secure the necessary approvals from the relevant state regulators. Consistent with this, 

we also clarify that we do not require that the transmission facilities in a public utility 

transmission provider’s local transmission plan be subject to approval at the regional or 

interregional level, unless that public utility transmission provider seeks to have any of 

those facilities selected in the regional transmission plan for purposes of cost allocation. 

191. Accordingly, in response to Ad Hoc Coalition of Southeastern Utilities, we 

disagree that we are effectively making decisions about which transmission facilities will 

be sited and constructed, that we are effectively preempting state decisions in that regard, 

or that we are doing anything indirectly that we cannot do directly. As discussed above, 

we conclude that we possess ample legal authority under the FPA to implement Order 

No. 1000’s transmission planning reforms. As we also explain immediately above, 

nothing in Order No. 1000 explicitly or implicitly requires that any transmission facilities 

be sited, permitted, or constructed. We do not see that decisions made in the regional 

transmission planning process would interfere with these state-jurisdictional processes. 

Further, in response to Ad Hoc Coalition of Southeastern Utilities’ question regarding the 

implications of not implementing the regional transmission plan, we reiterate that Order 

No. 1000 requires a regional transmission plan be developed pursuant to a Commission-
Docket No. RM10-23-001 -150-

approved process, the Commission is not requiring that such a plan be filed for 

Commission approval or be implemented. Rather, as was made clear in Order No. 1000, 

the designation of a transmission project as a “transmission facility in a regional 

transmission plan” or a “transmission facility selected in a regional transmission plan for 

purposes of cost allocation” only establishes how the developer may allocate the costs of 

such a facility in Commission-approved rates if it is built.251 Order No. 1000, however, 

does not require that such facilities be built, give any entity permission to build a facility, 

or relieve a developer from obtaining any necessary state regulatory approvals.252

192. We disagree with Ad Hoc Coalition of Southeastern Utilities that the Order No. 

1000 transmission planning reforms will be disruptive to integrated resource planning 

due to the impact of long-distance transmission lines on bulk power flows. Some public 

utility transmission providers may be concerned that Order No. 1000, because it provides 

for transmission facilities being selected in the regional transmission plan for purposes of 

cost allocation, establishes an incentive for other entities to propose larger regional 

transmission projects that may disrupt or interfere with state-level integrated resource 

planning efforts. Even if such an incentive were present, we note that unless a longdistance transmission solution identified in the regional transmission planning process is 

 251 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 66.

252 Id.
Docket No. RM10-23-001 -151-

a more efficient or cost-effective solution than what is identified in the local transmission 

plans of individual public utility transmission providers, it would not be selected in the 

regional transmission plan for purposes of cost allocation.

193. We also disagree with Kentucky PSC that Order No. 1000’s direction that public 

utility transmission providers, in consultation with stakeholders, consider nontransmission alternatives is outside of the Commission’s jurisdiction. We do not require 

anything more than considering non-transmission alternatives as compared to potential 

transmission solutions, similar to what was developed in Order No. 890, Order No. 890-

A, and resulting compliance filings.253 The evaluation of non-transmission alternatives as 

part of the regional transmission planning process does not convert that process into 

integrated resource planning. Order No. 1000 requires that there be a regional 

transmission plan that includes transmission facilities selected in the regional 

transmission plan for purposes of cost allocation.254

 253 Id. P 155 n.149 (citing to Commission orders addressing Order No. 890 

compliance filings that require the evaluation of transmission, generation, and demand 

response on a comparable basis in the public utility transmission providers’ transmission 

planning process).

254 It may be the case that non-transmission alternatives may result in a regional 

transmission planning process deciding that a proposed transmission facility is not a more 

efficient or cost-effective solution and, accordingly, that facility may not be selected in 

the regional transmission plan for purposes of cost allocation. Such a decision by the 

regional transmission planning process does not interfere with integrated resource 

planning.
Docket No. RM10-23-001 -152-

194. In further response to those petitioners who claim that Order No. 1000 will disrupt 

state integrated resource planning, we note that the identification of more efficient or 

cost-effective transmission facilities through a regional transmission planning process 

should not disrupt state integrated resource planning. In any event, we find that such 

concerns are speculative and, should they arise, it will be in the context of a specific 

factual circumstance. If any issues arise in such a context, affected parties are free to 

raise these issues before the Commission in the appropriate proceeding. 

e. Legal Authority Related to Consideration of Transmission 

Needs Driven by Public Policy Requirements

i. Requests for Rehearing and Clarification

195. Several petitioners express concerns about the Commission’s legal authority to 

require public utility transmission providers to consider transmission needs driven by 

Public Policy Requirements, arguing that the Commission failed to meet its burden, and 

that the requirements raise federalism issues and go beyond the Commission’s statutory 

authority.

196. PPL Companies assert that while the Commission may permit public utility 

transmission providers to consider Public Policy Requirements on a voluntary basis, it 

erred in mandating such consideration without first finding that existing rates are unjust, 

unreasonable, or unduly discriminatory. They assert that the Commission has not met its 

FPA section 206 burden to explain why consideration of transmission needs driven by 

Public Policy Requirements will remedy unjust and unreasonable rates or undue 
Docket No. RM10-23-001 -153-

discrimination. They argue that having to plan for and construct such public policydriven transmission projects could unduly burden utilities and their customers with 

additional unjust and unreasonable costs that would not likely have been incurred but for 

the Public Policy Requirements. 

197. ELCON, AF&PA, and the Associated Industrial Groups argue that, by allowing 

one state’s public policy agenda to adversely affect electricity prices in other states that 

do not share that agenda, Order No. 1000 raises significant federalism issues. They claim 

that this obscures political accountability because ISOs/RTOs will have discretion to 

determine which public policy to follow, and that this approach permits the federal 

government to burden state taxpayers with onerous, unpopular policies or force them to 

subsidize the public policy decisions of neighboring states without facing the political 

accountability that federalism demands. They state that the federal government cannot 

commandeer state legislatures and state executives in the name of federal interests.255 

Alabama PSC raises similar concerns.

198. PPL Companies argue that the FPA does not permit utilities, or the Commission, 

to pursue public policy objectives broadly, and such a departure from the FPA requires an 

amendment to the statute itself and cannot be undertaken by the Commission via 

 255 ELCON, AF&PA, and the Associated Industrial Groups at 10 (quoting New 

York v. United States, 505 U.S. 144 (1992)); see also PSEG Companies at 45.
Docket No. RM10-23-001 -154-

rulemaking.256 PSEG Companies contend that the Commission acted outside the scope 

of its authority, arguing that there is no statute authorizing the Commission to require that 

transmission providers build public policy projects or even consider Public Policy 

Requirements. They also argue that, in the absence of specific findings of undue 

discrimination in a particular region, the Commission should leave it to transmission 

providers to determine if there is a problem that needs to be addressed through revisions 

to the planning process and, if necessary, develop solutions that do not get ahead of 

states’ efforts to implement their own public policies. They argue that the requirement 

that transmission providers prognosticate public policy outcomes and plan the system 

based on those predictions is not proportional to the alleged problem and is thus 

impermissible.257 They also allege that the Commission did not explain how and why the 

 256 PPL Companies at 10-11 (citing NAACP v. FPC, 425 U.S. 662, 669-70 (1976) 

(explaining why Congress’ direction for the Commission to act in furtherance of the 

public interest under the FPA “is not a broad license to promote the general welfare”); 

Atlantic City, 295 F.3d at 8 (explaining that, as a federal agency, the Commission is a 

“creature of statute,” having “no constitutional or common law existence or authority, but 

only those authorities conferred upon it by Congress.” (quoting Michigan v. EPA, 268 

F.3d 1075, 1081 (D.C. Cir. 2001) (emphasis added)); Louisiana Pub. Serv. Comm’n v. 

FCC, 476 U.S. 355, 374 (1986) (recognizing that “an agency literally has no power to act 

... unless and until Congress confers power upon it”); American Petroleum Inst. v. EPA, 

52 F.3d 1113, 1119-20 (D.C. Cir. 1995) (stating that in the absence of statutory 

authorization for its act, an agency’s “action is plainly contrary to law and cannot stand”); 

Ethyl Corp. v. EPA, 51 F.3d 1053, 1060 (D.C. Cir. 1995)).

257 PSEG Companies at 47 (citing California Indep. Sys. Operator Corp. v. FERC,

372 F.3d 395 (D.C. Cir. 2004) (CAISO v. FERC)).
Docket No. RM10-23-001 -155-

existing construct focusing on the planning of reliability and economic projects has not 

served the needs of load-serving entities.

199. Ad Hoc Coalition of Southeastern Utilities and Large Public Power Council assert 

that the Commission exceeded its authority under the FPA, as delineated in NAACP v. 

FPC, by directing transmission providers to consider Public Policy Requirements in the 

planning process. Ad Hoc Coalition of Southeastern Utilities argues that although 

Congress directs the Commission to act in furtherance of the public interest, it is not a 

broad license to promote the general public welfare.258 Instead, it asserts that public 

interest must be understood in the context of the broad goals of the FPA itself—to ensure 

the provision of reliable transmission service on a non-discriminatory basis, at just and 

reasonable rates. Thus, it argues that the Commission lacks authority to consider broad 

concepts of public policy in implementing its duties under the FPA, and may not 

promulgate rules advancing environmental goals. It notes that the Commission has 

recognized that its NEPA-related responsibilities to consider environmental policy 

objectives do not extend to section 205 rate filings.259 

 258 Ad Hoc Coalition of Southeastern Utilities at 53 (citing NAACP v. FPC, 425 

U.S. 662, 665 (1976)).

259 Ad Hoc Coalition of Southeastern Utilities at 54 (citing, e.g., Monongahela 

Power Co., 39 FERC ¶ 61,350, at 62,097, reh’g denied, 40 FERC ¶ 61,256 (1987) 

(Monongahela); 18 C.F.R. § 380.4(a)(15) (2011)). See also Large Public Power Council.
Docket No. RM10-23-001 -156-

200. Southern Companies argue that the Commission lacks authority under the FPA to 

enforce and implement state and federal policies, which violates Comcast v. FCC.

260 

They add that Order No. 1000’s regulation of specific evaluative practices violates 

precedent establishing that the Commission cannot regulate a matter just because the 

Commission is able to articulate some relationship between that matter and the 

Commission-regulated, wholesale electric and transmission services.261 They assert that 

the Commission’s reading of the holding of CAISO v. FERC, which it interprets as giving 

it authority to control anything that affects the need for interstate transmission facilities, 

is too broad since all aspects of our modern, electricity-consuming lives drive the need 

for interstate transmission facilities.262

201. Southern Companies asserts that Public Policy Requirements are merely 

components that drive load growth and resource decisions that are the major aspects of 

integrated resource planning, which demonstrates that addressing Public Policy 

Requirements is an issue for state-regulated integrated resource planning. In addition, 

 260 Southern Companies at 51 (citing Comcast Corp. v. FCC, 600 F.3d 642, 659 

(D.C. Cir. 2010)). 

261 Southern Companies at 51 (quoting State of Missouri v. Southwestern Bell Tel. 

Co., 262 U.S. 276, 289 (1923) (stating that a regulatory agency with general oversight 

and rate authority “is not the owner of the property of public utility companies, and is not 

clothed with the general power of management incident to ownership”) (Southwestern 

Bell)). 

262 Southern Companies at 52 (citing CAISO v. FERC, 372 F.3d 395). 
Docket No. RM10-23-001 -157-

they state that even though it already incorporates public policies into its transmission 

planning process, Order No. 1000’s Public Policy Requirement appears to add nothing 

but costs and burdens by mandating nothing more than compliance activities. Therefore, 

Southern Companies argue that Order No. 1000’s Public Policy Requirements are 

arbitrary and capricious,263 and violate National Fuel.

264 

202. Bonneville Power seeks clarification that the Public Policy Requirement reforms 

to its local planning process must be consistent with its statutory authorities related to 

providing regional and interregional transmission facilities.265 Bonneville Power states 

that its statutory authorities for planning and building transmission facilities are not 

constrained by the FPA’s just and reasonable and not unduly discriminatory standard. It 

also explains that while its Administrator may consider policies at play under those 

standards, he must also factor in other considerations.266 If the Commission declines to 

 263 Southern Companies at 50 (citing Motor Vehicles Mfrs. Ass’n of the U.S. v.

State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 43 (1983)). 

264 Southern Companies at 50 (citing National Fuel, 468 F.3d at 844). 

265 Bonneville Power at 21. Bonneville Power states that it is only requesting 

clarification with respect to its local planning process rather than with respect to the 

regional planning process in which it voluntarily participates. Bonneville Power at 22.

266 Bonneville Power states that Congress recognized this in section 1232 of 

EPAct 2005, which provides that if Bonneville Power enters into a contract, agreement, 

or arrangement for participation in a transmission organization, then it must assure, 

among other things, “consistency with the statutory authorities, obligations, and 

limitations of the federal utility.” Bonneville Power at 22 (quoting 42 U.S.C. 

(continued...)
Docket No. RM10-23-001 -158-

grant this clarification, Bonneville Power seeks rehearing, arguing that the Commission 

failed to provide reasonable notice of the requirement and failed to consider Bonneville 

Power’s comments and statutory requirements.

ii. Commission Determination

203. We deny rehearing. Many of the arguments raised on rehearing simply repeat 

assertions made by commenters in response to the Proposed Rule in this proceeding, 

namely, that the Commission is not permitted to require public utility transmission 

providers to consider transmission needs driven by public policy under the FPA or that 

the direction to public utility transmission providers to consider transmission needs 

driven by Public Policy Requirements is not a practice affecting rates. 

204. At the outset, it is important to emphasize exactly what these reforms are intended 

to do and what they clearly are not intended to do. As explained in Order No. 1000, in 

requiring the consideration of transmission needs driven by Public Policy Requirements, 

the Commission is not mandating fulfillment of those requirements or that public utility 

transmission providers consider the Public Policy Requirements themselves. We address 

this issue in more detail below,267 but we clarify here the basic components of Order No. 

1000’s requirements in this regard, as it appears there are misconceptions about precisely 

 

§16431(c)(1)(C)).

267 See discussion infra at section III.A.2.
Docket No. RM10-23-001 -159-

what Order No. 1000 requires. To be clear, we are not requiring that any federal or state 

laws or regulations themselves be considered as part of the transmission planning 

process. That distinction is critical, and we want to be clear that this is not what Order 

No. 1000 requires.268 

205. Instead, the Commission is acknowledging that the requirements in question are 

facts that may affect the need for transmission services and these facts must be 

considered for that reason. Our intent is that public utility transmission providers 

consider such transmission needs just as they consider transmission needs driven by 

reliability or economic concerns.269 We are not requiring that public utility transmission 

providers do any more than that. Such requirements may modify the need for and 

configuration of prospective transmission facilities. Accordingly, the transmission 

planning process and the resulting transmission plans would be deficient if they do not 

provide an opportunity to consider transmission needs driven by Public Policy 

Requirements.270 As a result, in Order No. 1000 we acted pursuant to our section 206 

 268 See discussion infra at section III.A.2.

269 We note that this is consistent with the approach taken in Order No. 888, and 

reiterated in Order No. 890, that public utility transmission providers are obligated to 

plan for the needs of their transmission customers. See, e.g., Order No. 890, FERC Stats. 

& Regs. ¶ 31,241 at PP 418-19.

270 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 109.
Docket No. RM10-23-001 -160-

authority to ensure that this deficiency is remedied in the OATTs of public utility 

transmission providers.

206. We thus disagree with PSEG Companies that Order No. 1000’s requirements in 

this regard are impermissible because the remedy is disproportionate to the identified 

problem. Again, we are requiring only that there be a process in place for public utility 

transmission providers, in consultation with stakeholders, to consider transmission needs 

driven by Public Policy Requirements. We believe that these reforms are necessary, 

because the record shows that there are, and there will continue to be, federal and state 

laws and regulations that will have a direct impact on transmission needs, just as 

reliability and economic concerns have a direct impact on transmission needs. By setting 

forth this process, our expectation is that public utility transmission providers, in 

consultation with stakeholders, will identify more efficient or cost-effective solutions to 

such transmission needs than may be the case without these requirements. 

207. Given the parameters described above, and discussed in more detail below,271

we 

do not see how these reforms are comparable to the matters at issue in NAACP v. FPC. 

As discussed in Order No. 1000, the Court in NAACP v. FPC found that the Commission 

did not have the power under the FPA or the Natural Gas Act (NGA) to construe its 

obligation to promote the public interest under those statutes as creating a “broad license 

 271 See discussion infra at section III.A.3.
Docket No. RM10-23-001 -161-

to promote general public welfare.”272 The Court also found that the Commission’s duty 

to promote the public interest under the FPA and NGA “is not a directive to the 

Commission to seek to eradicate discrimination,” and it thus did not authorize the 

Commission to promulgate rules prohibiting the companies it regulates from engaging in 

discriminatory employment practices merely because the statutes pertain to matters 

affected with a public interest.273 We reiterate here that the consideration of 

transmission needs driven by Public Policy Requirements “cannot be construed as 

pursuing broad general welfare goals that extend beyond matters subject to our authority 

under the FPA.”274 

208. The planning necessary to consider transmission needs driven by Public Policy 

Requirements is not different in substance from the planning required to address 

reliability or economic needs. Such planning requires an open and transparent process 

that provides interested stakeholders with access to studies, models and data used to make 

decisions. This transparency and coordination helps to ensure no undue discrimination 

on the part of the public utility transmission provider in planning for its own needs vis-àvis the needs of customers to which it is obligated to provide open access transmission 

 272 NAACP v. FERC, 425 U.S. 662 at 668.

273 Id. at 670.

274 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 111.
Docket No. RM10-23-001 -162-

service. Thus, we disagree with petitioners that suggest that Order No. 1000’s 

requirements in this regard are analogous to promoting broad notions of public policy, as 

contemplated in NAACP v. FPC. 

209. Similarly, we find that references to the Commission’s order in Monongahela are 

not relevant here. In that case, the Commission explained that we “have consistently 

recognized that [our] review of electric rate filings is not subject to NEPA,”275 and we 

then rejected arguments by an environmental advocacy group that the Commission curtail 

the operation of existing but unused capacity within a transmission provider’s system. 

We stated that “[b]ecause the Commission does not possess such curtailment authority by 

virtue of section 201(b) of the FPA, it could not accomplish indirectly through NEPA that 

which it is prohibited from doing directly under section 201(b) of the FPA.”276 Nothing 

in Order No. 1000 contradicts these statements. Similar to our discussion above that we 

are not promoting broad notions of public policy, we emphasize that we are not 

advocating for any particular environmental or other public policy and we are not 

requiring electric rate filings under section 205 to be subjected to NEPA. We are 

requiring only that transmission needs driven by Public Policy Requirements be 

 275 Monongahela, 39 FERC ¶ 61,350 at 62,097

276 Id.
Docket No. RM10-23-001 -163-

considered in transmission planning processes, just as public utility transmission 

providers consider reliability- and economic-based transmission needs. 

210. Further, we disagree with Southern Companies that our actions in this regard are 

akin to what was at issue in CAISO v. FERC. As explained in Order No. 1000, in that 

case, the court found that the Commission did not have the authority under section 206 of 

the FPA to direct the California ISO to alter the structure of its corporate governance, 

concluding that the choosing and appointment of corporate directors is not a “practice ... 

affecting [a] rate” within the meaning of the statute.277 The court explained that the 

Commission is empowered under section 206 to assess practices that directly affect or are 

closely related to a public utility’s rates and “not all those remote things beyond the rate 

structure that might in some sense indirectly or ultimately do so.”278 As we explained in 

Order No. 1000, the transmission planning activities that are the subject of the rule have a 

direct and discernable effect on rates.279 These reforms are intended to help create a path 

to allow public utility transmission providers, in consultation with stakeholders, in each 

transmission planning region to assess what transmission needs are being driven by 

 277 CAISO v. FERC, 372 F.3d at 403.

278 Id.

279 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 112.
Docket No. RM10-23-001 -164-

Public Policy Requirements, just as they currently look to whether transmission needs are 

driven by reliability or economic considerations. 

211. Similarly, our actions in this regard are not contrary to the Supreme Court’s 

opinion in Southwestern Bell, which was cited by Southern Companies. We are “not the 

owner of the property of public utility companies” and we are “not clothed with the 

general power of management incident to ownership,” and nothing in these rules provide 

the Commission with such authority.280 We are, as we discuss herein, providing for the 

consideration of transmission needs driven by Public Policy Requirements, just as public 

utility transmission providers consider transmission needs driven by reliability or 

economics. That direction is not tantamount to directing public utility transmission 

providers how to manage their property. 

212. Because, as discussed herein, we have statutory authority to implement these 

reforms, we disagree with Southern Companies’ that Order No. 1000 is contrary to 

Comcast v. FCC, where the court concluded that the Federal Communications 

Commission (FCC) lacked requisite statutory authority to regulate an Internet service 

provider’s network management practices. The court explained that the FCC could not 

rely on policy statements in the Communications Act of 1934 by themselves as the basis 

for the FCC to exercise ancillary authority to regulate Internet service, noting that policy 

 280 Southwestern Bell, 262 U.S. at 289.
Docket No. RM10-23-001 -165-

statements are not delegations of regulatory authority.281 The court also found that the 

FCC’s reliance on other statutory provisions failed because the agency was using its 

ancillary authority to pursue standalone policy objectives rather than to support its 

exercise of a delegated power.282 By contrast, the Commission’s transmission planning 

reforms, including those related to Public Policy Requirements, fall within the 

Commission’s statutorily mandated duties under the FPA, as discussed above. Thus, the 

Commission is not relying on ancillary authority to pursue standalone policy objectives, 

much less basing its actions on broad statements of Congressional policy.

213. We disagree with ELCON, AF&PA, and Associated Industrial Groups that Order 

No. 1000’s requirements regarding Public Policy Requirements raise significant 

federalism issues. As a factual matter, there are significant differences between what we 

are requiring in Order No. 1000 and the decision in New York v. U.S., which petitioners 

cite in support of their federalism argument. In that case, the Supreme Court held that the 

federal government could not compel states to implement a federal regulatory 

program.283 That is not what is at issue here. Instead, Order No. 1000 requires that local 

and regional transmission planning processes consider transmission needs driven by 

 281 Comcast v. FCC, 600 F.3d at 654-55.

282 Id. at 658-61.

283 New York v. U.S., 505 U.S. at 151.
Docket No. RM10-23-001 -166-

Public Policy Requirements. This requirement is directed to public utility transmission 

providers, which are subject to the Commission’s FPA jurisdiction, and not states. States 

are not required to implement any action.

214. Petitioners’ federalism argument focuses more on the allocation of costs 

associated with transmission facilities developed in response to Public Policy 

Requirements that are selected in the regional transmission plan for purposes of cost 

allocation. But it is unclear how petitioners can reasonably make the leap from the 

federal commandeering of state legislatures at issue in New York v. U.S. to the 

requirement that costs for transmission needs driven by Public Policy Requirements be 

allocated pursuant to an Order No. 1000-compliant cost allocation method. As discussed 

below, it may or may not be the case that entities in one state benefit from a new 

transmission facility built in response to another state’s Public Policy Requirement, in 

accordance with a transmission planning region’s regional cost allocation method. For 

example, a transmission facility selected in a regional transmission plan for purposes of 

cost allocation that was in the first instance advanced to meet the transmission needs 

driven by a particular state’s Public Policy Requirement may also provide reliability or 

economic benefits to entities located outside of that state. We do not see how a regional 

cost allocation method making such a finding equates with the commandeering of states 

by the federal government or that this is tantamount to requiring the states to implement a 

federal regulatory program. Rather, this simply ensures that costs are allocated to all 
Docket No. RM10-23-001 -167-

those entities that benefit from any given transmission facility that is selected in a 

regional transmission plan for purposes of cost allocation, regardless of whether those 

benefits are reliability, economic, or related transmission needs driven by Public Policy 

Requirements.

215. Next, we disagree with Southern Companies that the consideration of transmission 

needs driven by Public Policy Requirements interferes with integrated resource planning. 

First, as we explain above, Order No. 1000 does not infringe on integrated resource 

planning. States can continue to require utilities under their jurisdiction to engage in 

integrated resource planning, and nothing in Order No. 1000 changes that or otherwise 

negates those state-level resource decisions. Second, with respect to these specific 

reforms, we note that this requirement is a tool for public utility transmission providers to 

consider transmission needs that may not be captured under existing transmission 

planning processes, which are focused on reliability and economic needs. If the 

transmission planning process does consider additional transmission needs, i.e., those 

driven by Public Policy Requirements, that does not mean this interferes with state-level 

integrated resource planning, just as those existing transmission planning processes do 

not interfere today.

216. We clarify that, for entities such as Bonneville Power, which may be subject to 

their own organic statutes and regulations, nothing in Order No. 1000’s reforms regarding 

the consideration of transmission needs driven by Public Policy Requirements is intended 
Docket No. RM10-23-001 -168-

to preempt those organic statutes or regulations. We believe that this should address 

Bonneville Power’s concern. 

f. Legal Issues Related to Order No. 1000’s Interregional 

Transmission Coordination Reforms

i. Requests for Rehearing and Clarification

217. While most rehearing requests address legal issues associated with transmission 

planning in general, some petitioners raise legal issues specifically related to Order No. 

1000’s interregional transmission coordination reforms. 

218. Some petitioners argue that the Commission lacks authority to require 

transmission providers to engage in interregional coordination.284 Xcel, for example, 

argues that the Commission has not adequately explained how interregional transmission 

planning activities of public utilities directly affect jurisdictional rates. It asserts that 

under a planning process no rate is charged and no transmission customer is in privity to 

the transmission owner. California ISO asserts that it is not precluded from arguing that 

the Commission’s interregional planning requirements in Order No. 1000 are beyond its 

authority based on the fact that it did not seek judicial review of the transmission 

planning provisions of Order No. 890. 

 284 See, e.g., Ad Hoc Coalition of Southeastern Utilities; California ISO; Southern 

Companies; and Xcel.
Docket No. RM10-23-001 -169-

219. Ad Hoc Coalition of Southeastern Utilities and Southern Companies assert that the 

Commission has not historically required transmission planning and coordination 

agreements to be filed, and argues that it is arbitrary and capricious for the Commission 

to determine now that such agreements are jurisdictional under section 205. They state 

that the Commission did not include transmission planning and coordination agreements 

among the type of agreements that are listed as jurisdictional in the Commission’s Prior 

Notice order.285 Ad Hoc Coalition of Southeastern Utilities adds that this is logical 

because the penalty for untimely filings of jurisdictional agreements, i.e., the payment of 

a refund to the affected customer in the form of interest on the payments received over 

the period that the jurisdictional agreement was not on file, would not apply to a 

transmission coordination planning agreement.286 For example, because there are no 

rates or payments in a transmission planning or coordination agreement, it asserts that 

there would be no penalty, which reinforces its claim that the Commission has no 

jurisdiction over such agreements for purposes of section 206. 

 285 Ad Hoc Coalition of Southeastern Utilities at 63-64; Southern Companies at 85 

(citing Prior Notice and Filing Req’ts Under Part II of the Fed. Power Act, 64 FERC ¶ 

61,139 (1993) (Prior Notice Order)).

286 Ad Hoc Coalition of Southeastern Utilities at 63 (citing generally Prior Notice 

Order, 64 FERC ¶ 61,139, App. at 11.)
Docket No. RM10-23-001 -170-

220. WIRES states that section 206 requires the Commission to indicate what measures 

will cure the practical and legal deficiencies in interregional planning and to order 

industry to make curative filings, not to ask industry to spend months in effect deciding 

what will satisfy the FPA. Moreover, it states that ordering regulated entities to make 

filings under section 205 is impermissible. It therefore contends that Order No. 1000 

lacks substantial evidence for this approach and is not the result of reasoned decisionmaking.

221. Bonneville Power seeks clarification that the formal procedure required by Order 

No. 1000 to identify and jointly evaluate transmission facilities that are proposed to be 

located within adjacent transmission planning regions may be established in a manner 

that allows Bonneville Power to identify and evaluate the interregional facility in an open 

and transparent process in accordance with its statutory authority.287 Alternatively, it 

requests rehearing of the Commission’s rejection of Bonneville Power’s concerns on the 

grounds that the Commission’s decision is arbitrary and capricious and violates the 

Administrative Procedure Act. Bonneville Power argues that, if the requirement for a 

formal procedure to identify and jointly evaluate proposed interregional facilities includes 

details about how the facilities will be planned and developed, then the Commission 

 287 Bonneville Power at 32-34 (citing Order No. 1000, FERC Stats. & Regs. ¶ 

31,323 at P 478, 481).
Docket No. RM10-23-001 -171-

effectively ignored Bonneville Power’s comment without explanation. Bonneville 

Power asserts that the Commission’s requirement, in effect, impermissibly requires nonpublic utilities to adhere to the FPA requirements applicable to public utilities, which it 

believes will have a chilling effect on non-public utility participation in regional planning 

process, contrary to the Commission’s goal of broad-based participation. Bonneville 

Power also argues that the Commission lacks authority to require it to accept regulations 

under sections 205 and 206 as a condition of its participation in regional or interregional 

transmission planning.

ii. Commission Determination

222. We affirm our legal authority to undertake Order No. 1000’s reforms regarding 

interregional transmission coordination. We disagree with Xcel that we have not 

explained how interregional transmission coordination is a practice affecting 

jurisdictional rates. Similar to our regional transmission planning reforms, the 

Commission found that the interregional transmission coordination reforms will help to 

identify transmission facilities that may be more efficient or cost-effective than what 

individual transmission planning regions may identify, thereby helping to ensure that 

jurisdictional rates for transmission service are just and reasonable and not unduly 

discriminatory or preferential. 

223. Further, we disagree with WIRES that we cannot undertake the interregional 

transmission coordination reforms as set forth in Order No. 1000. Order No. 1000 
Docket No. RM10-23-001 -172-

requires that the public utility transmission providers in each pair of neighboring 

transmission planning regions, working through their regional transmission planning 

processes, must develop the same language to be included in each public utility 

transmission provider’s OATT that describes the interregional transmission coordination 

procedures for that particular pair of regions, or alternatively, to enter into interregional 

coordination agreements.288 In doing so, the Commission is allowing public utility 

transmission providers in the first instance to negotiate the terms of the common OATT 

language or agreements, so long as they meet the minimum requirements set forth in 

Order No. 1000. This approach is consistent with the regional flexibility provided 

elsewhere in Order No. 1000. WIRES offers no compelling reason that we should depart 

from that approach here. The Commission has taken appropriate action under FPA 

section 206 to undertake the interregional transmission coordination reforms. While we 

provide flexibility and, therefore, allow public utility transmission providers the ability to 

craft agreements that take into account their needs and the needs of their stakeholders, it 

is important to note that the Commission will review each compliance filing to ensure 

that they are just and reasonable and not unduly discriminatory or preferential.

224. We also disagree with Ad Hoc Coalition of Southeastern Utilities and Southern 

Companies that it is arbitrary and capricious to require public utility transmission 

 288 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 475.
Docket No. RM10-23-001 -173-

providers to file interregional transmission coordination agreements. As an initial matter, 

as noted above, the Commission does not require that public utility transmission 

providers enter into interregional transmission coordination agreements to comply with 

Order No. 1000, though they may do so. Rather, public utility transmission providers 

must develop common OATT language that implements Order No. 1000’s interregional 

transmission coordination reforms. As noted above, we find that these reforms are 

necessary to identify more efficient or cost-effective transmission facilities than what 

individual transmission planning regions may identify, thereby helping to ensure that 

jurisdictional rates for transmission service are just and reasonable and not unduly 

discriminatory or preferential. Accordingly, it follows that such common OATT 

language must be filed with the Commission. Furthermore, we fail to see how this is 

changed by the Commission allowing, as an alternative, public utility transmission 

providers to reflect the interregional transmission coordination procedures in an 

agreement filed with the Commission.

225. Moreover, whether or not such agreements were contemplated in the Prior Notice 

Order, we find that the Prior Notice Order does not prescribe the entire universe of 

filings that the Commission will require to be filed. To so limit the universe of such 

agreements would impede the Commission’s statutory duty to ensure that the rates, terms, 

and conditions of jurisdictional service are just and reasonable and not unduly 

discriminatory or preferential. In the Prior Notice Order, the Commission made an effort 
Docket No. RM10-23-001 -174-

to bring certainty to a number of jurisdictional issues surrounding certain agreements. 

Among other things, the Prior Notice Order stated that “the utility industry remains 

unclear as to whether various types of agreements need to be filed for Commission 

review because of the uncertain jurisdictional status of particular types of agreements.”289 

It should be noted that the Commission did not represent that the agreements it addressed 

in the Prior Notice Order were, or would be, the only agreements that are subject to the 

Commission’s jurisdiction.290

226. Ad Hoc Coalition of Southeastern Utilities overstates the Prior Notice Order’s 

discussion when it contends that the Prior Notice Order’s remedy for late-filed 

agreements (i.e., time-value refunds) shows the questionable jurisdictional nature of 

interregional transmission coordination agreements because the remedy would not apply. 

We stated: “If a utility files an otherwise just and reasonable cost-based rate after the 

new service has commenced, we will require the utility to refund to its customers the time 

 289 Prior Notice Order, 64 FERC ¶ 61,139 at 61,977.

290 In the appendix to the Prior Notice Order, the Commission provided “a brief 

analysis of the various types of agreements identified by the participants in this 

proceeding . . . . [T]his analysis is general in nature and is intended to be illustrative of 

the Commission’s current thinking on these subjects.” Prior Notice Order, 64 FERC ¶ 

61,139 at 61,989. The specific types of agreements discussed in the appendix to the 

Prior Notice Order include: (1) contribution in aid of construction agreements; (2) 

Qualifying Facility agreements; (3) exchanges; (4) borderline agreements; and (5) de 

minimis agreements. Id. at 61,989-96.
Docket No. RM10-23-001 -175-

value of the revenues collected . . . for the entire period that the rate was collected 

without Commission authorization . . . . We will implement a similar remedy for the 

unauthorized late filing of market-based rates.”291 We note that this discussion focuses 

on rate filings (whether market-based or cost-based). However, there are other types of 

documents that the Commission requires to be filed that govern the terms and conditions 

of jurisdictional transmission service. For example, many pro forma OATT provisions 

deal with terms and conditions rather than strictly with rates. And, as discussed herein, 

we find that interregional transmission coordination issues have a direct and concrete 

impact on jurisdictional rates and, consequently, interregional transmission coordination 

agreements must also be filed.

227. We clarify for Bonneville Power that Order No. 1000’s interregional transmission 

coordination reforms are not intended to preempt the statutes governing Bonneville 

Power. However, to the extent that any of the interregional transmission coordination 

efforts in which Bonneville Power participates does have the effect of interfering with 

Bonneville Power’s statutory duties, it may bring those concerns to the Commission’s 

attention.

g. Other Legal Issues Related to Regional Transmission 

Planning Requirements

 291 Id. at 61,979-80.
Docket No. RM10-23-001 -176-

i. Requests for Rehearing and Clarification

228. APPA asserts that public power systems will likely be unable to participate in 

regional transmission planning processes without specific assurances that their legal 

obligations and concerns will be accommodated in regional transmission planning 

processes. In particular, APPA is concerned that public power systems may lose their 

tax-exempt status if transmission facilities are found to be used for private activity rather 

than public activity. APPA argues that Order Nos. 888 and 890 acknowledged the 

importance of this issue by limiting a jurisdictional public utility’s transmission 

obligations regarding facilities funded with local furnishing bonds, and that Congress 

limited the Commission authority to require non-jurisdictional transmission providers to 

provide comparable transmission service. APPA states that the Commission’s 

expectation that non-public utility transmission providers will participate in regional 

transmission planning processes is at odds with the Commission’s declining to provide 

assurance in Order No. 1000 of accommodations for their unique limitations, choosing 

instead to advise public power systems to advocate such accommodation on their own in 

these regional processes. APPA encourages the Commission to reaffirm the specific 

assurances provided to public power transmission providers in the past regarding the 

protection of their tax-exempt financing.

229. Arizona Cooperative and Southwest Transmission seek clarification that nothing 

in Order No. 1000 alters the rights of entities to submit section 206 complaints charging 
Docket No. RM10-23-001 -177-

that a transmission plan submitted, accepted, or approved under Order No. 1000, or a 

subsequent cost allocation or cost recovery made under such a plan, establishes or 

contributes to a rate, charge, classification, rule, regulation, practice, or contract that is 

not just and reasonable or that is unduly discriminatory or preferential. Otherwise, they 

seek rehearing because the right to file a complaint and the applicable standard for such 

complaints and for a rate, charge, classification, rule, regulation, practice or contract is 

established by sections 205 and 206 of the FPA and cannot be abrogated by the 

Commission by rule or practice. 

ii. Commission Determination

230. We recognize that Order No. 1000 may have been unclear as to whether public 

power entities, such as those represented by APPA, would be provided with the same 

assurances that they received in Order Nos. 888 and 890 as to whether the requirements 

of the rule would abrogate their tax-exempt status or cause them to violate a private 

activity bond rule. Order No. 1000 had focused on the consistency of reciprocity 

obligations in the three orders but did not specifically address the tax-exempt status of 

public power entities. To be clear, the assurances provided in Order Nos. 888 and 890 

remain unchanged in Order No. 1000. Consistent with Order Nos. 888 and 890, nothing 

in Order No. 1000 is intended to abrogate the tax-exempt status of public power entities 

or otherwise cause such entities to violate a private activity bond rule for purposes of 

section 141 of title 26 of the Internal Revenue Code. 
Docket No. RM10-23-001 -178-

231. In response to Arizona Cooperative and Southwest Transmission, we clarify that 

nothing in Order No. 1000 modifies any right to file a section 206 complaint. In so 

clarifying, we make the following observations. We note that Order No. 1000 does not 

require the filing of a regional transmission plan for Commission approval. Nonetheless, 

entities may file a complaint regarding the implementation of the process itself. We have 

entertained such complaints in similar circumstances.292 For example, a party might 

argue in a section 206 complaint that the public utility transmission providers in a given 

region did not follow their Commission-approved Order No. 1000-compliant regional 

transmission process in selecting facilities in their regional transmission plan for purposes 

of cost allocation. Of course, under section 206, the complainant bears the burden of 

proof to demonstrate that the process was unjust and unreasonable and that its proposed 

remedy is just and reasonable. We also note that a primary purpose of Order No. 1000 is 

to establish a Commission-approved open and transparent regional transmission planning 

process that includes cost allocation determinations based on a cost allocation method 

that is also Commission-approved.293 

 292 See, e.g., Transmission Technology Solutions, LLC and Western Grid 

Development, LLC v. California Indep. Sys. Operator Corp., 135 FERC ¶ 61,077 (2011) 

(Transmission Technology Solutions).

293 See, e.g., Transmission Technology Solutions, 135 FERC ¶ 61,077 at P 122 

(“Contrary to Complainants’ arguments, CAISO submitted evidence to demonstrate that 

its decision-making process reflected objective analysis; was consistent with the CAISO 

(continued...)
Docket No. RM10-23-001 -179-

2. Regional Transmission Planning Requirements 

a. Final Rule

232. Order No. 1000 required each public utility transmission provider to participate in 

a regional transmission planning process that produces a regional transmission plan that 

complies with seven of the nine transmission planning principles of Order No. 890.294 

Order No. 1000 required public utility transmission providers to evaluate, through this 

regional transmission planning process and in consultation with stakeholders, alternative 

transmission solutions that might meet the needs of the transmission planning region 

more efficiently or cost-effectively than solutions identified by individual public utility 

transmission providers in their local transmission planning process. This could include 

transmission facilities needed to meet reliability requirements, address economic

considerations, or meet transmission needs driven by Public Policy Requirements.295 

When evaluating the merits of such alternative transmission solutions, the Commission 

also directed public utility transmission providers in the transmission planning region to 

 

Tariff; and was based on approving the most prudent and cost-effective long-term 

projects that maintain reliability for the region.”). 

294 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 146, 151 & n.141 (the 

regional participation and cost allocation principles were not included because they are 

the subject of specific reforms in Order No. 1000).

Id. P 148.
Docket No. RM10-23-001 -180-

consider proposed non-transmission alternatives on a comparable basis.296 In addition, 

Order No. 1000 provided public utility transmission providers in each transmission 

planning region the flexibility to develop, in consultation with stakeholders, procedures 

by which the public utility transmission providers in the region identify and evaluate the 

set of potential solutions that may meet the region’s needs more efficiently or costeffectively. 

233. The Commission clarified that for purposes of Order No. 1000, a transmission 

planning region is one in which public utility transmission providers, in consultation with 

stakeholders and affected states, have joined for purposes of satisfying the requirements 

of Order No. 1000, including among other purposes to develop a regional transmission 

plan.297 The Commission explained that the scope of a transmission planning region 

should be governed by the integrated nature of the regional power grid and the particular 

reliability and resource issues affecting individual regions.298 While the Commission 

declined to prescribe the geographic scope of any transmission planning region, the 

Commission nevertheless clarified that an individual public utility transmission provider 

cannot, by itself, satisfy the regional transmission planning requirements of either Order 

 296 Id.

297 Id. P 160.

298 Id. (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 527).
Docket No. RM10-23-001 -181-

No. 890 or Order No. 1000.299 The Commission also noted that every public utility 

transmission provider has already included itself in a region for purposes of complying 

with Order No. 890’s regional participation principle, and encouraged public utility 

transmission providers to look to existing regional processes for guidance on compliance 

in formulating transmission planning regions.300 

234. Further, Order No. 1000 declined to require merchant transmission developers to

participate in a regional transmission planning process, because they assume all financial 

risk for developing and constructing their transmission facilities, and therefore, it is 

unnecessary to require such developers to participate in a regional transmission planning 

process for purposes of identifying the beneficiaries of their transmission facilities so that 

they can avail themselves of regional cost allocation.301 However, Order No. 1000 

acknowledged that a transmission facility proposed or developed by a merchant 

transmission developer has broader impacts than simply cost recovery. Therefore, Order 

No. 1000 concluded that it is necessary for a merchant transmission developer to provide 

adequate information and data to allow public utility transmission providers in the 

transmission planning region to assess the potential reliability and operational impacts of 

 299 Id.

300 Id.

301 Id. P 163.
Docket No. RM10-23-001 -182-

the merchant transmission developer’s proposed transmission facilities on other systems 

in the region.302 

b. Requests for Rehearing and Clarification

235. Petitioners raise a number of arguments with respect to the regional transmission 

planning process, which address such topics as whether public utility transmission 

providers were given too much flexibility, the definition of a “transmission planning 

region,” the participation of non-public utility transmission providers in regional 

transmission planning processes, compliance with Order No. 890 transmission planning 

principles, whether there needs to be a post-plan process, the role of state regulators in 

the regional transmission planning process, Order No. 1000’s treatment of merchant 

transmission projects, what constitutes “new” transmission facilities for purposes of 

Order No. 1000, and other issues.

236. Some petitioners are concerned that the Order No. 1000 does not set out the 

regional transmission planning requirements in sufficient detail. Illinois Commerce 

Commission contends that the Commission erred in providing too much flexibility in the 

regional planning process, and that now is the time for the Commission to provide 

guidance to the industry that will reduce business uncertainty and increase process 

efficiency. WIRES urges the Commission to assist the industry with new standard 

 302 Id. P 164.
Docket No. RM10-23-001 -183-

procedures for regional planning, including criteria for evaluating both major backbone 

projects and transmission upgrades that have a relatively short planning and construction 

cycle and that can be adapted to fill economic or reliability needs as they arise in the 

ordinary course of system operations. Regarding Order No. 1000’s statement that “public 

utility transmission providers explain in their compliance filings how they will determine 

which facilities evaluated in their local and regional planning processes will be subject to 

the requirements of this Final Rule” (emphasis added), Western Independent 

Transmission Group requests that transmission providers should not only simply 

“explain” how they will determine which facilities to evaluate, but also should be 

required to justify those determinations in their compliance filings.

237. PPL Companies are concerned with Order No. 1000’s mandate to participate in a 

regional transmission planning process, arguing that such a mandate forces utilities in 

non-RTO regions to join an RTO or RTO-like process. PPL Companies claim that 

because this mandate may put certain entities at odds with their state commissions, the 

Commission should clarify that RTO membership remains voluntary, as does 

participation in regional transmission planning. 

238. Others are concerned that Order No. 1000’s regional transmission planning 

reforms may allow public utility transmission providers to discriminate against other 

entities. Transmission Access Policy Study Group claims that Order No. 1000 enhances 

the ability of public utility transmission providers in non-RTO regions to benefit their 
Docket No. RM10-23-001 -184-

generation function by giving them the right to make decisions as to which upgrades go 

into the regional transmission plan for purposes of cost allocation, while transmission 

dependent utilities and non-jurisdictional entities are only offered the opportunity to 

provide input into the planning process. It points to the RTG Policy Statement, which it 

states provides for fair and nondiscriminatory governance and decision-making 

procedures and which states that transmission dependent utilities must be protected.303 If 

a non-RTO region does not provide balanced decision-making, Transmission Access 

Policy Study Group argues that there should be consequences, such as more scrutiny with 

respect to transmission rates and regional cost allocation methods. PPL Companies seek 

clarification that the Commission will review the voting rules and structures of regional 

and interregional groups to ensure that the effect of such structures on small utilities is 

not unjust, unreasonable or unduly discriminatory.

239. Transmission Dependent Utility Systems further argue the Commission should 

clarify that more efficient and cost-effective solutions to the effects of loop flow are 

among the things to be considered in regional planning and interregional coordination 

processes. Transmission Dependent Utility Systems state that although Order No. 1000 

 303 Transmission Access Policy Study Group at 9 (citing RTG Policy Statement, 58 

Fed. Reg. 41,626 (Aug. 5, 1993), FERC Stats. & Regs. ¶ 30,976 (1993); Southwest 

Regional Transmission Ass’n, 69 FERC ¶ 61,100, at 61,400-02 (1994); PacifiCorp, 69 

FERC ¶ 61,099, at 61,382, n.70 (1994)).
Docket No. RM10-23-001 -185-

discusses loop flows in the context of cost allocation, it does not address the issue in the 

context of regional planning or interregional coordination.

240. Several petitioners seek clarity as to what the Commission means by a 

“transmission planning region.”304 Energy Future Coalition Group asserts that the 

Commission must set minimum standards for defining transmission planning regions; 

otherwise, such regions may be defined in a way that is irrational and unworkable, thus 

hindering the transmission development that Order No. 1000 is meant to promote. It 

suggests the following: all transmission providers in the region must be within the same 

interconnection; participants in the region must be electrically contiguous; the region 

must have sufficient existing internal electricity generation and consumption to justify the 

planning of high voltage transmission facilities within it; and the region must be an 

integrated electric system for which transmission planning within the region can be 

accomplished consistent with engineering principles and common sense. It also suggests 

that the Commission specify that use of the regions approved for purposes of Attachment 

K coordination of transmission plans would be presumptively acceptable. 

241. Ad Hoc Coalition of Southeastern Utilities commends the Commission for what it 

characterizes as a reaffirmation of existing regions. However, it asserts that if the 

 304 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Energy Future Coalition 

Group; MISO Northeast; PPL Companies; and Southern Companies.
Docket No. RM10-23-001 -186-

Commission changes course and finds that planning regions in the Southeast are different 

from current regions, such a finding would be counter to Order No. 890 precedent. It 

also asserts that it would violate FPA section 202(a) because affected transmission 

owners and providers have not agreed to engage in transmission coordination based on a 

different configuration of a region. Southern Companies raise similar arguments, noting 

that it is commencing its compliance requirements with the understanding that the 

SERTP is an appropriate region under Order No. 1000.

242. PPL Companies state that the geographic scope requirement poses difficulties 

outside of an RTO. For example, they state that if Louisville Gas & Electric and 

Kentucky Utilities prefer to have a Kentucky-only planning group, it is unclear from 

Order No. 1000 whether such a region would be sufficient for regional planning 

purposes. PPL Companies further claim that regional transmission planning 

requirements raise practical concerns for entities outside of RTOs, particularly those in 

regions with non-public utility transmission providers, which have the discretion, not a 

mandate, to comply. PPL Companies thus seek clarification that a region can be 

comprised of a single system or single state where a broader scope is either difficult or 

impossible to attain.

243. MISO Northeast seeks clarification that an RTO/ISO may have more than one 

transmission planning region for purposes of developing regional transmission plans, 

noting that there are three distinct subregions in MISO. MISO Northeast states that while 
Docket No. RM10-23-001 -187-

the Commission does not require any changes to existing regions, limiting the number of 

transmission planning regions in an RTO/ISO to one would have the effect of prescribing 

the geographic scope of a transmission planning region, which the Commission said it 

would not do in Order No. 1000.

244. Several petitioners take issue with Commission’s statement in Order No. 1000 

that, “if a non-public utility transmission provider makes the choice to become part of the 

transmission planning region and it is determined by the transmission planning process to 

be a beneficiary of certain transmission facilities selected in the regional transmission 

plan for purposes of cost allocation, that non-public utility transmission provider is 

responsible for the costs associated with such benefits.”305 

245. Large Public Power Council contends that unless non-public utility transmission 

providers vote on which proposed transmission projects should be selected in the regional 

transmission plan for purposes of cost allocation, the Commission should allow nonpublic utility transmission providers to participate in all aspects of regional transmission 

planning without being allocated costs pursuant to the regional cost allocation method. 

Large Public Power Council argues that to do otherwise will substantially disrupt existing 

planning processes by discouraging non-public utility transmission providers from 

 305 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 629.
Docket No. RM10-23-001 -188-

participating out of concern that they will be allocated costs, detrimentally affecting 

system efficiency, cost, and reliability.

246. MEAG Power contends that it would be problematic for it to enter into an openended commitment to pay costs that are allocated per a regional plan before the regional 

planning and cost allocation protocols have been developed and determined. Moreover, 

MEAG Power states that this will deter it from continuing to participate in the current 

SERTP planning effort on a voluntary basis if in doing so it would be bound to an 

unknown amount of allocated transmission costs. MEAG Power requests clarification 

that its choice to continue to participate in SERTP does not bind it to a cost allocation 

result under Order No. 1000 Otherwise, it states it will be compelled by its Board’s 

policy to withdraw from SERTP as well as SIRPP before the provisions of Order No. 

1000 take full effect.

247. Transmission Dependent Utility Systems request that the Commission clarify or 

grant rehearing to specify that those stakeholders who have not meaningfully participated 

in the regional planning or interregional coordination, the development of regional and 

interregional cost allocation methods, or in the determination of beneficiaries, will have 

no costs for such projects allocated to them. Transmission Dependent Utility Systems 

argue this clarification will ensure participation of load-serving customers and is 

consistent with Cost Allocation Principle 2.
Docket No. RM10-23-001 -189-

248. Sacramento Municipal Utility District states that it participates in both the 

California Transmission Planning Group and the WestConnect planning processes, but 

would have little incentive to participate in either if doing so would expose it to costs for 

transmission over which it does not take any service and could result in duplicative 

charges.

249. Bonneville Power seeks clarification that it may independently decide, using an 

open and transparent process consistent with its statutory authorities, whether it will 

receive the benefits of, and pay for, a transmission project. It requests clarification that 

the regional planning process determination would not be binding on it, but that, instead, 

it and transmission developers could use the cost allocation analysis as input to their 

negotiations and other required statutory processes. Bonneville Power argues that this 

clarification is appropriate because its governing statutes do not permit it to participate in 

mandatory cost allocation, explaining that its Administrator must determine its cost 

allocation responsibilities and cannot delegate them to the regional planning process.306 

Bonneville Power argues that it also must retain the right to determine whether or not to 

commit funds to a project until conclusion of a review of a project under the National 

Environmental Policy Act. In the alternative, Bonneville Power requests rehearing, 

 306 Bonneville Power at 13-15 (citing Northwest Power Act, 16 U.S.C. § 839f(b) 

(2006); Transmission System Act, 16 U.S.C. §838b (2006); Pacific Northwest 

Generating Coop. v. DOE, Bonneville Power Admin., 580 F.3d 792, 823 (9th Cir. 2009)).
Docket No. RM10-23-001 -190-

arguing that the Commission failed to adequately consider and address its comments 

addressing Bonneville Power’s statutory authorities related to mandatory cost allocation.

250. With respect to Order No. 1000’s discussion of compliance with Order No. 890 

transmission planning principles and related issues, Ad Hoc Coalition of Southeastern 

Utilities argues that the Southeast transmission planning regions already comply with 

Order No. 890’s planning principles. Ad Hoc Coalition of Southeastern Utilities asserts 

that Order No. 890 and the subsequent compliance orders make it clear that the nine 

planning principles apply to regional planning processes. However, it asserts that certain 

statements in Order No. 1000, such as the statement that some regions are not exchanging 

sufficient data, imply that all or some of the nine planning principles do not apply under 

Order No. 890 to the existing regional planning processes.307 If the Commission assumes 

or concludes that utilities in the Southeast are not exchanging sufficient information, then 

Ad Hoc Coalition of Southeastern Utilities contends that such an assumption or 

conclusion would be in error and not supported by substantial evidence.

251. With regard to the openness and transparency transmission planning principles, 

Transmission Dependent Utility Systems want the Commission to clarify that information 

cannot be withheld from load-serving entities based on common rationales offered by 

 307 Ad Hoc Coalition of Southeastern Utilities at 48 (citing Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 at PP 151-52).
Docket No. RM10-23-001 -191-

transmission owners, such as claims of discrimination against non-load-serving entity 

customers, violation of tariff confidentiality provisions, or violation of the Commission’s 

Standards of Conduct. They argue that if these concerns are legitimate, they can be 

adequately addressed by confidentiality agreements or through other appropriate means. 

Transmission Dependent Utility Systems also want the Commission to confirm that such 

disclosure will not be deemed a violation of the Standards of Conduct.

252. With respect to the requirement that public utility transmission providers develop 

a regional transmission plan, Illinois Commerce Commission argues that the Commission 

erred in not requiring each transmission provider to file its regional transmission plan (as 

well as associated cost allocations), contending that the regional and interregional 

stakeholder processes that Order No. 1000 requires are not sufficient to ensure notice to 

the public and an opportunity to be heard. Illinois Commerce Commission states that the 

failure to establish a process for Commission review of regional transmission plans and 

associated cost allocations burdens ratepayers and exacerbates the problem associated 

with delegating authority to transmission providers.308

253. Transmission Access Policy Study Group argues that Order No. 1000 should have 

required a timely post-plan process to ensure that the plan is acted upon, and argues that 

 308 As noted above, Illinois Commerce Commission also believes that Order No. 

1000 provides too much flexibility to transmission providers.
Docket No. RM10-23-001 -192-

if a transmission developer has made a commitment to construct facilities, then it should 

not have the option to abandon the project, thus leaving others that counted on the 

upgrade responsible for the costs. It contends that the steps Order No. 1000 did take, 

such as website posting requirements and the reliability protections addressed in the 

context of Order No. 1000’s nonincumbent reforms, are inadequate. Additionally, 

Transmission Access Policy Study Group argues that Order No. 1000 should have made 

clear that the website posting requirement it did require must be made on a timely basis, 

such as a specified time after the regional transmission plan is posted.

254. Some state regulators raise concerns about the role they are intended to play in the 

regional transmission planning process.309 NARUC argues that, while prior Commission 

orders and the DOE-funded interconnectionwide planning processes properly recognize 

the essential role of state regulators, Order No. 1000 improperly lumps state regulators 

with all other stakeholders. Illinois Commerce Commission also points out that Order 

No. 1000 does not require transmission providers to establish any unique role or provide 

any special weight in the process for state regulators. Wisconsin PSC asserts that there is 

no rational basis for the casual and undefined potential role that Order No. 1000 implies 

that states would have in the regional and interregional transmission planning processes. 

 309 See, e.g., NARUC; Florida PSC; Illinois Commerce Commission; and 

Wisconsin PSC.
Docket No. RM10-23-001 -193-

It asserts that states and state commissions are different from other stakeholders in 

materially important ways, such as their authority to authorize utilities to build and the 

ability to collect an allocated share of the cost of transmission facilities. It also claims 

that this treatment of the states is at odds with Order No. 890’s express emphasis that 

“planning must be coordinated with state regulators...”310 Given this, Wisconsin PSC 

suggests the following changes to help enhance state participation: (1) more focus on 

reducing planning delays in a project’s preconstruction phase by coordinating with state 

regulators; (2) minimizing overlap between state and regional transmission planning 

procedures relative to evaluation of project need or sponsor qualification; and (3) where 

feasible, required compliance with applicable state laws by a transmission developer 

before any transmission line is selected for eligibility for regional cost sharing. North 

Carolina Agencies state that the Commission should recognize the unique and 

indispensible role that state regulatory authorities play, rather than demoting them to one 

of many stakeholders, as suggested in Order No. 1000. 

255. Further, Illinois Commerce Commission contends that the Commission failed to 

recognize that state regulators may be limited in their ability to actively engage in 

transmission planning processes given the prohibition against pre-judging cases that may 

 310 Wisconsin PSC at 9 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 

574 (2007)).
Docket No. RM10-23-001 -194-

subsequently come before them for siting, certification, or rate recovery. Illinois 

Commerce Commission suggests that Commission attendance in a meeting of the states 

to discuss this issue may be useful to reconcile the Commission’s expectations and the 

practical realities borne by state regulators in this regard. 

256. Florida PSC states that it is unclear how the Order No. 1000 transmission planning 

process overlay will interact and coexist with existing planning processes. Florida PSC 

also asserts that participating in the planning processes and monitoring neighboring 

interregional agreements would require additional state commission resources during a 

time of constrained state budgets. Illinois Commerce Commission likewise contends that 

the level of participation the Commission is encouraging is beyond most states’ current 

capabilities. It states that the Commission must go beyond Order No. 890 initiatives to 

facilitate enhanced participation by state authorities in regional and interregional planning 

processes. Illinois Commerce Commission also seeks clarification that, where regional 

state committees have been formed, it will be that committee (with Commission review) 

that decides on its budget for participation in the planning process, and such budget shall 

not be subject to veto by the transmission provider or any stakeholder group.

257. Some petitioners seek rehearing or clarification of Order No. 1000’s discussion of 

the role of merchant transmission developers in the regional transmission planning 
Docket No. RM10-23-001 -195-

process.311 APPA asks that the Commission reconsider its decision to allow merchant 

developers merely to provide information to transmission planners and instead require 

merchant transmission developers to participate fully in regional and interregional 

transmission planning processes. APPA argues that requiring such developers to 

participate in regional and interregional planning processes will give transmission 

planners the opportunity to evaluate all projects side-by-side and then develop the set of 

projects that will best serve the needs of all loads in a region, while presenting the best 

economics and minimizing adverse impacts on the environment.

258. National Rural Electric Coops seek clarification that Order No. 1000 does not 

create a special class of public utilities, i.e., merchant transmission developers, who are 

excused from obligations imposed on other public utility transmission providers. 

National Rural Electric Coops argue that the creation of a preferred class distinguished 

solely by their method of cost recovery does not square with the purpose of Order No. 

1000 to ensure that all public utility transmission providers be treated comparably in the 

transmission planning process. They contend that the method of cost recovery is not a 

valid reason for excusing public utility merchant developers from the regional planning 

requirements generally applicable to public utility transmission providers.

 311 See, e.g., APPA; National Rural Electric Coops; and Transmission Dependent 

Utility Systems.
Docket No. RM10-23-001 -196-

259. Transmission Dependent Utility Systems seek rehearing of the determination that 

merchant transmission developers may opt out of participation in regional transmission 

planning processes if they assume all financial risk. Transmission Dependent Utility 

Systems argue that financial arrangements have no bearing on the ability of affected loadserving entities to reliably and economically serve their native loads, that the failure to 

mandate merchant participation in regional transmission planning therefore conflicts with 

FPA section 217(b)(4), and that the internalization of risk by a merchant developer 

cannot justify excusing it from compliance with other planning obligations. They add 

that requiring merchant developers only to share information with public utility 

transmission providers fails to ensure that load-serving transmission customers will be 

able to obtain information about proposed merchant projects, evaluate their effects, and 

provide input regarding their development. Transmission Dependent Utility Systems 

seek clarification that if a merchant developer does not fully participate in a regional 

transmission planning process, it should be obligated to internalize the costs of any 

adverse reliability effects on the grid posed by its project or any need for upgrades caused 

by a change in flows, adding that the failure to require merchant developers to internalize 

all related costs of their transmission projects would violate cost causation principles by 

forcing transmission customers to pay for the costs of upgrades caused, but not paid for, 

by merchant transmission developers.
Docket No. RM10-23-001 -197-

260. Petitioners raise concerns about Order No. 1000’s conclusion that public utility 

transmission providers could apply flexible criteria when determining which transmission

projects are in the regional transmission plan. PSEG Companies argue that the 

Commission introduced vague criteria into the planning process that will result in an 

opaque and confusing, rather than a formulaic, approach.312 They claim that an opaque 

approach will allow transmission providers to unofficially represent policymaking bodies 

and impose their costs on customers, who must pay for unneeded projects.

261. Finally, some petitioners request guidance on what constitutes a “new” 

transmission facility for purposes of Order No. 1000. Western Independent Transmission 

Group seeks clarification of the Commission’s statement that Order No. 1000 applies to 

new transmission facilities. It states that Order No. 1000 does not provide sufficient 

guidance as to how transmission providers should define evaluation and reevaluation for 

purposes of determining what facilities are subject to Order No. 1000. It contends that, in 

the absence of Commission guidance, transmission providers will have excessive 

discretion to determine which facilities are subject to Order No. 1000. Western 

Independent Transmission Group seeks clarification regarding the extent of transmission 

 312 PSEG Companies at 50 (citing PJM Interconnection, L.L.C., 119 FERC ¶ 

61,265 at P 24 (2007) (directing PJM to file a formulaic approach with respect to 

planning for economic transmission projects)).
Docket No. RM10-23-001 -198-

planning entities’ discretion and Commission guidance as to how such discretion should 

be exercised without restricting independent developers’ access to the grid.

262. LS Power requests that the Commission clarify that all projects that are approved 

on or after the compliance date shall be subject to Order No. 1000, regardless of the 

status of the planning cycle. It explains that such a requirement would not burden the 

regional planning process as the transmission planning entity has ample warning 

regarding the requirement and can tailor its planning process to incorporate Order No. 

1000 for all projects not yet approved as of the compliance date.

c. Commission Determination

263. Order No. 1000’s regional transmission planning reforms are intended to ensure 

that there is an open and transparent regional transmission planning process that complies 

with Order No. 890’s transmission planning principles and produces a regional 

transmission plan. There, we stated that such transmission planning will expand 

opportunities for more efficient and cost-effective transmission solutions for public utility 

transmission providers and stakeholders, which, in turn, will help ensure that the rates, 

terms, and conditions of Commission-jurisdictional services are just and reasonable and 

not unduly discriminatory or preferential.313

 313 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 146.
Docket No. RM10-23-001 -199-

264. For the most part, petitioners do not argue against the soundness of Order No. 

1000’s basic regional transmission planning requirements although, as discussed above, 

some petitioners question the need for these reforms as applied to their specific regions of 

the country,314 while some assert that the Commission lacks the legal authority to 

undertake these reforms, as discussed earlier in this section.315 However, most of the 

petitioners’ requests as to the actual regional transmission planning requirements go to 

specific issues, such as the flexibility afforded in Order No. 1000 to public utility 

transmission providers, the definition of a transmission planning region, the participation 

of non-public utilities and the role of state regulators in the regional transmission 

planning process, compliance with certain transmission planning principles, the treatment 

of merchant transmission developers, and the definition of “new” transmission facilities 

under Order No. 1000. 

265. In this section, we affirm Order No. 1000’s regional transmission planning 

reforms. We also provide clarifications on many of the issues raised by petitioners, 

including an issue that generated a number of requests for rehearing and clarification, 

namely, the participation of non-public utility transmission providers in the regional 

transmission planning process. We believe the discussion herein will assist public utility 

 314 See discussion supra at section II.B.

315 See discussion supra at section III.A.
Docket No. RM10-23-001 -200-

transmission providers, in consultation with stakeholders, in developing their Order No. 

1000 compliance filings by providing more clarity as to what the Commission’s 

requirements are with respect to Order No. 1000’s regional transmission planning 

reforms.

266. Some petitioners, such as Illinois Commerce Commission, assert that Order No. 

1000’s regional transmission planning reforms provide too much flexibility to public 

utility transmission providers. We disagree. Rather, we believe that Order No. 1000 sets 

forth an approach that balances the need to ensure that specified regional transmission 

planning requirements are satisfied with our belief that the various regions of the country 

differ significantly in resources, industry organization, market design, and other ways so 

that a one-size-fits-all approach to regional transmission planning would not be 

appropriate. Specifically, Order No. 1000 requires public utility transmission providers 

to develop a regional transmission planning process that complies with the Order No. 890 

transmission planning principles and that produces a regional transmission plan. Within 

these parameters, public utility transmission providers, in consultation with stakeholders, 

have the flexibility to ensure that their respective regional transmission planning process 

is designed to accommodate the unique needs of that particular region. We will then 

evaluate each of the Order No. 1000 compliance filings to ensure that they satisfy these 

requirements. 
Docket No. RM10-23-001 -201-

267. For the same reasons, we decline to adopt standard procedures in the regional 

transmission planning process for evaluating backbone transmission facilities or for 

addressing transmission upgrades that have a short planning and construction cycle and 

that can be adapted to fill economic or reliability needs as they arise in the ordinary 

course of system operations, as suggested by WIRES. As the Commission found in 

Order No. 1000, each public utility transmission provider is required to amend its OATT 

to describe a transparent and not unduly discriminatory process for evaluating whether to 

select a proposed transmission facility in the regional transmission plan for purposes of 

cost allocation. This process must comply with the Order No. 890 transmission planning 

principles, ensuring transparency and the opportunity for meaningful stakeholder input. 

The evaluation process must culminate in a determination that is sufficiently detailed for 

stakeholders to understand why a particular transmission facility was selected or not 

selected in the regional transmission plan for purposes of cost allocation.316 Accordingly, 

we do not find that standardized procedures such as those suggested by WIRES are 

necessary or appropriate. Moreover, by requiring an open and transparent transmission 

planning process that produces a regional transmission plan, Order No. 1000 will provide 

the Commission and interested parties with a record that we believe will be able to 

highlight whether public utility transmission providers are engaging in undue 

 316 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 328.
Docket No. RM10-23-001 -202-

discrimination against others, such as transmission-dependent utilities and nonjurisdictional entities. 

268. As discussed in greater detail in the section of Order No. 1000 addressing 

nonincumbent reforms,317 we agree with Western Independent Transmission Group that 

public utility transmission providers should both explain and justify the 

nondiscriminatory evaluation process proposed in their compliance filings. Additionally, 

Commission review and approval of a not unduly discriminatory evaluation process will 

address Transmission Access Policy Study Group’s concern that Order No. 1000’s 

regional transmission planning reforms may empower public utility transmission 

providers at the expense of other stakeholders, as well as its concern that the regional 

transmission planning governance process should be fair and not unduly discriminatory 

for all participants, including transmission dependent utilities. 

269. PPL Companies assumes that a region will have formal voting rules and structures 

to carry out these evaluations and decide which proposed new transmission facilities are 

in the regional transmission plan and selected for cost allocation, and it requests that we 

review the voting rules and structures of each region’s transmission planning process to 

ensure that they do not disadvantage smaller utilities. While Order No. 1000 does not 

necessarily require formal voting rules, we will review any rules submitted to ensure that 

 317 See id. at section III.B.3.
Docket No. RM10-23-001 -203-

they are fair to all participants. More important, we believe that adherence to the seven 

Order No. 890 transmission planning principles, as adopted in Order No. 1000, will 

ensure fair treatment of all regional planning participants, and we will review the process 

in every compliance filing, whether or not it has formal voting rules and stakeholder 

governance structure, for compliance with the transmission planning principles for (1) 

coordination, (2) openness, (3) transparency, (4) information exchange, (5) 

comparability, (6) dispute resolution, and (7) economic planning. If public utility 

transmission providers in a transmission planning region, in consultation with 

stakeholders, decide to establish formal stakeholder governance procedures, such as 

voting measures, they should include these in their Order No. 1000 compliance filings. 

270. We agree with PPL Companies that RTO membership is and remains voluntary. 

However, regional transmission planning under Order No. 1000 is not voluntary for 

public utility transmission providers.318 We disagree that by mandating a regional 

transmission planning process we are forcing utilities in non-RTO areas to join an RTOlike organization. The transmission planning function of Order No. 1000 is but one of 

nine essential characteristics and functions of an RTO under Order No. 2000, which 

include having an independent grid operator for the entire region, among other operating 

 318 We address PPL Companies’ legal arguments regarding mandatory 

transmission planning requirements above. See discussion supra at section III.A.1.
Docket No. RM10-23-001 -204-

functions. Here, Order No. 1000’s transmission planning requirements involve the 

consideration of whether more efficient or cost-effective alternatives to solutions 

identified in individual local transmission plans exist and whether they will be selected in 

a regional transmission plan for purposes of cost allocation. As discussed in Order No. 

1000 and here, we find that such transmission planning activities are wholly within the 

Commission’s statutory authority, and that such reforms are necessary to implement at 

this time.

271. In response to Transmission Dependent Utility Systems, we do not believe that it 

is necessary that we require that the regional transmission planning process and 

interregional transmission coordination procedures specifically address loop flows. We 

believe that such concerns will necessarily be evaluated by the public utility transmission 

providers in the regional transmission planning process as they plan for the region’s 

reliability and economic needs, as well as the transmission needs driven by Public Policy 

Requirements. Likewise, if loop flow affects more than one transmission planning 

region, these issues may be addressed as part of Order No. 1000’s interregional 

transmission coordination.

272. With respect to questions from some petitioners concerning transmission planning 

regions,319 we affirm Order No. 1000’s determination that “the scope of a transmission 

 319 See, e.g., PPL Companies; MISO Northeast; and Energy Future Coalition 

(continued...)
Docket No. RM10-23-001 -205-

planning region should be governed by the integrated nature of the regional power grid 

and the particular reliability and resource issues affecting individual regions.”320 We also 

affirm Order No. 1000’s determination that the Commission will not prescribe the size or 

scope of a transmission planning region in a generic proceeding except to provide that a 

single public utility transmission provider by itself may not be a transmission planning 

region, consistent with Order No. 890.321 We find that Order No. 1000 appropriately 

provided flexibility in this regard, and that this flexibility will permit public utility 

transmission providers and others the opportunity to form or join a transmission planning 

region that best meets their needs and the needs of their transmission customers. 

273. In response to Southern Companies and Ad Hoc Coalition of Southeastern 

Utilities, we reiterate that public utility transmission providers may look to the 

transmission planning regions that were accepted by the Commission in the Order No. 

890 compliance phase in forming a transmission planning region for purposes of Order 

No. 1000. 

274. We appreciate petitioners’ concerns about Order No. 1000’s expectations 

regarding the participation of non-public utility transmission providers in the regional 

 

Group.

320 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 160 (citing Order No. 890, 

FERC Stats. & Regs. ¶ 31,241 at P 527).

321 Id.
Docket No. RM10-23-001 -206-

transmission planning process. After reviewing the requests for rehearing and 

clarification on this topic, we provide additional clarifications to the discussion in Order 

No. 1000 regarding the participation of non-public utility transmission providers in the 

regional transmission planning process. 

275. As discussed more fully below, public utility transmission providers in each 

transmission planning region must have a clear enrollment process that defines how 

entities, including non-public utility transmission providers, make the choice to become 

part of the transmission planning region.322 In addition, each public utility transmission 

provider (or regional transmission planning entity acting for all of the public utility 

transmission providers in its transmission planning region) must include in its OATT a 

list of all the public utility and non-public utility transmission providers that have 

enrolled as transmission providers in its transmission planning region. A non-public 

utility transmission provider that makes the choice to become part of a transmission 

planning region by enrolling in that region would be subject to the regional and 

 322 While Order No. 1000 did not address issues relating to stakeholder 

procedures, we note that those that make the choice to become part of a transmission 

planning region could be provided with voting rights upon enrollment if the regional 

transmission planning process has a voting mechanism for selecting transmission projects 

in the regional transmission plan for purposes of cost allocation. See, e.g., Order No. 

890-A, FERC Stats. & Regs. ¶ 31,261 at P 252 (stating that “[w]ithin an RTO or ISO,

stakeholder processes can be used to determine whether to pursue either economic or 

reliability upgrades and, thus, voting mechanisms such as those suggested by PSEG could 

be adopted if stakeholders desire.”).
Docket No. RM10-23-001 -207-

interregional cost allocation methods for that region.323 Any non-public utility 

transmission providers that do not make the choice to become part of the transmission 

planning region will nevertheless be permitted to act as stakeholders in the regional 

transmission planning process.324 In sum, we believe that the requirement to have a clear 

enrollment process for transmission providers in a transmission planning region, 

including non-public utility transmission providers that make the choice to join that 

region, along with the maintenance of a list of such enrollees, provides certainty 

regarding who is enrolled in a region and therefore who is a potential beneficiary that 

may be allocated costs. 

276. In response to petitioners such as MEAG Power, we clarify that participation in 

the development of the regional transmission planning process and regional cost 

allocation method that a public utility transmission provider will submit to the 

Commission to comply with Order No. 1000 does not obligate a non-public utility 

transmission provider to choose to join the transmission planning region by enrolling and 

 323 We note that many of the issues raised by petitioners that are addressed in this 

part of the order also implicate reciprocity issues. Requests for rehearing and 

clarification regarding Order No. 1000’s conclusions regarding reciprocity are addressed 

in section V.B, infra.

324 The term “stakeholder” is intended to include any party interested in the 

regional transmission planning process. See Order No. 1000, FERC Stats. & Regs. ¶ 

31,323 at n.143. 
Docket No. RM10-23-001 -208-

thus be eligible to be allocated costs under its regional cost allocation method. As such, a 

non-public utility transmission provider will not be considered to have made the choice to 

join a transmission planning region and thus eligible for cost allocation until it has 

enrolled in the transmission planning region. However, the regional transmission 

planning process is not required to plan for the transmission needs of such a non-public 

utility transmission provider that has not made the choice to join a transmission planning 

region. If the non-public utility transmission provider is a customer of a public utility 

transmission provider in the region, that public utility transmission provider must plan for 

that customer’s needs as it would for the needs of any customer. That non-public utility 

transmission provider’s ability to participate as a stakeholder in the regional transmission 

planning process should be the same as for any other similarly situated stakeholder 

customer.

277. While we acknowledge concerns raised by petitioners such as MEAG Power and 

Large Public Power Council about how non-public utility transmission providers make 

the choice to join a transmission planning region, we conclude that these concerns are 

best addressed in the first instance through participation in the development of the 

regional transmission planning process and cost allocation method that its neighboring 

public utility transmission provider(s) will rely on to comply with Order No. 1000. Each 

non-public utility transmission provider may decide whether or not to enroll in the region 

as a transmission provider as such development nears completion. Participation in the 
Docket No. RM10-23-001 -209-

development of regional processes will not in itself make the participant subject to 

regional cost, absent enrollment. We encourage MEAG Power and other non-public 

utility transmission providers to raise their concerns with all participants in the 

development of the regional transmission planning process and cost allocation method as 

they are developing the compliance filings.325 If non-public utility transmission 

providers believe that their concerns have not been adequately addressed, they may raise 

their concerns when the neighboring public utility transmission providers in the region 

submit their compliance filing to the Commission. 

278. We decline to adopt Large Public Power Council’s suggestion that there either be 

voting mechanisms in place or allow non-public utility transmission providers to 

participate in all aspects of regional transmission planning without being allocated costs 

pursuant to the regional cost allocation method. The enrollment process that we are 

requiring here should address these concerns in part. Additionally, as noted above, nonpublic utilities—including non-public utility transmission providers that also are loadserving entities or have other stakeholder interest in the regional transmission system—

can still participate as stakeholders in the regional transmission planning process, even if 

 325 See, e.g., Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 117 (“[N]onjurisdictional entities, unlike public utilities, may choose to join a regional transmission 

planning process and, to the extent they choose to do so, they may advocate for those 

processes to accommodate their unique limitations and requirements.”).
Docket No. RM10-23-001 -210-

they do not enroll in the regional transmission planning process. As stakeholders, nonpublic utility transmission providers will have an opportunity to express their views and 

concerns as part of the process. 

279. We clarify for Bonneville Power that the Commission in Order No. 1000 did not 

require it, or any other non-public utility transmission provider, to enroll or otherwise 

participate in a regional transmission planning process. As discussed above, it will be 

Bonneville Power’s decision whether or not to enroll as a transmission provider in a 

transmission planning region and become subject to that region’s cost allocation method. 

Additionally, with respect to Bonneville Power’s concerns regarding its perceived 

conflict between its statutory authorities and Order No. 1000’s cost allocation 

requirements, we believe that any such perceived conflict is best addressed in the first 

instance through participation in the development of the regional transmission planning 

process and cost allocation method that its neighboring public utilities will rely on to 

comply with Order No. 1000.

280. We reaffirm Order No. 1000’s statement that many public utility transmission 

providers may need to make only modest changes to their regional transmission planning 

processes to comply with Order No. 1000.326 Thus, if public utility transmission 

 326 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at n.142 (“[E]xisting regional 

transmission planning processes that many utilities relied upon to comply with the 

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

(continued...)
Docket No. RM10-23-001 -211-

providers believe that the regional transmission planning process in which they 

participate already complies with the Order No. 890 transmission planning principles, 

such as Ad Hoc Coalition of Southeastern Utilities’ statement that existing regional 

processes in the Southeast are in compliance with the data exchange transmission 

planning principle, they should make the case for such assertions in their Order No. 1000 

compliance filings.

281. In response to Transmission Dependent Utility Systems, we reiterate our 

determination in Order No. 890 that public utility transmission providers should provide 

sufficient information to “enable customers, other stakeholders, or an independent third 

party to replicate the results of planning studies and thereby reduce the incidence of afterthe-fact disputes regarding whether planning has been conducted in an unduly 

discriminatory fashion.”327 Thus, as we stated in Order No. 890 and subsequent orders 

on compliance, public utility transmission providers should provide the basic 

methodology, criteria, and processes used to develop transmission plans sufficient for 

stakeholders to be able to replicate its transmission plans, and describe the methods it will 

use to disclose the criteria, data, and assumptions that underlie its transmission system 

plans. The information should be of sufficient detail to allow a customer to replicate the 

 

these Final Rule requirements.”).

327 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 471.
Docket No. RM10-23-001 -212-

results of the planning studies.328 Additionally, in discussing the openness principle in 

Order No. 890, the Commission required that “transmission providers, in consultation 

with affected parties, develop mechanisms, such as confidentiality agreements and 

password-protected access to information, in order to manage confidentiality and CEII 

concerns.”329 Subject to our review of public utility transmission providers’ compliance 

filings, we believe that these basic requirements should permit stakeholders to access and 

review information that is relevant to transmission planning, while at the same time 

protecting information that is commercially sensitive or that is otherwise considered 

confidential under Commission regulations.330 

 328 Id.

329 Id. P 460.

330 The Commission has addressed the issue of access to confidential material in 

Order No. 890 compliance proceedings. In Entergy Services, Inc., 130 FERC ¶ 61,264, 

at PP 55-57 (2010), for example, the Commission accepted compliance revisions 

proposed by the Entergy Services, Inc. (Entergy) that would permit stakeholders to be 

certified to obtain CEII material by following certain procedures located on Entergy’s 

website and the SIRPP website. Further, the Commission accepted revisions that allowed 

stakeholders to have access to resource-specific information if it was provided in the 

SIRPP and was needed to participate in the SIRPP or to replicate interregional studies. 

The Commission also found acceptable provisions regarding processing requests for CEII 

data. The Commission found that while Entergy and transmission owners had broad 

discretion over this process, as some protestors argued, that discretion was not unbounded 

because Entergy, its Independent Coordinator of Transmission, and transmission owners 

would develop procedures to review requests for access to CEII data, and protestors 

could thus raise concerns during that development process. The Commission noted that 

any party denied access to information could raise objections through the dispute 

(continued...)
Docket No. RM10-23-001 -213-

282. Regarding Transmission Dependent Utility Systems’ request that the Commission 

confirm that information disclosure will not be deemed a violation of the Standards of 

Conduct, we reiterate our determinations on the transparency principle in Order No. 890, 

where we addressed similar concerns about the Standards of Conduct. There, we stated 

that the “simultaneous disclosure of transmission planning information can 

alleviate...Standards of Conduct concerns.”331 Further, Order No. 890 stated that 

“transmission providers should make as much transmission planning information publicly 

available as possible, consistent with protecting the confidentiality of customer 

information,” noting that it will be necessary for market participants “to have access to 

basic transmission planning information” to consider future resource options.332 These 

principles apply to the Order No. 1000 regional transmission planning process. To the 

extent that an interested party believes that necessary information is being unreasonably 

withheld for unduly discriminatory purposes, we will review on a case-by-case basis.

283. With respect to questions about Order No. 1000’s discussion as to whether public 

utility transmission providers can use flexible criteria or bright-line metrics when 

determining which transmission facilities are in the regional transmission plan, we affirm 

 

resolution process. 

331 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 476 & n.270.

332 Id. P 476.
Docket No. RM10-23-001 -214-

that public utility transmission providers, in consultation with stakeholders, may apply 

either flexible criteria or bright-line metrics. As we explained in Order No. 1000, the 

comments in the record indicated that flexible criteria may be more appropriate than the 

bright-line metrics we had previously required in one earlier decision. 333 We leave it to 

public utility transmission providers, in consultation with stakeholders, in each 

transmission planning region to determine what type of criteria they will use, consistent 

with Order No. 1000’s overarching goal of providing flexibility to meet regional needs. 

Thus, we clarify that we were not necessarily endorsing flexible criteria over bright-line 

criteria. 

284. However, we reject PSEG Companies’ argument that, by making this decision, the 

Commission will introduce opaqueness and confusion into the transmission planning 

process and that it will allow public utility transmission providers to unofficially 

represent policymaking bodies. We continue to find that there is merit in using a flexible 

approach because it may capture certain transmission projects that might be unnecessarily 

excluded with a bright-line approach. We believe that this approach is reasonable, 

particularly in light of the many comments that were supportive of a flexible approach. 

And, again, we are not mandating such an approach, and proponents of bright-line 

 333 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 223 (citing PJM 

Interconnection, L.L.C., 119 FERC ¶ 61,265 (2007)).
Docket No. RM10-23-001 -215-

metrics can advocate for use of those metrics during the compliance process. We also 

find PSEG Companies’ argument that this approach would allow public utility 

transmission providers to unofficially represent policymaking bodies to be speculative 

and unsupported. We therefore reject that argument. However, if PSEG Companies 

believe that, in a specific case, that is the case, it may file a complaint under section 206.

285. In response to Illinois Commerce Commission, we decline to establish a generic 

requirement in Order No. 1000 for the filing of regional transmission plans with the 

Commission. We believe doing so is unnecessary given the requirements of Order No. 

1000, which requires public utility transmission providers to participate in a regional 

transmission planning process that produces a regional transmission plan and complies 

with Order No. 890 transmission planning principles.334 We will evaluate compliance 

filings to ensure that public utility transmission providers satisfy these requirements, but 

we do not see a need to mandate the additional requirement of filing regional 

transmission plans that result from the regional transmission planning process. Our 

concern is with ensuring that there is an open and transparent regional transmission 

planning process. We are not dictating substantive outcomes of that process.335 

 334 Id. P 146.

335 Id. P 113.
Docket No. RM10-23-001 -216-

286. Similarly, we do not require under Order No. 1000 that public utility transmission 

providers file with the Commission associated cost allocation determinations. Again, we

believe that this is unnecessary under Order No. 1000. There, the Commission required 

public utility transmission providers to have an ex ante cost allocation method on file 

with and approved by the Commission.336 This cost allocation method is required to 

explain how the costs of new transmission facilities selected in a regional transmission 

plan for purposes of cost allocation are to be allocated, consistent with the cost allocation 

principles set forth in Order No. 1000. Customers, stakeholders, and others have “notice” 

at the time the compliance filings are made, when the Commission acts on those filings, 

and as the open and transparent regional transmission planning process results in the 

selection of a transmission facility in the regional transmission plan for purposes of cost 

allocation. However, consistent with the regional flexibility provided in Order No. 1000, 

public utility transmission providers, in consultation with stakeholders, may propose 

OATT revisions requiring the submission of cost allocations in their Order No. 1000 

compliance filings.

287. Moreover, we disagree with Illinois Commerce Commission that the Commission 

is delegating authority to public utility transmission providers. As discussed above, the 

Commission will evaluate compliance filings to ensure that they comply with Order No. 

 336 Id. PP 499-500.
Docket No. RM10-23-001 -217-

1000 and both stakeholders and the Commission have the right to initiate actions under 

section 206 of the FPA if they believe that, for example, a Commission-approved 

regional transmission planning process was not followed or if a cost allocation method 

was not followed or produced unjust and unreasonable results for a particular new 

transmission facility or class of new transmission facilities. 

288. We deny Transmission Access Policy Study Group’s request for a post-plan 

process to ensure transmission facilities are actually constructed. As we explained in 

Order No. 1000, the package of transmission planning and cost allocation reforms 

adopted is designed to increase the likelihood that transmission facilities in regional 

transmission plans will move from the planning stage to construction. Additionally, as 

acknowledged by Transmission Access Policy Study Group, a public utility transmission 

provider already is required to make available information regarding the status of 

transmission upgrades identified in transmission plans, including posting appropriate 

status information on its website.337 To the extent that an entity has undertaken a 

commitment to build a transmission facility in a regional transmission plan, that 

information should be included in such a posting.338 We continue to believe that this 

 337 Id. P 159 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 472).

338 Id. P 159 & n.155.
Docket No. RM10-23-001 -218-

obligation, together with the other reforms found in Order No. 1000, is adequate without 

placing further obligations on public utility transmission providers. 

289. Moreover, we are providing public utility transmission providers, in consultation 

with stakeholders, the flexibility to design a regional transmission planning process that 

meets regional needs. As part of the stakeholder process to develop the regional 

transmission planning processes in compliance with Order No. 1000, concerned 

stakeholders have the ability to participate and seek changes to those individual 

processes, subject to Commission review on compliance. Additionally, we decline to 

prescribe specific timing parameters for the website posting requirement that we directed 

in Order No. 1000.339 Again, if stakeholders would like to see such timing requirements 

as part of the website postings, they may seek to do so as part of the compliance process. 

However, the website postings should provide the information we require in a complete 

and transparent manner so that it will be fully accessible and useful to interested 

stakeholders such that they can see the status of various transmission facilities included in 

the regional transmission plan. 

290. Regarding concerns about the role of state utility regulators in the regional 

transmission planning process, we support states’ efforts to take an active role in the 

regional transmission planning process and encourage proposals that seek to establish a 

 339 Id. P 159.
Docket No. RM10-23-001 -219-

formal role for state commissions in the regional transmission planning process as well as 

proposals to establish cost recovery for state regulators’ participation. However, for the 

reasons noted below, we will not require one formal method for how states will 

participate in the process. 

291. We recognize that state utility regulators play an important and unique role in 

transmission planning processes, given that the states often have authority over 

transmission, permitting, siting, and construction, and that many state regulatory 

commissions require utilities to engage in integrated resource planning. We also expect 

that state utility regulators will play an active role in working with public utility 

transmission providers and other stakeholders in the Order No. 1000-compliant regional 

transmission planning processes.

292. That being said, the Commission finds that it would be premature in a generic 

proceeding to mandate any particular role for state regulators in regional transmission 

planning processes. Instead, we believe the best place for a state to determine the role it 

is to play is in the Order No. 1000 compliance process that will develop a regional 

transmission planning process that will be filed for Commission review. This is 

appropriate because individual states can be the best advocates for the role they wish to 

take in that process. For example, in large, multistate regions, states may seek to join a 

committee of state regulators that, in their view, may be a more effective vehicle for 

collective action than any single state could do individually. On the other hand, some 
Docket No. RM10-23-001 -220-

states may feel that its best to have a more independent role if, for example, they believe 

that joining a formalized committee of state regulators may dilute their ability to 

participate in the regional transmission planning process. Some states may have a 

stronger interest in transmission planning issues than others. 

293. We understand and appreciate the concerns expressed by NARUC and others that 

Order No. 1000 may appear to lump state utility regulators with all other stakeholders. 

That was not the Commission’s intent. We understand that state regulators play a crucial 

role in transmission planning and that the role of state regulators is unique and distinctly 

different from the roles played by other stakeholders in transmission planning. We agree 

with Wisconsin PSC that the differences between state utility regulators and other 

stakeholders may well lead to a regional transmission planning process to treat state 

utility regulators differently than other stakeholders. However, for the reasons discussed 

next, we decline to adopt the various suggestions made by Wisconsin PSC and others to 

establish the same formal state commission role in every transmission planning region 

through a generic rulemaking proceeding, although all the regions are free to use the 

same formal process for state participation if they choose to do so. With respect to 

Illinois Commerce Commission’s specific concerns about the roles state regulators might 

be allowed to play consistent with state law, we encourage it and other state regulators to 

raise such concerns during the compliance process.
Docket No. RM10-23-001 -221-

294. We are aware of the wide range of views expressed by state utility commissions 

and others, both in rehearing petitions and previously in comments on the Proposed Rule, 

regarding the appropriate role of the states in regional transmission planning. Some state 

commissions argue for a strong role in shaping regional transmission plans, while others 

are concerned that their states’ laws limit their ability to participate in forming plans that 

may come before them in regulatory proceedings. Respecting this range of views the 

Commission believes that each state commission, or the state commissions collectively in 

a region, is in the best position, in the first instance and in consultation with the 

transmission providers subject to their jurisdiction, to define the appropriate role for the 

state commissions in a particular region. This role will take into account the authorities 

and restrictions conferred by their own states’ statutes and their own policy preferences. 

Thus, the Commission believes it would be inappropriate for us to define the role of all 

state commissions in every regional transmission planning process in a single generic 

proceeding, both because a state commission’s authority and responsibility is established 

by its own state’s laws—not by this Commission—and because a one-size-fits-all state 

role would not accommodate the wide range of views expressed by state commissions.

295. Instead, we believe the best place to determine the role any state commission plays 

is through the development of each region’s transmission planning process. This is 

appropriate because individual state commissions can be the best advocates for the role 

they wish and are able to play in that process. We believe that, in a multistate region, the 
Docket No. RM10-23-001 -222-

state commissions may want to establish a committee of state regulators, which may be 

more effective by acting collectively rather than individually. On numerous occasions, 

the Commission has expressed strong support for such regional state committees, and we 

continue to do so here. But we have not prescribed that states act though regional state 

committees. Some state commissions may want an independent role in regional 

transmission planning. Others may believe they lack authority under their states’ laws to 

engage in planning facilities that are outside the state’s borders. Finally, some states may 

have a stronger interest in regional transmission planning issues than others that simply 

have little interest in participating actively.

296. In response to Illinois Commerce Commission and Florida PSC’s concerns 

regarding funding for state regulator participation in the regional transmission planning 

process, we affirm the approach taken in Order No. 1000. This approach adopted Order 

No. 890’s requirement that public utility transmission providers propose a mechanism for 

recovery of planning costs in their compliance filings, including relevant cost recovery 

for state regulators, to the extent requested.340 Accordingly, we encourage public utility 

transmission providers to engage respective state regulators regarding such provisions in 

their compliance filings. 

 340 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 162 (quoting Order No. 

890, FERC Stats. & Regs. ¶ 31,241 at n.339 & P 586).
Docket No. RM10-23-001 -223-

297. With respect to arguments raised by petitioners concerning Order No. 1000’s 

discussion of the role of merchant transmission developers in the regional transmission 

planning process, we deny rehearing. As the Commission found in Order No. 1000, 

because a merchant transmission developer assumes all financial risk for developing and 

constructing its transmission facility, it is unnecessary to require such a developer to 

participate in a regional transmission planning process for purposes of identifying the 

beneficiaries of its transmission facility that would otherwise be the basis for securing 

eligibility to use a regional cost allocation method or methods. However, because a 

merchant developer’s transmission facility may nevertheless have an impact on a region’s 

transmission network, we will continue to require a merchant transmission developer to 

provide adequate information and data, as explained in more detail in Order No. 1000, to 

allow public utility transmission providers in the transmission planning region to assess 

the potential reliability and operational impacts of the merchant transmission developer’s 

proposed transmission facilities on other systems in the region. We will allow public 

utility transmission providers in each transmission planning region, in consultation with 

stakeholders, in the first instance to propose what information would be required. Public 

utility transmission providers should include these requirements in their filings to comply 

with Order No. 1000.341 

 341 Id. P 163.
Docket No. RM10-23-001 -224-

298. In response to APPA and Transmission Dependent Utility Systems, we believe 

that by requiring merchant transmission developers to provide information regarding their 

projects, including information regarding reliability and operational impacts, public 

utility transmission providers and stakeholders will have sufficient information to analyze 

how a merchant transmission facility may impact the transmission planning region. In 

short, we believe that Order No. 1000’s information sharing requirement balances the 

need for public utility transmission providers and stakeholders in transmission planning 

regions to know about the impacts of potential merchant transmission facilities in their 

regions with our view that it is unnecessary to require a specific degree of participation 

by merchant transmission developers in the regional transmission planning process when 

they are not establishing a cost-based rate base to be allocated to other beneficiaries of 

that facility.

299. We disagree with National Rural Electric Coops that we are establishing a 

“special” class of public utilities by requiring merchant transmission developers to 

comply only with an informational requirement, rather than being subject to the full 

panoply of requirements that will be applicable to all other public utility transmission 

providers. However, it should be noted that merchant transmission developers are those 

for which the costs of constructing the proposed transmission facilities will be recovered 

through negotiated rates instead of cost-based rates, so that this fact alone serves to 
Docket No. RM10-23-001 -225-

distinguish them from other developers.342 As noted above, merchant transmission 

developers are not seeking to allocate the costs associated with their merchant 

transmission facilities to other entities. Thus, we affirm our decision in Order No. 1000. 

300. We also decline Transmission Dependent Utility Systems’ request that we clarify 

that merchant transmission developers not participating in the regional transmission 

planning process should be obligated to internalize the costs of any adverse reliability 

effects on the grid posed by its transmission facility or any need for upgrades caused by a 

change in power flows. Every new facility affects the facilities around it, whether it is a 

merchant facility or a cost-based facility, just as the actions of one region may have 

positive or negative affects on a neighboring regions. A generic proceeding on 

internalizing the costs of all new facilities, whether merchant or otherwise, is beyond the 

scope of Order No. 1000, and may not be suited for a blanket determination in any 

generic proceeding as such a determination would likely require an evaluation of the 

specific facts and circumstances of each particular new facility. The Commission 

reiterates, however, that Order No. 1000 provides that a merchant transmission developer 

has to pay for upgrades on neighboring systems.343

 342 Id. P 119.

343 Id. P 165.
Docket No. RM10-23-001 -226-

301. Finally, in response to those petitioners seeking clarification of what constitutes a 

“new” transmission facility, we will affirm the Commission’s approach taken in Order 

No. 1000.344 Order No. 1000 purposely does not define what type of evaluation or 

reevaluation of transmission facilities needs to occur to determine whether a previously 

approved facility may be subject to Order No. 1000. That is because we understand that 

different transmission planning regions may use different processes based on their unique 

needs and characteristics. We intentionally did not prescribe what such an evaluation or 

reevaluation must look like, and we leave it to public utility transmission providers, in 

consultation with stakeholders, to develop proposals addressing this issue as part of their 

Order No. 1000 compliance filings. If a stakeholder believes that these proposals are 

unduly discriminatory or preferential (e.g., they favor incumbent transmission owners to 

the detriment of nonincumbent transmission developers), it should raise these concerns 

during the development of the Order No. 1000 compliance filing and, if it is not 

successful at that stage, it may raise the issue before the Commission after the 

compliance filing is submitted. For these reasons, we decline to provide the clarifications 

requested by Western Independent Transmission Group and LS Power.

3. Consideration of Transmission Needs Driven by Public Policy 

Requirements

 344 Id. P 65.
Docket No. RM10-23-001 -227-

a. Final Rule

302. Order No. 1000 directed public utility transmission providers, in consultation with 

stakeholders, to amend their OATTs to describe procedures that provide for the 

consideration of transmission needs driven by Public Policy Requirements in the local 

and regional transmission planning processes.345 By considering transmission needs 

driven by Public Policy Requirements, the Commission explained that it meant: (1) the 

identification, with stakeholders, of transmission needs driven by Public Policy 

Requirements; and (2) the evaluation of potential solutions, including those proposed by 

stakeholders, to meet those needs.346 The Commission emphasized that it would allow 

local and regional flexibility in designing these procedures.347 Additionally, to ensure 

that requests to include transmission needs are reviewed in a fair and non-discriminatory 

manner, Order No. 1000 required public utility transmission providers to post on their 

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 

 345 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 203.

346 Id. PP 205-11.

347 Id. P 208.
Docket No. RM10-23-001 -228-

transmission needs will not be evaluated.348 The Commission further explained that 

Order No. 1000 did not establish an independent requirement to satisfy such Public 

Policy Requirements such that the failure of a public utility transmission provider to 

comply with a Public Policy Requirement established under state law would constitute a 

violation of its OATT.349

303. The Commission did not require public utility transmission providers to consider 

in the local and regional transmission planning processes any transmission needs that go 

beyond those driven by state or federal laws or regulations or to specify additional public 

policy principles or public policy objectives.350 However, the Commission reiterated and 

clarified that Order No. 1000 does not preclude any public utility transmission provider 

from considering in its transmission planning process transmission needs driven by 

additional public policy objectives not specifically required by state or federal laws or 

regulations.351 

 348 Id. P 209.

349 Id. P 213.

350 Id. P 214.

351 Id. P 216.
Docket No. RM10-23-001 -229-

b. Requests for Rehearing and Clarification

304. Several petitioners filed requests for rehearing and clarification regarding Order 

No. 1000’s requirement that public utility transmission providers include in their OATTs 

language providing for the consideration of transmission needs driven by Public Policy 

Requirements. Some petitioners assert that the Commission has not spelled out with 

sufficient detail what is required of public utility transmission providers.352 ELCON, 

AF&PA, and the Associated Industrial Groups, as well as PSEG Companies, contend that 

Order No. 1000 provides virtually no practical guidance as to how disparate state policies 

are to be reconciled. PSEG Companies also contend that the Commission’s reforms may 

undermine competitive wholesale energy markets by driving market outcomes, 

explaining that predictions about generation additions and retirements that will occur in a 

competitive market are too speculative for a transmission provider to rely upon and, if a 

transmission provider were to make such judgments, then it would be a market maker or 

market influencer. 

305. Ad Hoc Coalition of Southeastern Utilities is concerned that Order No. 1000’s 

public policy planning requirements will be confusing and counterproductive and are 

likely to result in skewed decision-making. Coalition for Fair Transmission Policy 

 352 See, e.g., Coalition for Fair Transmission Policy; ELCON, AF&PA, and the 

Associated Industrial Groups; and PSEG Companies.
Docket No. RM10-23-001 -230-

argues that any construct of benefits associated with public policy-driven transmission 

projects would require speculation and deviate from industry norms that use models to 

project system conditions and dynamics for planning purposes. Long Island Power 

Authority argues that the process for identifying transmission needs driven by Public 

Policy Requirements is incomplete because it is necessary to identify what parties are 

subject to the Public Policy Requirements and whether such parties have a need for a 

transmission solution to meet those requirements.

306. Sacramento Municipal Utility District explains that current transmission planning 

processes take into account state renewable energy goals, adding that, to the extent that 

Public Policy Requirements spur development of new projects that create demand for 

new transmission, such projects would be incorporated into existing planning processes, 

even if those processes do not expressly reference the Public Policy Requirement that 

created the demand. Ad Hoc Coalition of Southeastern Utilities argue that Order No. 

1000 fails to account for the fact that, at least in the Southeast, existing practices take into 

account Public Policy Requirements.

307. A number of petitioners seek rehearing or clarification on several other issues 

related to Order No. 1000’s requirement that local and regional transmission planning 

processes consider transmission needs driven by Public Policy Requirements. APPA, for 

example, seeks clarification that the term “Public Policy Requirements” is intended to 

include duly enacted laws, ordinances, and regulations passed by units of state and local 
Docket No. RM10-23-001 -231-

government regulating public power systems, such as city councils, utility district boards, 

and other governing bodies. MISO Northeast argues that the Commission should limit 

the definition of “Public Policy Requirements” to those requirements that create 

transmission-related benefits. 

308. AEP seeks clarification that transmission providers are required to include 

specific, evaluated solutions to all transmission needs in the transmission plan, explaining 

that it is concerned that transmission providers may simply identify possible solutions to 

needs driven by Public Policy Requirements without including solutions that address 

such needs in an actionable transmission plan. As an example, AEP states that PJM is 

considering the “FYI to Market” approach, where PJM identifies projects that might 

respond to certain public policy needs and lets the market determine, without any PJM 

involvement, which projects are built.

309. Southern Companies contend that Order No. 1000’s requirement that transmission 

needs driven by Public Policy Requirements must be considered in transmission planning 

processes is vague. Specifically, they claim that Order No. 1000’s directive that public 

utility transmission providers post on their websites an explanation of which public 

policy considerations are and are not considered in the transmission planning process is 

impermissibly vague and overbroad. In support, Southern Companies explain that their 

native load has numerous federal and state legal requirements driving their load 

projections.
Docket No. RM10-23-001 -232-

310. American Transmission seeks clarification on issues related to Order No. 1000’s 

direction that the consideration of transmission needs driven by Public Policy 

Requirements applies to local, as well as regional, transmission planning processes. 

American Transmission seeks clarification that it is necessary and appropriate for it to 

amend its local planning process to include provisions for public policy-driven 

transmission projects.353 It explains that it is a transmission-owning member of MISO, 

which has a Commission-approved regional planning process, but that it also has a 

Commission-approved local planning process, through which transmission projects are 

identified and included in the Midwest ISO MTEP process. 

311. While others raise concerns about the reach of Order No. 1000 on this issue, 

AWEA argues that transmission planners should be required to do more than “consider” 

state and federal requirements, stating that the Commission recognized that when a 

transmission provider focuses only on the needs of its franchised or contract-load 

customers, it creates opportunities for undue discrimination. It suggests that the 

Commission require transmission providers to undertake scenario studies to plan and 

direct the build-out of the transmission system for those entities with signed 

interconnection agreements. It also suggests that the Commission require that scenarios 

 353 American Transmission at 8-9 (citing what it terms as an inconsistency 

between paragraph 203 and footnote 185 of Order No. 1000).
Docket No. RM10-23-001 -233-

account for transmission that may be necessary to accommodate individual or multiple 

RPS requirements or other state and federal requirements, and that transmission providers 

then would present these analyses to stakeholders and include recommended projects and 

anticipated costs under each scenario. Otherwise, it seeks clarification regarding the 

following: (1) that transmission providers must actively address public policy 

considerations within their local and regional planning processes; (2) the requirements 

imposed on transmission providers in meeting the requirement to consider public policy 

goals; and (3) that a transmission provider has an independent duty to identify needs, 

rather than being passive if no participant raises any concerns or needs.

312. Some petitioners raise concerns that the requirements will put transmission 

planners into the role of policymakers. Coalition for Fair Transmission Policy argues 

that, under the top-down planning permitted in Order No. 1000, the regional planning 

group would be placed in the position of making decisions that affect how utilities and 

other entities with the responsibility to meet Public Policy Requirements would meet 

those requirements. Coalition for Fair Transmission Policy asserts that Order No. 1000 

thus authorizes submission of regional transmission planning processes that would reduce 

those with public policy obligations and state regulators to mere stakeholders in the 

regional transmission planning process. It argues that, with respect to transmission needs 

driven by Public Policy Requirements, regional transmission plans can be developed only 

through a bottom-up process. PPL Companies argue that requiring Public Policy 
Docket No. RM10-23-001 -234-

Requirements in the transmission planning process could become a justification to unduly 

discriminate against “non-renewable” generation, which would violate the Commission’s 

open access policies. They also assert that, to the extent public utility transmission 

providers are mandated to consider transmission needs driven by Public Policy 

Requirements in local and regional transmission planning processes, the Commission 

should clarify that such considerations need not, and cannot, trump the FPA’s 

requirement that rates be just and reasonable.

313. Transmission Access Policy Study Group raises a similar concern, pointing to 

Order No. 1000’s statement regarding the consideration of public policy goals not 

codified in laws and regulations. Florida PSC argues that provisions allowing 

transmission providers to consider additional public policy objectives not specifically 

required by state or federal laws or regulations should be struck. Instead, Florida PSC 

argues that transmission planning decisions should be based on meeting the policy 

requirements of state and federal law. It also states that it is unclear whether there will be 

enough flexibility to adjust planning decisions to respond to changes in uncodified public 

policies. Transmission Access Policy Study Group believes that allowing public utility 

transmission providers to consider such goals would allow them to substitute their own 

agenda for that of state and federal legislatures and regulators. 

314. Transmission Access Policy Study Group raises the example that a public utility 

transmission provider’s definition of a “public policy” may be influenced by the potential 
Docket No. RM10-23-001 -235-

for incentive rate recovery or that it may define “public policy” to advance its own 

generation interests. It claims that, despite Order No. 1000’s statement that public utility 

transmission providers always had the ability to plan for any transmission system needs 

that it foresees, public utility transmission providers in non-RTO regions have never 

before been authorized to allocate costs for transmission projects aimed at policy 

objectives not grounded in law or regulation.354 It argues that planning for these goals 

should be grounded in terms of satisfying needs identified by load-serving entities, and 

requests that the Commission at least provide guidance that any plans developed based on 

public utility transmission providers’ own public policy vision should be structured to 

ensure their usefulness by supporting multiple likely power supply scenarios should the 

original vision prove faulty. It believes this approach is more rational for integrating 

public policies into the planning process and will help focus planning on constructing 

broadly supported upgrades needed under multiple potential power supply and public 

policy scenarios.355 

 354 Transmission Access Policy Study Group also cites to Order No. 1000’s 

reference to PJM’s inability to go beyond specific interconnection requests in its planning 

mechanism as a reason for requiring the consideration of transmission needs driven by 

Public Policy Requirements, claiming that this shows that the authorization to go beyond 

public policies embodied in state or federal laws or regulations may not be the status quo

in some RTO regions. 

355 Transmission Access Policy Study Group at 18-19 (citing the CapX 2020 

project, planning processes in MISO and New England, and California ISO’s “least 

(continued...)
Docket No. RM10-23-001 -236-

315. Some state electric regulatory agencies are concerned about the role they will play 

in the process to identify and evaluate transmission needs driven by Public Policy 

Requirements.356 Illinois Commerce Commission asserts that the Commission should 

have clarified that, when state commissions in a region, either acting individually or via 

committee, decide that a unique role or special weight should be given to state authorities 

in the regional planning process regarding the consideration of transmission needs driven 

by Public Policy Requirements, then the transmission provider should be required by the 

Commission to defer to that decision. It maintains that by leaving the role of state 

authorities in the regional planning process up to the transmission providers, the 

Commission allows for the possibility that transmission providers can thwart the will of 

regionally organized state authorities. It also seeks clarification that the “committee of 

regulators” envisioned for the purpose of identifying transmission needs driven by Public 

Policy Requirements would not need to consist solely of personnel employed by state 

regulatory commissions, but could include other state authorities as well. It further seeks 

clarification that the engagement of such a committee will be at the discretion of the 

regional state committee, not at the transmission provider’s discretion. It asks that the 

Commission clarify how its statement that authorizes use of “a committee of state 

 

regrets” planning criteria). 

356 See, e.g., Illinois Commerce Commission; and New York PSC.
Docket No. RM10-23-001 -237-

regulators” to “identify those transmission needs for which potential solutions will be 

evaluated in the transmission planning processes” fits with the requirement that public 

utility transmission providers “have in place processes that provide all stakeholders the

opportunity to provide input into what they believe are transmission needs driven by 

Public Policy Requirements.”

316. Similarly, New York PSC requests clarification that when state regulators play a 

formal role in the planning process, their determinations regarding transmission needs 

driven by state public policies will be entitled to deference.

c. Commission Determination

317. We affirm Order No. 1000’s reforms regarding the consideration of transmission 

needs driven by Public Policy Requirements. We recognize that Order No. 1000 could 

have been more clear regarding what the Commission intended, as evidenced by many of 

the petitioners’ arguments suggesting that Order No. 1000 requires the consideration of 

Public Policy Requirements themselves, which is not the case. In this section, we clarify 

what the Commission intended by these reforms. We believe that these clarifications will 

be helpful in dispelling some of the misconceptions about this requirement that appear in 

many of the petitioners’ requests for rehearing and clarification. 

318. Order No. 1000 requires that public utility transmission providers amend their 

OATTs to provide for the consideration of transmission needs driven by Public Policy 

Requirements. Order No. 1000 did not require that Public Policy Requirements 
Docket No. RM10-23-001 -238-

themselves be considered. This is a critical distinction. As discussed more fully below in 

response to requests for rehearing on this issue, we are not placing public utility 

transmission providers in the position of being policymakers or allowing them to 

substitute their public policy judgments in the place of legislators and regulators. 

Transmission needs driven by Public Policy Requirements, and not the Public Policy 

Requirements themselves, are what must be considered under Order No. 1000.

319. First, we discuss the elements of Order No. 1000’s requirement regarding the 

consideration of transmission needs driven by Public Policy Requirements. Order No. 

1000 defined “Public Policy Requirements” as public policy requirements established by 

state or federal laws and regulations.357 Order No. 1000 explained that “state or federal 

laws and regulations” means “enacted statutes (i.e., passed by the legislature and signed 

by the executive) and regulations promulgated by a relevant jurisdiction, whether within 

a state or at the federal level.”358 We grant APPA’s clarification that Public Policy 

Requirements established by state or federal laws or regulations includes duly enacted 

laws or regulations passed by a local governmental entity, such as a municipal or county 

government. This is the intent of the word “within” in Order No. 1000’s explanation that 

“state or federal laws or regulations,” meant “enacted statutes...and regulations 

 357 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 2.

358 Id.
Docket No. RM10-23-001 -239-

promulgated by a relevant jurisdiction, whether within a state or at the federal level.”359 

In response to MISO Northeast, we will not revise the definition of Public Policy 

Requirements to limit it to those that provide transmission-related benefits. Order No. 

1000 does not require the consideration of Public Policy Requirements: rather, it 

requires the consideration of transmission needs driven by Public Policy Requirements. 

We also will not exclude any particular state or federal law or regulation from the 

definition of Public Policy Requirements. 

320. Next, we discuss another key component of Order No. 1000’s requirement, 

namely, the term “consideration” in reference to the requirement that public utility 

transmission providers amend their OATTs to provide for the consideration of 

transmission needs driven by Public Policy Requirements. By “consideration,” Order 

No. 1000 explained that this included: (1) the identification of transmission needs driven 

by Public Policy Requirements; and (2) the evaluation of potential solutions to meet those 

identified needs.360 Order No. 1000 further explained that, with respect to the 

identification of transmission needs driven by Public Policy Requirements, the process 

must permit stakeholders with an opportunity to provide input and offer proposals 

 359 Id. (emphasis added).

360 Id. P 205.
Docket No. RM10-23-001 -240-

regarding the transmission needs that they believe should be so identified.361 Order No. 

1000 also stated that not every suggested need will be identified such that solutions for 

the need will be evaluated.362 In response to AEP, we reiterate that Order No. 1000 

provides only that public utility transmission providers must consider transmission needs 

driven by Public Policy Requirements. Order No. 1000 does not require that every 

potential transmission need proposed by stakeholders must be selected for further 

evaluation. We find that this approach is a fair balance that allows interested 

stakeholders to submit their views on what is driving their transmission needs while 

allowing the process itself determine what transmission needs are identified for which 

solutions must be evaluated.

321. Similarly, in response to AWEA, we are not requiring anything more than what 

we directed in Order No. 1000, namely, the two-part identification and evaluation 

process. As with other Order No. 1000 transmission planning reforms, our concern is 

that the process allows for stakeholders to submit their views and proposals for 

transmission needs driven by Public Policy Requirements in a process that is open and 

transparent and satisfies all of the transmission planning principles set out in Order Nos. 

890 and 1000, and that there is a record for the Commission and stakeholders to review to 

 361 Id. P 209.

362 Id.
Docket No. RM10-23-001 -241-

help ensure that the identification and evaluation decisions are open and fair, and not 

unduly discriminatory or preferential. However, we reiterate that not every proposal by 

stakeholders during the identification stage will necessarily be identified for further 

evaluation. The OATT revisions that public utility transmission providers submit as part 

of their Order No. 1000 compliance filings will set forth the process for permitting 

stakeholders to provide input and for determining which proposed transmission needs 

will be identified for evaluation.

322. We are also not prescribing how active a public utility transmission provider 

should itself be in identifying transmission needs driven by Public Policy Requirements, 

although it certainly may take a more proactive approach if it, in consultation with its 

stakeholders, so chooses. Even if a public utility transmission provider takes a less active 

approach on this issue, our expectation is that interested stakeholders will participate and 

suggest transmission needs driven by Public Policy Requirements.363 An open and 

transparent transmission planning process will identify those transmission needs that 

should be evaluated, regardless of whether they are suggested by the public utility 

transmission provider or by an interested stakeholder.

 363 We emphasize that, although a public utility transmission provider is not 

obligated to proactively identify transmission needs driven by Public Policy 

Requirements, it still must consider the transmission needs driven by Public Policy 

Requirements raised by other stakeholders in the transmission planning process.
Docket No. RM10-23-001 -242-

323. In response to Coalition for Fair Transmission Policy, we recognize that 

consideration of transmission needs driven by Public Policy Requirements could create 

challenges in defining beneficiaries, but we fail to see how these challenges are 

appreciably different from those involved in determining beneficiaries of reliability or 

economic projects. In those cases as well, the determination of beneficiaries will often

turn on informed forecasts or predictions regarding future needs and demands to be 

placed on the transmission system. In fact, given that the Commission is only requiring 

the consideration of transmission needs driven by Public Policy Requirements that are 

established by state or federal laws or regulations,364 it may very well be the case that the 

determination of beneficiaries of transmission facilities to address transmission needs 

driven by Public Policy Requirements is easier to define than for other types of 

transmission facilities. In any event, we want public utility transmission providers, in 

consultation with stakeholders, to make those determinations in the first instance. We 

also disagree with Coalition for Fair Transmission Policy’s argument that these reforms 

can only be implemented through bottom-up transmission planning. Coalition for Fair 

Transmission Policy has not persuaded us that these reforms cannot be implemented 

through either a “top-down” or “bottom up” process, particularly given the significant 

 364 As discussed above, the Commission clarifies that this requirement was meant 

to include local laws or regulations as well.
Docket No. RM10-23-001 -243-

flexibility we are providing to public utility transmission providers to comply with these 

requirements.

324. Regarding American Transmission’s request for clarification, we note that in 

Order No. 1000, footnote 185, we stated that “[t]o the extent public utility transmission 

providers within a region do not engage in local transmission planning, such as in some 

ISO/RTO regions, the requirements of this Final Rule with regard to Public Policy 

Requirements apply only to the regional transmission planning process.”365 That 

statement only applies to public utility transmission providers that do not engage in local 

transmission planning. If a public utility transmission provider does engage in local 

transmission planning, regardless of whether or not it is in an ISO/RTO region, then the 

requirements of Order No. 1000 regarding Public Policy Requirements apply to both the 

local and regional transmission planning processes. Therefore, if American Transmission 

engages in local and regional transmission planning, then it must revise its local 

transmission planning process to reflect this aspect of Order No. 1000.

325. Southern Companies find the requirement that public utility transmission 

providers post on their websites an explanation of which transmission needs have been 

identified for evaluation and an explanation of why other suggested transmission needs 

will not be evaluated to be vague and overbroad. We clarify as follows. Public utility 

 365 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at n.185.
Docket No. RM10-23-001 -244-

transmission providers are not required to research and post on their websites what they 

perceive to be every transmission need that is conceivably driven by a Public Policy 

Requirement and then explain why it will not evaluate each one. Public utility 

transmission providers are only obligated to (a) post an explanation of those transmission 

needs driven by Public Policy Requirements that have been identified for evaluation and 

(b) post an explanation of how other transmission needs driven by Public Policy 

Requirements introduced by stakeholders were considered during the identification stage 

and why they were not selected for further evaluation. For example, if public utility 

transmission providers or stakeholders in a transmission planning region submit what 

they believe are ten transmission needs driven by Public Policy Requirements, and five of 

those ten are identified for evaluation, then the public utility transmission providers must 

(a) post an explanation of why the five were evaluated and (b) post an explanation of why 

the other five were not evaluated. 

326. Having provided additional clarifications and information as to what Order No. 

1000 does require, i.e., the consideration of transmission needs driven by Public Policy 

Requirements, we now turn to discussing what Order No. 1000 does not require, i.e., the 

consideration of Public Policy Requirements themselves, as well as otherwise allowing 

public utility transmission providers to become policymakers, as some petitioners appear 

to believe. Order No. 1000 does not require public utility transmission providers to 

amend their OATTs to provide for the consideration of Public Policy Requirements. Nor 
Docket No. RM10-23-001 -245-

do we believe that anything in Order No. 1000’s reforms on this issue will lead to that 

outcome. 

327. It is not the function of the transmission planning process to reconcile state 

policies. If the utilities in one state are required, for example, to procure wind resources 

and the utilities in another state are required to shut down old fossil units and construct 

new fossil units, it is not the transmission providers’ function to decide on the merits of 

these federal or state requirements or to decide between wind and coal resources. It is 

their function to help both sets of utilities comply with the laws they each face by 

considering in the transmission planning process, but not necessarily including in the 

regional transmission plan, the new transmission facilities needed by both sets of utilities 

to meet their obligations, and also to determine if these diverse objectives can be met 

more efficiently or cost-effectively through regional transmission planning than through 

individual utility planning.

328. Additionally, in establishing this process, we are not requiring public utility 

transmission providers to make any substantive determinations as to what Public Policy 

Requirements may qualify under these reforms or to identify them in their OATTs. If 

they choose to do so, then such proposals must be vetted through the local and regional 

transmission planning process, as discussed in Order No. 1000. 

329. For these reasons, we reject assertions that we are allowing public utility 

transmission providers to assume the role of policymaker in their transmission planning 
Docket No. RM10-23-001 -246-

processes with respect to considering transmission needs driven by Public Policy 

Requirements. We also disagree with Ad Hoc Coalition of Southeastern Utilities that 

these reforms may lead to skewed decision-making. Our intent is to help develop a path 

to allow public utility transmission providers to consider transmission needs driven by 

Public Policy Requirements, just as they consider reliability-driven and economic-driven 

transmission needs, but we are not mandating that any particular transmission facility 

identified to address identified transmission solutions be built. 

330. Further, we disagree with PSEG Companies’ argument that, by requiring the 

development of a process, we are somehow getting ahead of the states’ own public policy 

efforts. Nothing in the development of this process preempts or conflicts with state-level 

public policy efforts. Indeed, Order No. 1000 and state-level Public Policy Requirements 

should be complementary—Order No. 1000’s intent is to establish a space in the 

transmission planning process to identify transmission needs driven by Public Policy 

Requirements and to evaluate potential solutions to identified needs. 

331. We also decline to require that regional transmission plans support multiple likely 

power supply scenarios should a region’s public policy vision not come to fruition, as 

requested by Transmission Access Policy Study Group. It may well be the case that 

evaluating different power supply scenarios will be an effective way of identifying more 

efficient or cost-effective transmission solutions; however, we will not prescribe any such 

requirements here, consistent with our preference for regional flexibility in designing 
Docket No. RM10-23-001 -247-

regional transmission planning processes. Stakeholders may advocate for such a 

requirement in the development of Order No. 1000 compliance filings and, to the extent 

such language is included in the compliance filing, the Commission will consider that 

language.366 

332. Just as Order No. 1000 did not intend for public utility transmission providers to 

consider Public Policy Requirements, Order No. 1000 also does not convert public utility 

transmission providers into policymakers with respect to the consideration of public 

policy objectives that are not codified in federal or state laws or regulation. On this 

matter, Order No. 1000 stated: “[T]he Final Rule does not preclude any public utility 

transmission provider from considering in its transmission planning process transmission 

needs driven by additional public policy objectives not specifically required by state or 

federal regulations.”367 Some petitioners expressed alarm that we are permitting public 

utility transmission providers to become policymakers and substitute their policy 

judgments in place of legislators and regulators. This was not our intent, and we take this 

opportunity to provide some clarifications on this matter.

 366 Similarly, we will not require the adoption of a “least regrets” process or 

processes that resulted in the development of transmission projects such as the CapX2020 

project; however, the public utility transmission providers in each region are free to 

develop such processes and submit them in their compliance filing for Commission 

consideration.

367 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 216.
Docket No. RM10-23-001 -248-

333. We reiterate the observations we made in Order No. 1000. A public utility 

transmission provider “has, and always had, the ability to plan for any transmission 

system needs that it foresees. Our recognition of this ability is not intended to limit or 

expand in any way the option that a public utility transmission provider has always had to 

plan for facilities that it believes are needed if it chooses to do so.”368 All this statement 

was intended to convey was that, even absent the requirements in Order No. 1000, public 

utility transmission providers take a number of different factors into account in 

developing their transmission plans. While Order No. 1000 established a requirement for 

certain factors that must be considered in transmission planning, as the quoted sentence 

states, it does not expand what public utility transmission providers have always been 

entitled to do. If, for example, a state law that has been identified as a Public Policy 

Requirement requires utilities to meet a 10 percent renewable portfolio standard and that 

state’s governor urges them to meet a 20 percent standard, Order No. 1000 requires 

consideration of transmission needed to meet the 10 percent but neither requires utilities 

to, nor prohibits them from, considering a 20 percent standard, as some petitioners 

apparently urge us to do. 

334. Order No. 1000 concluded that it is appropriate to require public utility 

transmission providers, in consultation with stakeholders, to design the appropriate 

 368 Id. (emphasis added).
Docket No. RM10-23-001 -249-

procedures for identifying and evaluating the transmission needs that are driven by Public 

Policy Requirements in their area, subject to guidance the Commission provided in Order 

No. 1000 and our review on compliance.369 Additionally, in response to Long Island 

Power Authority, we anticipate that the process for identifying transmission needs driven 

by Public Policy Requirements can identify what parties are subject to the Public Policy 

Requirements and whether such parties have a need for a transmission solution to meet 

those requirements. 

335. With respect to the contention raised by Sacramento Municipal Utility District, Ad 

Hoc Coalition of Southeastern Utilities, and others that existing transmission planning 

processes already account for state renewable energy goals, we note that we are not 

endorsing, nor does the Public Policy Requirement include, any particular state or federal 

law or regulation as special or “preferred.” Further, as we have noted elsewhere, we 

understand that some regions may already be in compliance with many of the 

requirements of Order No. 1000 and thus may need to make only modest changes to 

comply. Compliance filers must explain how their process gives all stakeholders a 

meaningful opportunity to submit what they believe are transmission needs driven by 

Public Policy Requirements, and allow an open and transparent transmission planning 

process to determine whether to move forward regarding those needs. 

 369 Id. P 208.
Docket No. RM10-23-001 -250-

336. Further, we disagree that we have not justified this reform generically, as 

suggested by Ad Hoc Coalition of Southeastern Utilities, which argues that there is no 

need for this reform in the Southeast. As discussed above and in Order No. 1000, we 

concluded that there was a need for the Commission to act under FPA section 206 to 

remedy a deficiency that we found in existing transmission planning processes. There 

was no formal requirement for public utility transmission providers to consider 

transmission needs driven by Public Policy Requirements, despite the fact that the record 

indicates that in recent years there has been significant activity at the federal and state 

levels in enacting laws and regulations that will potentially impact transmission needs.370 

The lack of a formal requirement in public utility transmission providers’ OATTs to 

address this issue is, in our view, unjust, unreasonable, and unduly discriminatory.371 We 

affirm our conclusion that these reforms are necessary on a nationwide basis. 

337. Finally, some state regulators question their role in this process. We agree with 

petitioners that state regulators play an important and unique role in the transmission 

planning process, given their oversight over transmission siting, permitting, and 

construction, as well as integrated resource planning and similar processes. Additionally, 

 370 See, e.g., Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 45-47.

371 Id. PP 82-83. See also discussion supra at section II.C (explaining need for 

Order No. 1000’s reforms).
Docket No. RM10-23-001 -251-

they may be in the best position of determining how state-level public policy 

requirements are satisfied. Nonetheless, for the reasons discussed fully above, the 

Commission will not require as part of this generic rulemaking proceeding a particular 

status for state regulators in the transmission planning process.372 To do so would ignore 

the wide range of roles that state regulators themselves tell us that they are permitted to 

take under their various state laws. 

338. However, as we also explained in Order No. 1000 and above, our expectation is 

that state regulators should play a strong role and that public utility transmission 

providers will consult closely with state regulators to ensure that their respective 

transmission planning processes are consistent with state requirements. We believe this 

will be particularly true in the case of state-level Public Policy Requirements, where state 

regulators are likely to have unique insights as to how transmission needs driven by those 

state-level Public Policy Requirements should be satisfied. Thus, we leave it to state 

regulators and public utility transmission providers, in consultation with stakeholders, in 

each transmission planning region to determine the appropriate role of state regulators in 

the transmission planning process generally and in the consideration of transmission 

needs driven by Public Policy Requirements in particular. 

 372 See discussion supra at section III.A.2.
Docket No. RM10-23-001 -252-

339. In response to Illinois Commerce Commission, we are not prescribing how any 

committee of state regulators should be comprised. We note that existing committees of 

state regulators have been effective representatives of state regulators, and any region that 

wants to form such a committee may want to look to these and other similar 

organizations in other regions of the country as possible models for organizing its own 

similar committees for purposes of regional transmission planning under Order No. 1000.

B. Nonincumbent Transmission Developers

340. This section of Order No. 1000 addressed the removal from Commissionjurisdictional tariffs and agreements of provisions that contain a federal right of first 

refusal373 to construct transmission facilities selected in a regional transmission plan for 

purposes of cost allocation. The Commission also adopted a framework that requires the 

development of qualification criteria and protocols to govern the submission and 

evaluation of proposals for transmission facilities to be evaluated by public utility 

transmission providers in the regional transmission planning process. The Commission 

further required that the developer of any transmission facility selected in the regional 

 373 We continue to use the phrase “federal right of first refusal” to refer only to 

rights of first refusal that are created by provisions in Commission-jurisdictional tariffs or 

agreements. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 253 n.231.
Docket No. RM10-23-001 -253-

transmission plan have a comparable opportunity to allocate the cost of such transmission 

facility through a regional cost allocation method or methods.374

1. Legal Authority

a. Final Rule375

341. In Order No. 1000, the Commission found that a federal right of first refusal is, in 

the language of FPA section 206, a “rule, regulation, practice, or contract” affecting the 

rates for jurisdictional transmission service. The Commission further stated that under 

section 206 when the Commission finds that such rules, regulations, practices, or 

contracts are unjust, unreasonable, unduly discriminatory, or preferential, it must 

determine by order the just and reasonable rate, charge, classification, rule, regulation, 

practice, or contract to be thereafter observed and in force. The Commission concluded 

that because federal rights of first refusal in favor of incumbent transmission providers 

deprive customers of the benefits of competition in transmission development, and 

associated potential savings, these federal rights of first refusal affect the rates for 

jurisdictional transmission service, and so the Commission was compelled under FPA 

section 206(a) to take corrective action. The Commission also stated that federal rights 

 374 Id. P 225.

375 We address legal arguments related to the need for our nonincumbent 

transmission developer reforms in the “Need for Reform” discussion. See discussion 

supra at section II.C.
Docket No. RM10-23-001 -254-

of first refusal create opportunities for undue discrimination and preferential treatment 

against nonincumbent transmission developers within existing regional transmission 

planning processes, and noted that it has a responsibility to consider anticompetitive 

practices and eliminate barriers to competition.376

342. The Commission noted that nothing in Order No. 1000 is intended to limit, 

preempt, or otherwise affect state or local laws or regulations with respect to construction 

of transmission facilities, including, but not limited, to authority over siting or permitting 

of transmission facilities. The Commission therefore determined that its reforms 

regarding elimination of federal rights of first refusal from Commission-jurisdictional 

tariffs and agreements are not prevented or otherwise limited by the FPA. The 

Commission also explained that in directing the removal of a federal right of first refusal 

from Commission-jurisdictional tariffs and agreements, it is not ordering public utility 

transmission providers to enlarge their transmission facilities under sections 210 or 211 

of the FPA, nor making findings related to its authorities under section 215 or 216. 

343. The Commission also stated that, while a public utility transmission provider may 

have accepted an obligation to build in relation to its membership in an RTO/ISO, the 

Commission did not believe that obligation is necessarily dependent on the incumbent 

transmission provider having a corresponding federal right of first refusal to prevent 

 376 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 286.
Docket No. RM10-23-001 -255-

others from constructing and owning new transmission facilities in that region.377 The 

Commission stated that, while implementing these reforms may change the package of 

benefits and burdens in place for transmission owning members of RTOs/ISOs, such 

changes are necessary to correct practices that may be leading to unjust and unreasonable 

rates.378

344. Finally, the Commission declined to address the merits of comments arguing that 

section 3.09 of the ISO New England Transmission Operating Agreement establishes a 

federal right of first refusal that can be modified only if the Commission meets the 

Mobile-Sierra public interest standard, explaining that it was more appropriate to address 

this issue as part of the proceeding on ISO New England’s compliance filing.379

b. Requests for Rehearing and Clarification

i. Arguments That the Commission Does Not Have 

the Authority To Eliminate a Federal Right of First 

Refusal

345. Several petitioners argue that the Commission acted outside of its authority by 

requiring the removal of the federal right of first refusal from Commission-jurisdictional 

 377 Id. P 261.

378 Id.

379 Id. P 292.
Docket No. RM10-23-001 -256-

tariffs and agreements.380 Some petitioners assert that section 206 only extends to 

behavior that directly affects rates or the provision of jurisdictional service rather than to 

any term in a jurisdictional tariff or agreement.381 They argue the federal right of first 

refusal is not a practice within the meaning of section 206, and therefore is not a behavior 

that the Commission can address under that section.382 Similarly, Oklahoma Gas and 

Electric Company states that the Commission must show a direct and significant effect on 

jurisdictional rates before it can regulate actions indirectly affecting activity falling under 

state jurisdiction.

346. Petitioners also analogize the Commission’s action in Order No. 1000 with its 

failed attempt to regulate corporate governance and structure, which was at issue in 

CAISO v. FERC.

383 Petitioners argue that the federal right of first refusal affects a 

 380 See, e.g., FirstEnergy Service Company; Baltimore Gas & Electric; Southern 

Companies; Ad Hoc Coalition of Southeastern Utilities; and Sponsoring PJM 

Transmission Owners.

381 See, e.g., FirstEnergy Service Company; Sponsoring PJM Transmission 

Owners; Baltimore Gas & Electric; and Oklahoma Gas and Electric Company.

382 See, e.g., Southern Companies; Sponsoring PJM Transmission Owners ; 

Baltimore Gas & Electric; and Oklahoma Gas and Electric Company.

383 Sponsoring PJM Transmission Owners at 5-6 (citing California Indep. Sys. 

Operator Corp. v. FERC, 372 F.3d 403 (D.C. Cir. 2004) (CAISO v. FERC)); Southern 

Companies at 60-61 (citing CAISO v. FERC, 372 F.3d 395); PSEG Companies; 

Baltimore Gas & Electric (citing CAISO v. FERC, 372 F.3d at 403; City of Cleveland v. 

FERC, 773 F.2d 1368 (D.C. Cir. 1985)); Oklahoma Gas and Electric Company at 9-10 

(CAISO v. FERC, 372 F.3d at 403).
Docket No. RM10-23-001 -257-

transmission provider’s financial relationship with its customers no more than the D.C. 

Circuit found governance to in CAISO v. FERC.

384 According to Baltimore Gas & 

Electric, the court in CAISO v. FERC explained that the Commission cannot regulate 

“practices” using its section 206 ratemaking authority unless the practices “affect rates 

and services significantly...are realistically susceptible of specification, and...are not so 

generally understood in any contractual arrangement as to render recitations 

superfluous.”385 Sponsoring PJM Transmission Owners also note that the CAISO court 

explained that a more expansive interpretation of “practice” would allow the Commission 

to regulate a range of subjects that the court considered to be plainly beyond the 

Commission’s proper authority. Sponsoring PJM Transmission Owners add that, while 

the costs the transmission provider incurs to construct or procure an upgrade will be 

reflected in its rates, the same could be said of a myriad of other decisions the 

transmission provider makes, ranging from its hiring of staff to the procurement of 

outside services and materials. Southern Companies also analogize Order No. 1000 to 

CAISO v. FERC, arguing that the Commission, without evidence or a record of systemic 

abuse or actual discrimination or unreasonable decision making, is using sections 205 and 

 384 Southern Companies at 60-61 (citing CAISO v. FERC, 372 F.3d 395); 

Sponsoring PJM Transmission Owners at 7 (citing CAISO v. FERC, 372 F.3d at 403 

(quoting Mich. Wisc. Pipeline Co., 34 FPC ¶ 621,626 (1965))).

385 Baltimore Gas & Electric at 12 (quoting CAISO v. FERC, 372 F.3d at 403).
Docket No. RM10-23-001 -258-

206 and a theoretical threat of unjust and unreasonable rates or discrimination in the 

provision of transmission service to replace the existing business investment decision 

process with its own.386

347. Sponsoring PJM Transmission Owners also point out that the court in CAISO v. 

FERC found that section 305 of the FPA, giving the Commission authority over 

interlocking directorates, would not have been necessary if it intended that the 

Commission could regulate corporate governance as a practice affecting rates under 

sections 205 and 206 of the FPA. They contend that this same reasoning leads to the 

conclusion that section 206 does not encompass the assignment of construction 

responsibility. Sponsoring PJM Transmission Owners argue that this is clear in looking 

at the relationship of section 7 of the NGA to sections 4 and 5 of the NGA, which parallel 

sections 205 and 206 of the FPA. They assert that section 7 of the NGA, giving the 

Commission the authority to regulate pipeline construction, would not have been 

necessary if sections 4 and 5 of the NGA (which parallel sections 205 and 206 of the 

FPA) already allowed the Commission to regulate such construction.387 In addition, 

 386 Southern Companies at 103-104 (citing CAISO v. FERC, 372 F.2d at 395). 

387 Sponsoring PJM Transmission Owners. Similarly, Sponsoring PJM 

Transmission Owners assert that section 402 of the Transportation Act of 1920 

(superseded by 49 U.S.C. 10901 (2010)), which provided the Interstate Commerce 

Commission with approval authority for railway extensions, would not have been 

necessary if practices affecting rates included construction decisions. 
Docket No. RM10-23-001 -259-

Sponsoring PJM Transmission Owners state that it is significant that, when deliberating 

on the FPA, Congress rejected provisions that would have given the Commission 

authority to order a utility to fix the services, equipment, or facilities it is responsible for 

maintaining upon determining they were improperly maintained.388

348. Sponsoring PJM Transmission Owners also analogize the right of first refusal to 

Interstate Commerce Commission v. Pennsylvania.

389 They contend that the court in 

CAISO v. FERC looked to this case because the court in Interstate Commerce 

Commission v. Pennsylvania interpreted the Interstate Commerce Act upon which Part II 

of the FPA is based and which likewise authorized the regulation of practices affecting 

rates.390 Sponsoring PJM Transmission Owners assert the court in Interstate Commerce 

Commission v. Pennsylvania made clear that it was manifestly concerned about practices 

 388 Sponsoring PJM Transmission Owners at 11 (citing Duke Power Co. v. Fed. 

Power Comm’n, 401 F.2d 930, 943 n.106 (D.C. Cir. 1968)). They add that, although the 

statutory interpretations of later Congresses is not determinative of the statutory intent of 

an earlier Congress, it is informative that when Congress granted backstop siting 

authority to the Commission in the Energy Policy Act of 2005, it established clear limits 

that constrain the exercise of that authority. Id. (citing 16 U.S.C. 824p (2010); Piedmont 

Envtl. Council v. FERC, 558 F.3d 304 (4th Cir. 2009). They also state that section 1211 

of the EPAct 2005 expressly states that the new electric reliability provisions do not 

authorize the Commission to order the construction of additional transmission facilities. 

Id. (referencing 16 U.S.C. 824o(i)(2)).

389 Sponsoring PJM Transmission Owners at 9-10 (citing Interstate Commerce 

Commission v. Pennsylvania, 242 U.S. 208 (1916) (ICC v. Pennsylvania)).

390 Sponsoring PJM Transmission Owners at 9-10 (citing ICC v. Pennsylvania, 

242 U.S. 208)).
Docket No. RM10-23-001 -260-

that directly related to the jurisdictional service provided customers (which was rail 

service), rather than the railroads’ decisions regarding the means to provide such 

service.391 

349. Instead of finding that any rate is unjust and unreasonable, Baltimore Gas & 

Electric argues that the Commission states that there may be a superior alternative 

practice to the present federal right of first refusal regime. Baltimore Gas & Electric 

asserts that this is contrary to well-settled law, which requires that if the existing method 

is just and reasonable, then that is the end of the section 206 inquiry even if an alternative 

method may be better.392 Baltimore Gas & Electric asserts that the Commission violated 

this ratemaking precept by conflating its consideration of the federal right of first refusal 

mechanism for designating new transmission construction and operation responsibility 

with its consideration of an alternative selection process that the Commission prefers. 

350. PSEG Companies assert that elimination of the federal right of first refusal was 

arbitrary and capricious because the “remedy” far exceeded the purported harm. 

Similarly, Baltimore Gas & Electric asserts that proportionality between the identified 

 391 Sponsoring PJM Transmission Owners at 9-10 & n.20 (citing ICC v. 

Pennsylvania, 242 U.S. 208; Duncan v. Walker, 533 U.S. 167, 174 (2001)).

392 Baltimore Gas & Electric at 10-11 (citing Complex Consol. Edison Co. of N.Y. 

v. FERC, 165 F.3d 992, 1003 (D.C. Cir. 1999); Pub. Serv. Comm’n of N.Y. v. FERC, 642 

F.2d 1335 (D.C. Cir. 1980) cert. denied, 454 U.S. 879 (1981); Kern River Gas 

Transmission Co., Opinion No. 486-E, 136 FERC ¶ 61,045 (2011)).
Docket No. RM10-23-001 -261-

problem and the remedy “is the key,” and that if the Commission found isolated 

problems, a market-wide remedy would be inappropriate.393 Similarly, Baltimore Gas & 

Electric asserts that the Commission must adduce hard facts, and that the remedy should 

be narrowly tailored to fit the facts.

351. With regard to the Commission’s determination that the existence of a federal 

right of first refusal creates an opportunity for undue discrimination and preferential 

treatment against nonincumbent transmission developers, several petitioners argue that 

the Commission cannot rely on the FPA’s undue discrimination provisions in sections 

205 and 206 because these provisions only protect customers of public utilities, and not 

nonincumbent transmission developers.394 They argue that had Congress intended to 

 393 PSEG Companies at 33 (quoting Public Utils. Comm’n of the State of Cal. v. 

FERC, 462 F.3d 1027, 1054 (9th Cir. 2006)).

394 See, e.g., Southern Companies at 62 (citing Pub. Serv. Co. of Ind., Inc. v. 

FERC, 575 F.2d 1204, 1213 (7th Cir. 1978); see St. Michaels Util. Comm’n v. FPC, 377 

f.2d 912, 915 (4th Cir. 1967)); Sponsoring PJM Transmission Owners at 12 (citing Maine 

Pub. Serv. Co. v. FPC, 579 F.2d 659, 664 (1st Cir. 1978)); see also, e.g., FPC v. Sierra 

Pacific Power Co., 350 U.S. 348, 355 (1956); Mun. Light Bds. v. FPC, 450 F.2d 1341, 

1348 (D.C. Cir. 1971); Baltimore Gas & Electric; Large Public Power Council; Ad Hoc 

Coalition of Southeastern Utilities at 59 (citing Pub. Serv. Co. of Ind.. v. FERC, 575 F.2d 

1203, 1213 (7th Cir. 1978); St. Michaels util. Comm’n v. FPC, 377 F.2d 912, 915 (4th Cir. 

1967); City of Frankfort, Ind. v. FERC, 678 F.2d 699, 707 (7th Cir. 1982) (Frankfort v. 

FERC); Towns of Alexandria, Minn. V. FPC, 555 F.2d 1020, 1028 (D.C. Cir. 1977)); 

Oklahoma Gas and Electric Company at 7-8 (citing St. Michaels Util. Comm’n v. FPC, 

377 F.2d at 915; Pub. Serv. Co. of Ind., Inc. v. FERC, 575 F.2d at 1212 (stating that the 

intent of the statute’s undue discrimination protections “is to protect consumers from 

being placed at a competitive disadvantage with other [similar customers]”); Frankfort v. 

(continued...)
Docket No. RM10-23-001 -262-

grant the Commission such authority, it would have done so.395 Large Public Power 

Council and Ad Hoc Coalition of Southeastern Utilities note that the court, in the City of 

Frankfort, stated that section 205 provisions “regarding unlawful preference or advantage 

in setting of public utility rates requires that utility customers be treated fairly.”396 They 

also cite Public Service Co. of Ind. where the court stated that “the anti-discrimination 

policy in section 205(b) is violated ... where one consumer has its rates raised 

significantly above what other similarly-situated customers are paying.”397 Oklahoma 

Gas & Electric Company contends that neither of the cases the Commission cites support 

a different conclusion, claiming that, in Gulf States, the Commission addressed the 

narrow question of whether public utilities could “employ tariff provisions to foreclose 

wholesale competition,”398 and that in Otter Tail, the Supreme Court held that the FPA 

 

FERC, 678 F.2d at 707 ; Towns of Alexandria, Minn. v. FPC, 555 F.2d 1020, 1028 (D.C. 

Cir. 1977)).

395 Oklahoma Gas & Electric at 6 (citing Dunk v. Penn. Pub. Util. Comm’n, 252 A.2d 

589, 591-92 (Pa. 1969)). It also contrasts the absence of such language in the FPA with the 

Natural Gas Act and Part I of the FPA (addressing hydroelectric facilities). 

396 Ad Hoc Coalition of Southeastern Utilities at 59 (quoting Frankfort v. FERC, 

678 F.2d at 704); Large Public Power Council at 32 (quoting Frankfort v. FERC, 678 

F.2d at 707).

397 See, e.g., Ad Hoc Coalition of Southeastern Utilities at 59-60 (quoting Pub.

Serv. Co. of Ind. v. FERC, 575 F.2d at 1213); Large Public Power Council at 32 (quoting 

Pub. Serv. Co. of Ind., Inc. v. FERC, 575 F.2d at 1213).

398 Gulf States Utils. Co., 5 FERC ¶ 61,066 at 61,098 (1978).
Docket No. RM10-23-001 -263-

was not intended “to be a substitute for, or to immunize Otter Tail from, antitrust 

regulation.”399

352. Petitioners also argue that the Commission lacks the authority to remedy all 

instances of undue discrimination, and only is responsible for promoting competition if 

anticompetitive behavior has a direct effect on rates.400 In support, Sponsoring PJM 

Transmission Owners argue that CAISO v. FERC demonstrates that the Commission 

could not remedy a discriminatory governance structure of an independent system 

operator, and that the Supreme Court has held that the Commission does not have the 

authority to remedy racial discrimination in a utility’s hiring practices.401 Furthermore, 

Sponsoring PJM Transmission Owners argue that the Commission cannot rely on the 

court’s affirmation of Order Nos. 436402 and 888403 as support for its asserted authority to 

 399 Otter Tail Power Co. v. United States, 410 U.S. 366, 374-75 (1973) (Otter Tail v. 

U.S.).

400 Sponsoring PJM Transmission Owners at 14; Ad Hoc Coalition of Southeastern 

Utilities at n.176 (citing Entergy Services Inc., 64 FERC ¶ 61,001 at ¶ 61,013, n.66 

(1993); Cargill, Inc. v. Montfort of Colorado, Inc., 479 U.S. 104, 115-117 (1976)).

401 Sponsoring PJM Transmission Owners at 12 (citing CAISO. v. FERC, 372 F.3d 

400; NAACP v. FPC, 425 U.S. 662 (1976)).

402 Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order 

No. 436, FERC Stats. & Regs. ¶ 30,665, at 31,502 (1985).

403 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Pub. Utils.; Recovery of Stranded Costs by Pub. Utils. and 

Transmitting Utils., Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), order on 

(continued...)
Docket No. RM10-23-001 -264-

remedy any and all discrimination. Furthermore, Sponsoring PJM Transmission Owners, 

similar to Oklahoma Gas & Electric, assert that the court in Otter Tail Power Co. v. 

United States concluded that the Commission lacked the authority to compel 

interconnection based on antitrust considerations alone.404 Sponsoring PJM 

Transmission Owners also argue that Gulf States Utilities Co.,405 cited by the 

Commission, did not assert responsibility to promote competition in the abstract. 

Sponsoring PJM Transmission Owners assert that this lack of authority to act solely on 

antitrust considerations, in the absence of an impact on jurisdictional services, contrasts 

with the Commission’s authority to compel open access as a remedy for undue 

discrimination in transmission access, a jurisdictional service.406

353. Several petitioners contend that even if the Commission had the authority to 

address discrimination against nonincumbents, no undue discrimination against 

 

reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888-

B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 

(1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. 

FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002)). 

404 Sponsoring PJM Transmission Owners at 14 (citing 410 U.S. 366 (1973)). 

405 Gulf States Util. Co., 5 FERC ¶ 61,066 at 61,098.

406 Sponsoring PJM Transmission Owners at 15 (citing Transmission Access 

Policy Study Group v. FERC, 225 F.3d 667, 686 (D.C. Cir. 2000)). 
Docket No. RM10-23-001 -265-

nonincumbents exists for the Commission to remedy under section 206.407 Instead, some 

petitioners argue that Order No. 1000 institutionalizes undue discrimination against 

incumbent transmission owners in violation of the FPA and APA because it mandates 

similar treatment for incumbent transmission owners and nonincumbent transmission 

developers when they are not similarly situated.408 In support, petitioners argue that the 

Commission failed to consider evidence of the full scope of risks faced by incumbent 

utilities.409 For instance, several petitioners argue that incumbents have an obligation to 

serve customers and must comply with state legal and regulatory requirements, while 

nonincumbents are free to pick and choose among transmission investment options.410 

Others argue that incumbents are obligated to build under RTO contracts.411

354. Some petitioners also argue that it is unclear whether nonincumbent developers 

will have the same responsibilities as incumbent developers when operating their 

facilities. For instance, petitioners question whether there is a practical enforcement 

 407 See e.g., Ameren; PSEG Companies; and MISO Transmission Owners Group.

408 See, e.g., MISO Transmission Owners Group 2; and Ameren.

409 See, e.g., Ameren; Southern Companies; and MISO Transmission Owners 

Group 2.

410 See, e.g., Ameren; PSEG Companies; MISO Transmission Owners Group; and 

Southern Companies.

411 See, e.g., MISO Transmission Owners Group 2; and PSEG Companies.
Docket No. RM10-23-001 -266-

mechanism to ensure that a nonincumbent developer will build its transmission facility 

and then safeguard it from threats, such as cyber attacks.412 Transmission Dependent 

Utility Systems argue that even if the nonincumbent developer were to be assessed 

penalties for reliability violations, NERC penalties may be insufficient for a merchant 

transmission developer that, in the absence of a franchised service territory obligation, 

may walk away from its contractual commitments or become financially unable to meet 

them.

355. In related arguments, some petitioners disagree with the Commission’s conclusion 

that the federal right of first refusal is not dependent on an obligation to build.413 They 

argue that the obligation to build under an RTO or ISO is not an “option,” but rather 

imposes a duty of diligence in fulfilling construction obligations. Baltimore Gas & 

Electric argues that the Commission has misconstrued what a federal right of first refusal 

is, which it argues is another way of saying that it has a right of notification from PJM 

whenever PJM determines that transmission needs to be built in Baltimore Gas & 

Electric’s service area since Baltimore Gas & Electric is required to build it. Baltimore 

Gas & Electric argues that the Commission’s ruling on this issue is invalid because the 

 412 See, e.g., Baltimore Gas & Electric; and Transmission Dependent Utility 

Systems.

413 See, e.g., Baltimore Gas & Electric; and MISO.
Docket No. RM10-23-001 -267-

Commission failed to appreciate what a federal right of first refusal is. MISO states that 

since it does not own any transmission facilities, it needs to rely on the transmission 

owners’ obligation to build under the Transmission Owners Agreement to ensure MISO’s 

ability to fulfill its transmission planning and expansion responsibilities as an RTO. 

MISO states that its membership could be significantly eroded and its existence could be 

jeopardized, as well as its rate significantly affected, if the Commission were to modify 

this fundamental element of MISO’s structure as an RTO.

356. PSEG Companies contend that the elimination of the federal right of first refusal is 

a taking in violation of the Fifth Amendment to the U.S. Constitution because it renders 

meaningless the contractually-based consideration transmission owners received when 

they transferred control of their transmission facilities to ISOs/RTOs. They note that 

takings may not only be regulatory in nature but could include contractual takings.414 

According to PSEG Companies, language in the PJM Transmission Owners Agreement 

created the reasonable investment-backed expectation among incumbent transmission 

owners that they could participate in an RTO arrangement and commit to build 

everything needed for reliability purposes while still preserving fundamental rights, such 

as the right to build in their respective zones. PSEG Companies conclude that the 

 414 PSEG Companies at 36 (citing Tahoe-Sierra Preservation Council, Inc. v. 

Tahoe Regional Planning Agency, 535 U.S. 302, 332 (2002); Armstrong v. United Sates, 

364 U.S. 40, 49 (1960)).
Docket No. RM10-23-001 -268-

Commission’s impairment of this contractual right of first refusal creates unspecified 

economic injuries that, without just compensation, violate the U.S. Constitution.

(a) Commission Determination

357. We affirm the decision in Order No. 1000 that the Commission has the legal 

authority under section 206 of the FPA to require the elimination of federal rights of first 

refusal as practices that have the potential to lead to Commission-jurisdictional rates that 

are unjust and unreasonable or unduly discriminatory or preferential.415 At the outset, it 

is important to emphasize the scope of the Commission’s requirement to eliminate federal 

rights of first refusal. In Order No. 1000, the Commission required public utility 

transmission providers to remove from Commission-jurisdictional tariffs and agreements 

provisions that grant a federal right of first refusal to construct transmission facilities 

selected in a regional transmission plan for purposes of cost allocation.416 The 

Commission did not, however, require public utility transmission providers to remove a 

federal right of first refusal for local transmission facilities or upgrades to an incumbent 

transmission provider’s own transmission facilities, and did not alter an incumbent 

transmission provider’s use and control of an existing right of way.417 

 415 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 284.

416 Id. P 226.

417 Id.
Docket No. RM10-23-001 -269-

358. We affirm the decision in Order No. 1000 that a federal right of first refusal is a 

practice that falls squarely within the interpretation of a practice affecting rates.418 To 

this end, contrary to the argument of some petitioners, the Commission affirms that the 

CAISO v. FERC decision supports the Commission’s position. As discussed in Order No. 

1000, the court in CAISO v. FERC explained that the Commission is empowered under 

section 206 to assess practices that directly affect or are closely related to a public utility's 

rates and “not all those remote things beyond the rate structure that might in some sense 

indirectly or ultimately do so.”419 As explained in Order No. 1000, we meet this standard 

because here we are focused on the effect that federal rights of first refusal in 

Commission-approved tariffs and agreements have on competition and in turn the rates 

for jurisdictional transmission services. For example, as the Commission explained in 

Order No. 1000, the selection of transmission facilities in a regional transmission plan for 

purposes of cost allocation is directly related to costs that will be allocated to 

jurisdictional ratepayers.420 The ability of an incumbent transmission provider to 

discourage or preclude participation of new transmission developers through 

discriminatory rules in a regional transmission planning process, and in particular, the 

 418 Id. P 285.

419 CAISO v. FERC, 372 F.3d at 403.

420 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 289.
Docket No. RM10-23-001 -270-

inclusion of a federal right of first refusal, can have the effect of limiting the 

identification and evaluation of potential solutions to regional transmission needs.421 

This in turn can directly increase the cost of new transmission development that is 

recovered from jurisdictional customers through rates.422

359. Sponsoring PJM Transmission Owners argue that section 7 of the NGA, which 

gives the Commission authority to regulate pipeline construction, demonstrates that had 

Congress desired to give the Commission authority over construction of transmission 

lines it would have done so. However, Sponsoring PJM Transmission Owners 

misconstrue the Commission’s actions in Order No. 1000. As the Commission explicitly 

stated in Order No. 1000, it is not regulating construction of new transmission facilities 

because that is a matter reserved to the states.423 Instead, the Commission acted under its 

legal authority in section 206 to require the elimination of provisions in federallyregulated tariffs establishing practices in the regional transmission planning process that 

affect rates. The authority to authorize construction and siting of new transmission 

facilities is distinct from the authority to require public utility transmission providers to 

 421 Id. P 284.

422 Id.

423 Id. P 287 (“Eliminating a federal right of first refusal in Commissionjurisdictional tariffs and agreements does not, as some commenters contend, result in the 

regulation of matters reserved to the states, such as transmission construction, ownership 

or siting.” (emphasis added)).
Docket No. RM10-23-001 -271-

engage in an open and transparent regional transmission planning process designed to 

ensure that the more efficient or cost-effective solutions to regional transmission needs 

are selected in the regional transmission plan for purposes of cost allocation.

360. Contrary to Baltimore Gas & Electric’s arguments, the Commission made a 

finding in Order No. 1000 that granting an incumbent transmission provider a federal 

right of first refusal with respect to transmission facilities selected in a regional 

transmission plan for purposes of cost allocation can lead to rates for Commissionjurisdictional services that are unjust and unreasonable or otherwise result in undue 

discrimination by public utility transmission providers.424 Consistent with section 206, 

the Commission acted to remedy an unjust and unreasonable or unduly discriminatory or 

preferential practice by requiring public utility transmission providers to eliminate such 

provisions from Commission-jurisdictional tariffs or agreements and adopt the 

nonincumbent transmission developer reforms. In addition, the Commission’s decision 

to require public utility transmission providers to adopt the nonincumbent transmission 

developer reforms was an appropriate, and adequately tailored, remedy in light of the 

Commission’s conclusion that it is not in the economic self-interest of public utility 

transmission providers to permit new entrants to develop transmission facilities.425 For 

 424 Id. PP 253, 284.

425 Id. P 256.
Docket No. RM10-23-001 -272-

instance, some commenters supported eliminating all federal rights of first refusal. On 

balance, however, the Commission determined that incumbent transmission providers 

should be able to maintain an existing federal right of first refusal for certain types of new 

transmission projects, including a local transmission facility and upgrades to its existing 

transmission facilities. The Commission clarified that its actions were not intended to 

diminish the significance of an incumbent transmission provider’s reliability or service 

obligations.426 

361. In addition to affirming our decision to act to remedy unjust and unreasonable 

rates, we affirm, on an independent and alternative basis, the decision in Order No. 1000 

that the elimination of any federal rights of first refusal from Commission-jurisdictional 

tariffs and agreements is necessary to address opportunities for undue discrimination and 

preferential treatment against nonincumbent transmission developers within regional 

transmission planning processes.427 In Order No. 1000, the Commission explained that 

“it has a responsibility to consider anticompetitive practices and to eliminate barriers to 

competition.”428 We continue to believe, as the Commission found in Order No. 1000, 

 426 Id. P 262.

427 Id. P 286.

428 Id.
Docket No. RM10-23-001 -273-

that we have a duty to consider anticompetitive practices and to eliminate barriers to 

competition consistent with the FPA.429

362. Petitioners rely on City of Frankfort and Public Service Co. of Ind. in support of 

their contention that section 206’s prohibition on undue discrimination only protects 

customers of public utilities. However, the court did not, as petitioners would imply, set 

forth limits on who the Commission may, acting under its section 206 authority, protect 

from unduly discriminatory practices. Instead, the cases cited by petitioners address the 

applicability of section 206 in the context of a regulated utility appearing to provide 

favorable rates or terms to one customer, and the courts in those cases do not address 

whether section 206 may be used as a basis for eliminating unduly discriminatory or 

preferential practices between competitors. In addition, we continue to conclude that the 

Commission’s action is in accordance with its responsibility to eliminate unduly 

discriminatory or preferential practices in regional transmission planning processes.

363. While we agree with petitioners that argue that the Commission does not have the 

authority to remedy every instance of undue discrimination, given the FPA’s emphasis on 

promoting competition, the Commission has a responsibility to eliminate unduly 

 429 See Gulf States Utils. Co., 5 FERC ¶ 61,066 at 61,098; Otter Tail v. U.S., 410 

U.S. at 374 (“the history of Part II of the Federal Power Act indicates an overriding 

policy of maintaining competition to the maximum extent possible consistent with the 

public interest.”).
Docket No. RM10-23-001 -274-

discriminatory practices that come within the Commission’s subject matter jurisdiction 

under section 201 of the FPA, which includes the transmission of electric energy in 

interstate commerce.430 In Order No. 1000, the Commission found that “federal rights of 

first refusal create opportunities for undue discrimination and preferential treatment 

against nonincumbent transmission developers within existing regional transmission 

planning processes.”431 Accordingly, the Commission has acted consistent within its 

authority to eliminate and remedy practices that it found to be unduly discriminatory and 

anticompetitive. In any event, the Commission has not based its decision solely on 

competition concerns because, in the alternative, the Commission acted to remedy the 

potential for unjust and unreasonable rates for Commission-jurisdictional services in 

addition to promoting competition among potential transmission developers. 

364. We disagree with petitioners’ argument that Order No. 1000 institutionalizes 

undue discrimination against incumbent transmission providers. Petitioners argue that 

the Commission failed to consider the full scope of risks faced by incumbent 

transmission providers, and thus erroneously concluded that incumbent transmission 

providers and nonincumbent transmission developers are similarly situated. For example, 

some petitioners argue that many incumbent transmission providers have obligations to 

 430 16 U.S.C. 824.

431 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 286.
Docket No. RM10-23-001 -275-

build placed on them under RTO and ISO member agreements. However, as explained in 

Order No. 1000, nonincumbent transmission developers that build a transmission facility 

in an RTO or ISO and become members of that RTO or ISO will be subject to the same 

relevant obligations that apply to incumbent transmission providers that are members of 

an RTO or ISO.432 For instance, nonincumbent transmission developers also will have an 

obligation to expand their transmission facilities if directed to by the RTO or ISO 

consistent with the RTO’s or ISO’s tariff or governing agreement. 

365. Other petitioners argue that incumbent transmission providers are not similarly 

situated to nonincumbent transmission developers because incumbent transmission 

providers, unlike nonincumbent transmission developers, must comply with reliability 

standards and have an obligation to serve customers. They further argue that having a 

federal right of first refusal is necessary to comply with these standards and obligations. 

While public utility transmission providers must comply with reliability standards and 

some public utility transmission providers have an obligation to serve,433 we disagree that 

eliminating federal rights of first refusal amounts to discrimination in favor of 

nonincumbent transmission developers. Instead, as we stated in Order No. 1000, we are 

merely removing barriers to participation by all potential transmission providers in the 

 432 Id. P 265.

433 Id.
Docket No. RM10-23-001 -276-

regional transmission planning process subject to our jurisdiction. Moreover, as 

explained in Order No. 1000, all owners and operators of bulk-power system 

transmission facilities, including nonincumbent transmission developers, that 

successfully develop a transmission project, are required to be registered as Functional 

Entities434 and must comply with all applicable reliability standards.435Similarly, 

transmission facilities selected in a regional transmission plan for purposes of cost 

allocation owned by a nonincumbent transmission developer would be subject to any 

applicable open access requirements. Accordingly, we continue to believe that the 

nonincumbent transmission developer reforms will not result in undue discrimination 

against incumbent transmission developers.

366. Similarly, we disagree with Oklahoma Gas and Electric Company that the 

nonincumbent transmission developer reforms materially alter the business of a public 

utility that has been responsible for, and entitled to earn a return from, construction of its 

own transmission system. As we explained in Order No. 1000, while public utilities are 

entitled to receive a reasonable return on their investment, they will no longer be entitled 

 434 We use the term Functional Entity to refer to any user, owner or operator of the 

bulk power system that is responsible for complying with a NERC reliability standard as 

that term is defined in section 215(a)(3) of the FPA.

435 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 266 (citing 18 CFR Part 

39.2(a) (2011)).
Docket No. RM10-23-001 -277-

to receive from the Commission a preferential right to make those investments in new 

transmission facilities that are selected in a regional transmission plan for purposes of 

cost allocation under the provisions of Order No. 1000.436 Inherent in Oklahoma Gas and 

Electric Company’s argument is that incumbent transmission providers have traditionally 

had the opportunity to build transmission facilities for their own transmission systems. 

Nothing in Order No. 1000 prohibits an incumbent transmission provider from choosing 

to build new transmission facilities that are located solely within its retail distribution 

service territory or footprint and that are not selected for selection in a regional 

transmission plan for purposes of cost allocation.437

367. We are not persuaded by Baltimore Gas & Electric’s argument that a federal right 

of first refusal is simply the recognition of an obligation to build. In Order No. 1000, we 

acknowledged that a public utility transmission provider may have accepted an obligation 

to build in relation to its membership in an RTO or ISO, but the Commission did not 

agree that that obligation is necessarily dependent on the incumbent transmission 

provider having a corresponding federal right of first refusal to prevent other entities 

from constructing and owning new transmission facilities located in that region.438 We 

 436 Id. P 269.

437 Id. P 262.

438 Id. P 261.
Docket No. RM10-23-001 -278-

continue to believe that an obligation to build in relation to membership in an RTO or 

ISO is not necessarily dependent on an incumbent transmission provider having a 

corresponding federal right of first refusal to prevent other entities from constructing and 

owning new transmission facilities located in that region,439 and Baltimore Gas & 

Electric has provided no evidence to the contrary. Moreover, while eliminating a 

federal right of first refusal may change the benefits and obligations associated with 

membership in an RTO or ISO, we affirm our finding in Order No. 1000 that changing 

the benefits and obligations is necessary to correct practices that have the potential to lead 

to unjust and unreasonable rates for Commission-jurisdictional transmission service.440 

Similarly, we disagree with MISO that the nonincumbent transmission developer reforms 

will discourage entities from maintaining membership in an RTO or ISO, because, as 

explained in Order No. 1000, there are a variety of factors that public utility transmission 

providers must weight when evaluating the benefits and burdens of RTO/ISO 

membership.441 

368. We also are not convinced by PSEG Companies’ argument that requiring public 

utility transmission providers to eliminate a federal right of first refusal for transmission 

 439 Id.

440 Id.

441 Id. P 265.
Docket No. RM10-23-001 -279-

projects that are selected in the regional plan for purposes of cost allocation violates the 

Takings Clause of the Fifth Amendment. Nor do we agree that Order No. 1000 destroys 

or materially impairs PSEG Companies’ purported contractual right to build in their 

respective service areas or zones. Although some contractual rights are “property” within 

the meaning of the Taking Clause,442 the Commission has not impaired this alleged 

contractual right of first refusal. Order No. 1000 continues to permit an incumbent 

transmission provider, such as PSEG Companies, to meet its reliability needs or service 

obligations by choosing to build new transmission facilities that are located solely within 

its retail distribution service territory or footprint as long as the transmission provider 

does not receive regional cost allocation for the facilities.443 

369. Even assuming that Order No. 1000 impinges upon this alleged contractual right, 

PSEG Companies have not met their “substantial burden” to show “whether a regulation 

‘reaches a certain magnitude’ in depriving an owner of the use of property.”444 Just as 

“legislation [that] readjust[s] rights and burdens is not unlawful solely because it upsets 

 442 Connolly v. Pension Guaranty Corp., 475 U.S. 211, 224 (1986) (holding that 

congressional action that impinged upon employers’ contractual rights did not constitute 

an unconstitutional taking).

443 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 262.

444 District Intown Props. Ltd. Pshp. v. District of Columbia, 198 F.3d 874, 878 

(D.C. Cir. 1999) (citing Pennsylvania Coal Co. v. Mahon, 260 U.S. 393, 413 (1922)).
Docket No. RM10-23-001 -280-

otherwise settled expectations,”445 the Order No. 1000 regulations regarding the federal 

right of first refusal are not unconstitutional takings solely because the regulations impact 

the benefits and burdens of transmission owner agreements. Furthermore, in arguing that 

Order No. 1000 operates to take their property, PSEG Companies have a burden to 

demonstrate the economic injury they expect to incur if they are denied the future 

exclusive opportunity to build transmission facilities in their service territory.446 They 

have not met this burden in their rehearing request.

370. Finally, PSEG Companies also have not argued that Order No. 1000 appropriates 

their alleged contractual right of first refusal for public use. Nor could the Commission 

be said to be taking the federal right of first refusal so that another entity could use it for 

public purposes.

447 Rather, we require the elimination of such provisions so that 

incumbent transmission providers and nonincumbent transmission developers will have 

an opportunity on a comparable basis to propose new transmission facilities for selection 

 445 Connolly, 475 U.S. at 223.

446 See Connolly, 475 U.S. at 225 (to determine whether there is a “taking,” the 

Court evaluates three factors: “(1) the economic impact of the regulation on the claimant; 

(2) the extent to which the regulation has interfered with investment-backed expectations; 

and (3) the character of the governmental action). 

447 See Omnia, 261 U.S. at 508-13 (holding that, while government requisition of 

steel frustrated a contract for delivery of steel, the government action was not an 

appropriation for public purposes that required just compensation). 
Docket No. RM10-23-001 -281-

in the regional transmission plan for purposes of cost allocation.448 For these reasons, we 

find that the elimination of federal rights of first refusal does not constitute a taking under 

the Fifth Amendment’s Taking Clause.

ii. Arguments That the Commission Is 

Inappropriately Regulating the Construction of 

Transmission

371. Several petitioners argue that the Commission’s reforms impermissibly infringe on 

state jurisdiction to authorize construction and operation of transmission lines.449 

Ameren states that section 201(a) expressly provides that the Commission does not have 

authority over matters that are subject to regulation by the states, and that states have 

historically exercised jurisdiction over siting and construction of transmission facilities. 

Ameren asserts that had Congress wished to expand the Commission’s jurisdiction, it 

would have done so by adding new sections to the FPA, such as sections 215 and 216, 

which gave the Commission expanded authority over reliability. Wisconsin PSC also 

argues that FPA sections 201 and 206 do not create a federal right to authorize 

 448 Accord Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277, 1284 

(D.C. Cir. 2007) (finding that anti-discrimination rules commonly burden the obligated 

parties and that the burden imposed did not create an unconstitutional taking of private 

property).

449 See, e.g., Wisconsin PSC; Baltimore Gas & Electric; Ameren; and PSEG 

Companies.
Docket No. RM10-23-001 -282-

transmission line construction.450 According to PSEG Companies, the removal of the 

federal right of first refusal “immediately, directly and irreparably impacts” the decision 

of who gets to site, construct, and own transmission facilities in a transmission owner’s 

zone, and incumbent transmission owners will no longer have the threshold right to build 

in their respective state service territories to satisfy their obligations under state law. In 

addition, Baltimore Gas & Electric argues that the federal right of first refusal has 

nothing to do with the Commission’s limited backstop authority over transmission 

construction.451

372. Ameren requests clarification that, in implementing the requirement to remove any 

federal right of first refusal from Commission-jurisdictional tariffs and agreements, 

incumbent transmission owners that have a state certified service area or local franchise 

service area retain the sole right to build infrastructure and serve customers in that service 

territory. Ameren asserts the Commission also should clarify that it does not have the 

authority to preempt a state law or regulation of this type. However, Southern 

Companies assert that the Commission should explicitly state that Order No. 1000 

preempts the state-mandated duty to serve native load to the extent that a nonincumbent 

 450 Wisconsin PSC at 14-15 (citing Dunk v. Pennsylvania Pub. Util. Comm’n, 434 

Pa. 41, 44-45, 252 A.2d 589, 591-92, cert. denied, 396 U.S. 839 (1969)). 

451 Baltimore Gas & Electric at 5 (citing 16 U.S.C. 824p).
Docket No. RM10-23-001 -283-

sponsors a transmission project needed to fulfill that duty to serve. They argue that Order 

No. 1000’s requirements will impair the ability of incumbents to comply with their statemandated duty to serve native load, and that these provisions might be used to argue that 

incumbents should be subject to ramifications under state law for a nonincumbent’s 

delay, abandonment, or other possible wrong doing.

373. Other petitioners point out that, unlike the NGA, the FPA does not grant the 

Commission any authority over construction or ownership of transmission facilities.452 

Wisconsin PSC states that Order No. 1000 confusingly implies the existence in the FPA 

of a federal ability to confer a right to construct, which is not in the FPA, whereas the 

FPA reserved such authority to state jurisdiction.453 Wisconsin PSC argues that in 

Connecticut Light & Power Co. v. FERC, the Supreme Court engages in an extensive 

discussion that suggests that even though the particular facilities and activities of a person 

determine whether the person is a public utility subject to the FPA, there is a limit to the 

agency’s jurisdiction.454 Southern Companies also state that the decision to construct or

invest in a transmission facility does not belong to the Commission, except as required to 

 452 See, e.g., Southern Companies; and Wisconsin PSC.

453 Wisconsin PSC at 13-14 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323

at P 334, 340). 

454 Wisconsin PSC at 14 (citing 324 U.S. 515, 525-27 (1945)).
Docket No. RM10-23-001 -284-

grant or maintain service for transmission service customers.455 They argue there is no 

authority for the proposition that the Commission may require a public utility 

transmission provider to plan for, construct, or fund any new transmission facility 

involuntarily.

374. Some petitioners argue that existing rights of first refusal in Commission-approved 

RTO/ISO tariffs and agreements were crafted and negotiated expressly to ensure that 

each incumbent load-serving transmission owner could continue to fulfill its stateimposed service obligations.456 Baltimore Gas & Electric states that the federal right of 

first refusal stems from the natural monopoly franchise service obligations that retail 

public utilities must abide by, in part through their Commission-jurisdictional wholesale 

transmission lines. According to Baltimore Gas & Electric, Commission-jurisdictional 

tariffs and agreements merely acknowledge the right of first refusal that Baltimore Gas & 

Electric had before joining PJM and others had before joining other RTOs and ISOs. 

Thus, Baltimore Gas & Electric argues that there is no such thing as a federal right of first 

refusal derived from a Commission tariff, but rather a right of first refusal in a 

 455 Southern Companies at 102 (citing Alabama Power Co. v. FERC, 993 F.2d 1557 

(D.C. Cir. 1993)).

456 Ameren; MISO Transmission Owners Group 2; and PSEG Companies. PSEG 

Companies state that their points in this regard are buttressed by comments from 

Pennsylvania PUC, ITC, and SPP.
Docket No. RM10-23-001 -285-

Commission tariff connotes that the transmission owner retained its existing state-granted 

right of first refusal when it voluntarily submitted itself to the regional planning process 

of whatever RTO or ISO it opted to join, if any.

375. Moreover, MISO contends that the removal of such provisions would place MISO 

in the role of deciding who should construct planned transmission facilities. It states that 

state law, not federal, governs the preconditions associated with the siting and 

construction of transmission and the appurtenant rights associated with such construction 

including, but not limited to, the right of eminent domain. As such, MISO argues that its 

role under Order No. 1000 should not be to determine who should build specific 

transmission projects identified through its transmission planning process because it has 

not been vested with any rights by any state legislature or state commission regarding the 

construction of the facilities that may be deemed necessary as a result of the MISO 

Transmission Expansion Plan process or any other plan developed by MISO and its 

stakeholders. Therefore, MISO requests that the Commission reconsider Order No. 

1000’s generic requirement regarding the elimination of rights of first refusal from 

jurisdictional tariffs and agreements, insofar as that requirement would entail 

modification of the Transmission Owners Agreement provisions on the transmission 

owners’ right to build, and related tariff provisions.

376. Southern Companies argue that the Commission seeks to regulate who has the 

right to construct and own transmission facilities by regulating who is entitled to the 
Docket No. RM10-23-001 -286-

benefits of the regional and interregional cost allocation processes. Southern Companies 

argue that nothing in section 206 confers upon the Commission authority to require, 

authorize, or regulate who will construct or own transmission facilities or sponsor a 

transmission project in a transmission planning process.457 Similarly, Ad Hoc Coalition 

of Southeastern Utilities argues that although the Commission does not directly mandate 

construction according to regional plans, this distinction may prove to be immaterial as 

the financially punitive effect of constructing redundant transmission facilities makes 

deference to nonincumbent transmission developers effectively mandatory.458 Large 

Public Power Council makes a similar argument. Ad Hoc Coalition of Southeastern 

Utilities and Large Public Power Council assert that this creates a dilemma for incumbent 

transmission developers that must effectively defer to the plans of nonincumbent 

developers but also must continue to satisfy their service obligations while complying 

with potentially costly mandatory and enforceable reliability standards. 

(a) Commission Determination

377. We affirm the Commission’s finding in Order No. 1000 that the nonincumbent 

transmission developer reforms do not result in the regulation of matters reserved to the 

 457 Southern Companies at 60 (citing Northern Gas Co. v. Kansas Comm’n, 372 

U.S. 84, 91-93 (1963)). 

458 Ad Hoc Coalition of Southeastern Utilities at 57 (citing Associated Gas, 824 

F.2d at 1000-01).
Docket No. RM10-23-001 -287-

states, such as transmission construction, ownership or siting.459 As the Commission 

explained in Order No. 1000, the nonincumbent transmission developer reforms are 

focused solely on public utility transmission provider tariffs and agreements subject to 

the Commission’s jurisdiction and are not intended to limit, preempt, or otherwise affect 

state or local laws or regulations with respect to construction of transmission facilities, 

including but not limited to authority over siting or permitting of transmission 

facilities.460 

378. We disagree with petitioners that argue that the Commission needs new authority 

in the FPA to adopt the nonincumbent transmission developer reforms, as these 

arguments rest on the faulty premise that the Commission is somehow regulating the 

construction of transmission facilities. Order No. 1000 does not address transmission 

construction. Instead, the nonincumbent transmission developer reforms in Order No. 

1000 ensure that nonincumbent transmission developers have a comparable opportunity 

to incumbent transmission developers/providers to submit transmission projects for 

evaluation and potential selection in the regional transmission plan for purposes of cost 

allocation. These reforms further provide that a nonincumbent transmission developer’s 

project that is selected in the regional transmission plan for purposes of cost allocation 

 459 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 287

460 Id.
Docket No. RM10-23-001 -288-

will not be subject to any federal right of first refusal, which must be eliminated, except 

in certain limited circumstances. The reforms do not, however, speak to which entity 

may ultimately construct any transmission facilities. Moreover, we note that we agree 

with Baltimore Gas & Electric that eliminating a federal right of first refusal is unrelated 

to the Commission’s authority under section 216 of the FPA.461

379. We disagree with petitioners that argue that eliminating a federal right of first 

refusal preempts state law, or is otherwise prohibited by state law. As noted above, the 

Commission made clear that its reforms are focused on Commission-jurisdictional tariffs 

and agreements, and are not intended to preempt state or local laws or regulations. 

Moreover, as explained in greater detail below, an incumbent transmission provider has 

several choices for meeting its reliability needs and service obligations. In particular, 

Order No. 1000 permits an incumbent transmission provider to meet its reliability needs 

or service obligations by choosing to build new transmission facilities that are located 

solely within its retail distribution service territory or footprint and that are not selected 

for regional cost allocation.462

 461 16 U.S.C. 824p (2006). Section 216 addresses the designation and siting of 

transmission facilities within National Interest Electric Transmission Corridors.

462 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 262.
Docket No. RM10-23-001 -289-

380. In response to Wisconsin PSC, we note that the Commission specifically declined 

in Order No. 1000 to adopt the proposal in the rulemaking that would have required 

public utility transmission providers in the regional transmission planning process to 

provide transmission developers a right to construct and own a transmission facility 

selected in a regional transmission plan for purposes of cost allocation.463 The 

Commission also declined to a provide transmission developer with an ongoing right to 

build and own a transmission project that it proposed but that was not selected.464 

Because the Commission did not adopt these proposals, we do not need to address 

whether the Commission has the authority to grant them. 

381. In response to Baltimore Gas & Electric’s argument that Commissionjurisdictional tariffs and agreements merely acknowledge a right of first refusal that it had 

before joining PJM, we affirm the statement in Order No. 1000 that “[t]his Final Rule 

does not require removal of references to such state or local laws or regulations from 

Commission-approved tariffs or agreements.”465 Accordingly, such a right based on a 

state or local law or regulation would still exist under state or local law even if removed 

from the Commission-jurisdictional tariff or agreement, and nothing in Order No. 1000 

 463 Id. P 338.

464 Id. P 340.

465 Id. P 253 n.231.
Docket No. RM10-23-001 -290-

changes that law or regulation, for Order No. 1000 is clear that nothing therein is 

“intended to limit, preempt, or otherwise affect state or local laws or regulations with 

respect to construction of transmission facilities.”466

382. We disagree with MISO that eliminating a federal right of first refusal would put it 

in the position of deciding who should construct planned transmission facilities. Rather, 

the transmission planning and cost allocation reforms in Order No. 1000 are designed to 

allow the public utility transmission providers in a transmission planning region to 

evaluate whether new transmission facilities would efficiently and cost-effectively meet 

their transmission needs, as well as to provide a cost allocation method for those facilities 

selected in the regional transmission plan for purposes of cost allocation. We 

acknowledge that a decision made to select a new transmission facility in the regional 

transmission plan for purposes of cost allocation may affect which entity ultimately 

constructs and owns transmission facilities. However, we reiterate that nothing in Order 

No. 1000 creates any new authority for the Commission nor public utility transmission 

providers acting through a regional transmission planning process to site or authorize the 

construction of transmission projects. Furthermore, Order No. 1000 does not prohibit an 

incumbent transmission provider from having a federal right of first refusal for a new 

 466 Id. P 287.
Docket No. RM10-23-001 -291-

local transmission facility that is not selected in a regional transmission plan for purposes 

of cost allocation.

iii. Arguments That the Commission Must Meet the 

Mobile-Sierra Public Interest Standard Before 

Requiring Federal Rights of First Refusal To Be 

Removed From Agreements

383. Several petitioners argue that the Commission cannot modify a contractual federal 

right of first refusal without first making a determination that the federal right of first 

refusal seriously harms the public, which they argue the Commission failed to do.467 

MISO Transmission Owners Group 2 argues that in Mobile-Sierra, the U.S. Supreme 

Court found that the Commission must presume that the rate set out in a freely-negotiated 

wholesale energy contract meets the just and reasonable requirement, and that this 

presumption can be overcome only if the Commission concludes that the contract 

seriously harms the public interest. MISO Transmission Owners Group 2 also argues that 

other Supreme Court precedent found that the Commission cannot base its demand that 

 467 See, e.g., Ameren; Sponsoring PJM Transmission Owners at 21 (citing Morgan 

Stanley Capital Group v. Pub. Util. Dist. No. 1 of Snohomish City., 554 U.S. 527, 545-46 

(2008)); Baltimore Gas & Electric; PSEG Companies at 9-11, 14-15 (citing comments 

from Oklahoma Gas & Electric Co., Ad Hoc Coalition of Southeastern Utilities, North 

Dakota & South Dakota Commissions, Alabama PSC, Southern Companies, Baltimore 

Gas & Electric Co., MidAmerican, Pacific Gas & Electric, PJM, PSEG Companies, and 

Southern California Edison); MISO; MISO Transmission Owners Group 2; Northern Tier 

Transmission Group.
Docket No. RM10-23-001 -292-

public utility transmission providers modify existing contracts on a finding that the 

existing contract provisions may lead to rates that are unjust and unreasonable.468 

384. Some petitioners state that the federal right of first refusal is embodied in the PJM 

Transmission Owner’s Agreement, and thus assert that the Commission must make a 

Mobile-Sierra finding before it can modify the agreement.469 PSEG Companies argue 

that the Commission cannot make such a finding because nothing in Order No. 1000 or in 

the rulemaking record would support such a conclusion. 

385. Other petitioners also argue that Order No. 1000 does not discuss how existing 

contractual rights of first refusal, such as that in the Midwest ISO Transmission Owners 

Agreement, seriously harm the public interest.470 MISO states that while Order No. 1000 

purports to avoid addressing Mobile-Sierra issues with regard to any particular 

jurisdictional agreement, the Commission erred in requiring generically in this 

proceeding a modification that it cannot require specifically for each jurisdictional 

 468 MISO Transmission Owners Group 2 at 32 (citing Morgan Stanley Capital 

Group, Inc. v. Public Utility Dist. No. 1, 554 U.S. 527 (2008) and NRG Power Marketing, 

LLC v. Maine PUC, 130 S.Ct. 693 (2010)).

469 See, e.g., Sponsoring PJM Transmission Owners; Baltimore Gas & Electric; 

and PSEG Companies.

470 Ameren at 16 (citing Agreement of Transmission Facilities Owners to Organize 

the Midwest Independent Transmission System Operator, Inc., A Delaware Non-Stock 

Corporation, Third Revised Rate Schedule FERC No. 1); MISO; MISO Transmission 

Owners Group 2.
Docket No. RM10-23-001 -293-

agreement without determining that the retention of such a right in the particular 

agreement is against the public interest, unjust, unreasonable, or unduly discriminatory or 

preferential, or otherwise anticompetitive. MISO further argues that with respect to the 

public interest standard, the Commission cannot make a generic finding as a substitute for 

the specific finding it must make before declaring that the provisions of a particular 

agreement are contrary to the public interest.

386. In addition, PSEG Companies disagree with the statement in Order No. 1000 that 

this issue can be deferred until the compliance stage of this proceeding. Specifically, 

they take issue with the Commission’s conclusion that the record was insufficient to 

address National Grid’s comment regarding Mobile-Sierra and the ISO-NE operating 

agreement, stating that if the Commission had serious evidence of harm to the public 

interest then it should have had no difficulty in articulating it in Order No. 1000. PSEG 

Companies assert that it is ironic that while the Commission chose to engage in 

nationwide abrogation of individual contracts in a generic rulemaking, it seeks to avoid 

the required analysis on the ground that a rulemaking proceeding is an inappropriate 

vehicle for such an analysis. They also argue that the Commission’s decision to defer 

review of the Mobile-Sierra protections to the compliance stage has no basis in law, 

explaining that the Commission is bound by law to apply the standard before abrogating 

any contracts. PSEG Companies state that the compliance stage is not the appropriate 

procedural stage to address this issue because under Mobile-Sierra the Commission has 
Docket No. RM10-23-001 -294-

the burden to make its public interest finding and it is not the contracting parties’ burden 

to defend the provisions that the Commission seeks to modify.471

387. Sunflower, Mid-Kansas, and Western Farmers request a partial stay of Order No. 

1000’s effectiveness, at least for RTOs that have limited federal rights of first refusal, if 

the Commission does not grant their requests for rehearing and clarification, so that 

RTOs are not required to remove any federal right of first refusal provisions until Order 

No. 1000 is final and non-appealable. They argue that it is highly likely that Order No. 

1000 will be appealed and that the rehearing and appeals process may span several years. 

Sunflower, Mid-Kansas, and Western Farmers assert that stakeholders will be irreparably 

harmed if this portion of Order No. 1000 is effective before the appeals process is 

complete, citing the time and resources needed to modify existing tariffs and, more 

important, the loss of SPP transmission owners’ rights that cannot be restored if the 

courts rule against the Commission on this issue.

(a) Commission Determination

388. The Commission affirms its decision in Order No. 1000 to address arguments that 

an individual contract contains a federal right of first refusal that is protected by a 

Mobile-Sierra provision when it reviews the compliance filings made by public utility 

 471 PSEG Companies at 13 (citing Wisconsin Public Power, Inc. v. FERC, 493 

F.3d 239 (D.C. Cir. 2007)).
Docket No. RM10-23-001 -295-

transmission providers. We continue to find that the record in this rulemaking 

proceeding is not sufficient to address the specific issues raised regarding individual 

agreements. Accordingly, we reject arguments that the Commission must address in this 

generic rulemaking proceeding whether any particular agreement is protected by a 

Mobile-Sierra provision. Furthermore, in response to PSEG Companies, the Commission 

decided in Order No. 1000 when it will address the issue of whether a federal right of 

first refusal provision is protected by Mobile-Sierra; it did not and cannot shift the burden 

to defend such provisions to contracting parties.

389. As the Commission explained in Order No. 1000, a public utility transmission 

provider that considers its contract to be protected by a Mobile-Sierra provision may 

present its arguments as part of its compliance filing. We clarify, however, that any such 

compliance filing must include the revisions to any Commission-jurisdictional tariffs and 

agreements necessary to comply with Order No. 1000 as well as the Mobile-Sierra

provision arguments. The Commission will first decide, based on a more complete 

record, including the viewpoints of other interested parties, whether the agreement is 

protected by a Mobile-Sierra provision, and if so, whether the Commission has met the 

applicable standard of review such that it can require the modification of the particular 

provisions.472 If the Commission determines that the agreement is protected by a Mobile-

 472 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 292.
Docket No. RM10-23-001 -296-

Sierra provision and that it cannot meet the applicable standard of review, then the 

Commission will not consider whether the revisions submitted to the Commissionjurisdictional tariffs and agreements comply with Order No. 1000. However, if the 

Commission determines that the agreement is not protected by a Mobile-Sierra provision 

or that the Commission has met the applicable standard of review, then the Commission 

will decide whether the revisions to the Commission-jurisdictional tariffs and agreements 

comply with Order No. 1000 and, if such tariffs and agreements are accepted, would 

become effective consistent with the approved effective date. As a result, the 

Commission is not requiring public utility transmission providers to eliminate a federal 

right of first refusal before the Commission makes a determination regarding whether an 

agreement is protected by a Mobile-Sierra provision and whether the Commission has 

met the applicable standard of review, while at the same time the Commission is ensuring 

that the Order No. 1000 compliance process proceeds expeditiously and efficiently.

390. We also deny Sunflower, Mid-Kansas, and Western Farmers’ request for a partial 

stay of the requirement to remove a federal right of first refusal from Commissionjurisdictional tariffs and agreements. In considering requests for a stay, the Commission 

has applied the standards set forth in section 705 of the Administrative Procedure Act,473 

 473 5 U.S.C. 705 (2006).
Docket No. RM10-23-001 -297-

and has granted a stay “when justice so requires.”474 In deciding whether justice requires 

a stay, the Commission considers several factors, including: (1) whether the party 

requesting the stay will suffer irreparable injury without a stay; (2) whether issuing the 

stay may substantially harm other parties; and (3) whether a stay is in the public 

interest.475 The Commission’s general policy is to refrain from granting stays of its 

orders to assure definiteness and finality in Commission proceedings.476 If the party 

requesting the stay is unable to demonstrate that it will suffer irreparable harm absent a 

stay, the Commission need not examine the other factors.477 As the D.C. Circuit has 

explained, a harm must be both certain and actual rather than theoretical, and “mere 

injuries, however substantial, in terms of money, time and energy necessarily expended 

in the absence of a stay are not enough.”478 

391. Sunflower, Mid-Kansas, and Western Farmers’ request for stay fails to meet the 

first criterion, which requires it to show that it will suffer irreparable injury without a stay 

 474 Id.

475 See, e.g., CMS Midland, Inc., 56 FERC ¶ 61,177 at P 61,631 (1991), aff’d sub 

nom. Mich. Mun. Coop. Group v. FERC, 990 F.2d 1377 (D.C. Cir.), cert. denied, 510 

U.S. 990 (1993).

476 Id.

477 Id.

478 Wisconsin Gas Co. v. FERC, 785 F.2d 699, 674 (D.C. Cir. 1985).
Docket No. RM10-23-001 -298-

of the requirement to eliminate a federal right of first refusal. They argue that they must 

spend time and resources to modify existing tariffs. However, we find that this type of 

economic loss is not sufficient to warrant a stay. Furthermore, while Sunflower, MidKansas and Western Farmers may lose the opportunity to exercise a federal right of first 

refusal, it amounts to speculation to assert that this will necessarily cause Sunflower, 

Mid-Kansas and Western Farmers to lose the opportunity to build a transmission project 

that they could have exercised a federal right of first refusal to build. They also will still 

have the opportunity to submit projects for evaluation and potential selection in the 

regional transmission plan for purposes of cost allocation as well as to build local 

transmission projects.479 Thus, the harm that Sunflower, Mid-Kansas and Western 

Farmers argue that they will suffer is speculative because Sunflower, Mid-Kansas and 

Western Farmers cannot point to a specific transmission project that they will lose the 

right to construct and own at this time, or in the immediate future. Accordingly, we find 

that Sunflower, Mid-Kansas and Western Farmers have not shown that they will suffer 

irreparable harm absent a stay of the nonincumbent transmission developer reforms in 

Order No. 1000.480

 479 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 318.

480 Moreover, though unnecessary to support our denial of this motion for stay, we 

note that issuing a stay here may substantially harm other parties, thereby violating the 

second factor the Commission considers in whether to grant a stay. As the Commission 

(continued...)
Docket No. RM10-23-001 -299-

2. Requirement To Remove a Federal Right of First Refusal from 

Commission-Jurisdictional Tariffs and Agreements, and Limits 

on the Applicability of That Requirement

a. Final Rule

392. In Order No. 1000, the Commission directed public utility transmission providers 

to eliminate provisions in Commission-jurisdictional tariffs and agreements that establish 

a federal right of first refusal for an incumbent transmission provider with respect to 

transmission facilities selected in a regional transmission plan for purposes of cost 

allocation.481 However, Order No. 1000 also limited the applicability of that elimination 

requirement in important ways. The Commission stated that its focus was on the set of 

transmission facilities that are evaluated at the regional level and selected in the regional 

transmission plan for purposes of cost allocation, and that it was not requiring removal 

from Commission-jurisdictional tariffs and agreements of federal rights of first refusal as 

 

has explained, greater participation by transmission developers in the transmission 

planning process may lower the cost of new transmission facilities for transmission 

customers, enabling more efficient or cost-effective solutions to regional transmission 

needs. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 291. Accordingly, because 

the removal of a federal right of first refusal applies only to new transmission facilities 

selected in a regional transmission plan for purposes of cost allocation, granting a stay of 

the requirement to eliminate a federal right of first refusal would delay these potential 

cost-saving and efficiency benefits for all entities in the region for the duration of the 

stay. 

481 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 313.
Docket No. RM10-23-001 -300-

applicable to a local transmission facility.482 Additionally, the Commission explained 

that the reforms do not affect the right of an incumbent transmission provider to build, 

own, and recover costs for upgrades to its own transmission facilities, such as in the case 

of tower change outs or reconductoring, regardless of whether an upgrade has been 

selected in a regional transmission plan for purposes of cost allocation.483 The 

Commission further noted that the reforms are not intended to alter an incumbent 

transmission provider’s use and control of its existing rights-of-way, the retention, 

modification, or transfer of which remain subject to the relevant law or regulation that 

granted the right-of-way.484

393. In a separate section of Order No. 1000, the Commission stated that for purposes 

of Order No. 1000, “nonincumbent transmission developer” refers to two categories of 

transmission developer: “(1) a transmission developer that does not have a retail 

distribution service territory or footprint; and (2) a public utility transmission provider 

that proposes a transmission project outside of its existing retail distribution service 

territory or footprint, where it is not the incumbent for purposes of that project.” By 

contrast, the Commission explained that an “‘incumbent transmission 

 482 Id. P 318.

483 Id. P 319.

484 Id.
Docket No. RM10-23-001 -301-

developer/provider’ is an entity that develops a transmission project within its own retail 

distribution service territory or footprint.”485

394. The Commission also distinguished between a transmission facility in a regional 

transmission plan and a transmission facility selected in a regional transmission plan for 

purposes of cost allocation.486 The Commission also defined the term “local transmission 

facility,” which it stated is a transmission facility located solely within a public utility’s 

retail distribution service territory or footprint that is not selected in the regional 

transmission plan for purposes of cost allocation.487

b. Requests for Rehearing and Clarification

395. Several petitioners seek rehearing or clarification regarding the implementation of 

the removal of a federal right of first refusal for projects that are selected in the regional 

transmission plan for purposes of cost allocation.488 Northern Tier Transmission Group 

requests that the Commission clarify the types of Commission-jurisdictional agreements 

that are subject to Order No. 1000’s federal right of first refusal prohibition as well as the 

types of provisions that constitute federal rights of first refusal. Northern Tier 

 485 Id. P 225.

486 Id. PP 63-66. 

487 Id. PP 63-64.

488 See, e.g., Northern Tier Transmission Group; Duke; AEP; AEP; Sunflower, 

Mid-Kansas, and Western Farmers; and Dayton Power and Light.
Docket No. RM10-23-001 -302-

Transmission Group asserts that these clarifications are necessary to determine which 

bilateral agreements are affected by the rule and the types of provisions that are 

prohibited in future contracts. In addition, Northern Tier Transmission Group argues that 

the modification of bilateral agreements undermines the balance of the agreements, and 

therefore must be accomplished in accordance with relevant Commission precedent.

396. Some petitioners seek clarification of what Order No. 1000 intends when referring 

to “nonincumbent transmission developer” and “incumbent transmission 

developer/provider.”489 Transmission Access Policy Study Group and APPA state that 

the definitions of nonincumbent transmission developer and incumbent transmission 

developer/provider would exclude most municipal electric systems and electric 

cooperatives, as well as other public power entities. For example, Transmission Access 

Policy Study Group and APPA argue that because most non-public utility transmission 

developers have retail distribution service territories, they would not qualify as 

nonincumbent transmission developers under the first part of the definition. They also 

argue that non-public utility transmission providers, as defined in section 201(f) of the 

FPA, are not public utilities under FPA section 201(e); thus they would not qualify as 

nonincumbent transmission developers under the second part of the definition. 

Transmission Access Policy Study Group believes that this limitation was inadvertent 

 489 See, e.g., Transmission Access Policy Study Group; and APPA.
Docket No. RM10-23-001 -303-

and that the Commission should correct this error while at the same time keeping in mind 

that some references to “nonincumbent transmission developer” may in fact be intended 

to apply only to jurisdictional entities.

397. APPA notes that Order No. 1000 at P 227 requires incumbent transmission 

developers/providers to develop a framework that includes provisions regarding how best 

to address participation by nonincumbent transmission developers. Therefore, APPA and 

Transmission Access Policy Study Group are concerned that, if non-public entities do not 

qualify as nonincumbent transmission developers, incumbent transmission providers will 

not include provisions to address their participation. Accordingly, they ask the

Commission to make clear that non-public utility transmission developers can be 

considered nonincumbent transmission developers.

398. APPA also argues that, given these definitions, incumbent transmission 

developers/providers may develop a framework that prevents public power utilities from 

participating in joint ownership of regional transmission projects. On rehearing, APPA 

requests that the Commission clarify that this result was not intended and that the 

Commission revise the relevant definitions to allow for participation by public power 

entities in transmission projects. Otherwise, APPA requests rehearing of this issue on the 

grounds that the definitions are unduly discriminatory as applied to public power utilities 

and preferential as applied to public utilities and other for-profit entities, in violation of 

sections 205 and 206 of the FPA.
Docket No. RM10-23-001 -304-

399. Some petitioners seek guidance or clarification regarding the term “footprint” as it 

is used in the definitions of a “local transmission facility” and “incumbent transmission 

developer.”490 American Transmission and ITC Companies interpret the term footprint 

to be directed at entities, such as transmission-only companies, that do not have retail 

distribution service territories, and thus expands the definitions of an incumbent and a 

local transmission facility instead of further defining retail distribution service territory.

If the Commission instead clarifies that the term is intended to further define retail 

distribution service territory, then American Transmission seeks rehearing of the 

definition of incumbent transmission developer, arguing that it is arbitrary and capricious 

and discriminatory to exclude transmission-only companies from the definition. It argues 

that it should be considered an incumbent because it is subject to the mandatory NERC 

reliability standards for its facilities. As for the definition of a local transmission facility, 

ITC Companies state that they have no local transmission plans and that all transmission 

projects they propose are evaluated and included under the MISO or SPP Transmission 

Expansion Plans and are not “merely rolled up.” However, ITC Companies state that 

these projects may be located solely within the footprint of one or more of the ITC 

Companies.

 490 See, e.g., ITC Companies; LS Power; American Transmission; Wisconsin PSC; 

and Edison Electric Institute.
Docket No. RM10-23-001 -305-

400. Wisconsin PSC adds that American Transmission, for example, is effectively an 

incumbent transmission provider with a footprint equivalent to the aggregate franchise 

territories of its wholesale load-serving entity customers. Wisconsin PSC asserts that 

categorizing American Transmission as a nonincumbent transmission developer would 

treat it as a merchant transmission developer in its home territory of the last ten years and 

compel it to double up on the essentially local planning processes as if it was a merchant, 

even though it currently conducts regional planning in coordination with MISO’s 

regional planning. Wisconsin PSC asserts that the extra costs from such duplicative 

planning would be unjust and unreasonable and therefore it requests that the Commission 

clarify the categorization of nonincumbent transmission developer to exclude 

transmission-only entities.

401. Duke seeks confirmation that a nonincumbent transmission developer either 

becomes an incumbent transmission developer/provider when its project is energized, if 

not sooner, or that the provisions of paragraph 319 of Order No. 1000, relating to 

upgrades and use of rights-of-way, apply to nonincumbents that construct projects. Also, 

according to Duke, the term “retail distribution,” as used in the definitions of 

nonincumbent transmission developer and incumbent transmission developer/provider, 

modifies “service territory” but not “footprint.” Thus, Duke contends that, under this 

interpretation, the nonincumbent developer of an actual project will eventually have a 

footprint and thus become an incumbent as to that limited footprint. However, if the 
Docket No. RM10-23-001 -306-

Commission clarifies that nonincumbents never become incumbents, then it requests that 

the Commission nonetheless grant nonincumbents the same rights described in paragraph 

319 of Order No. 1000 as to its own facilities and rights of way and describe when those 

rights would exist. It recommends that a nonincumbent obtains a federal right of first 

refusal no later than energization of its facilities. At a minimum, Duke requests detailed 

clarification on this issue so as to avoid litigation on compliance.

402. Edison Electric Institute seeks clarification that public utility transmission 

providers constructing new facilities in their “footprint” pursuant to service obligations 

imposed on them under federal, state, or local law or under long-term contracts are 

included in the definition of incumbent transmission providers. It notes that some 

transmission facility-owning public utilities may lack a retail distribution service 

territory, and that other transmission facility-owning public utilities with retail 

distribution service territories may need to construct new transmission facilities that are 

not fully contained within those retail distribution territories. Thus, it seeks clarification 

that both kinds of transmission facility-owning public utilities continue to have the same 

right to construct reliability projects not subject to regional cost allocation where 

necessary to meet their reliability needs or service obligations. It also seeks confirmation 

that the use of the term “footprint” is intended to capture new facility construction that 

may be separate from a retail distribution service territory but is nonetheless being 

constructed by an incumbent transmission owning utility to meet reliability or service 
Docket No. RM10-23-001 -307-

obligation needs, adding that this clarification would tie the right of an incumbent 

transmission provider to choose to build facilities not submitted for regional cost 

allocation to the existence of a service obligation under federal, state, or local law or 

under long-term contracts. To the extent that the Commission intended to grant this right 

in favor of some public utility transmission provider service obligations and not others, 

Edison Electric Institute argues that the Commission is required to explain and justify its 

decision.

403. Other petitioners request clarification or rehearing as to how to determine whether 

a project is considered a regional or local project.491 For instance, LS Power requests 

clarification of how the Commission intends to apply this local exemption. LS Power 

states that the Commission did not explain how a footprint might differ from a retail 

distribution area, which may have a different meaning in different states. Also, LS Power 

states that while a retail distribution area is a familiar concept, it does not provide a 

geographic-based definition. For example, a utility may own a transmission line that 

geographically extends beyond its retail service area that it may believe should be part of 

its footprint, but that line may cross into another transmission provider’s geographical 

retail distribution area which the other transmission provider considers to be part of its 

footprint. LS Power also states that joint ownership of a substation or transmission line is 

 491 See, e.g., Duke; and AEP.
Docket No. RM10-23-001 -308-

common, where several entities all have rights to use the capacity of the line. LS Power 

also claims that it is unclear how this definition would be applied in the context of an 

RTO, where the transmission provider’s footprint covers the entire region.

404. Accordingly, LS Power requests clarification that within and outside an RTO, a 

“local transmission facility” is one that is located within the geographical boundaries of 

the retail distribution service territory served by the public utility transmission provider as 

of the effective date of Order No. 1000 and interconnecting solely to the public utility 

transmission provider’s existing facilities. LS Power continues that where there are 

affiliated public utility transmission providers located in adjacent and electrically 

connected geographic areas, they may be treated as a single transmission owner only if, 

as of the date Order No. 1000 became effective, the affiliates have, in the past, conducted 

joint planning and maintained a single transmission rate applicable to service provided by 

all such affiliates regardless of the customer’s location within the retail distribution area 

of a single affiliate and, where located in a RTO, proffered a single local plan to the RTO 

and participated in RTO affairs as a single transmission owner (e.g., voting rights under 

all jurisdictional agreements). LS Power further states that any projects connecting, in 

whole or in part, to facilities owned by another transmission owner or to jointly owned 

facilities would not constitute local facilities. Last, it argues that “local” should be 

defined as of the effective date of Order No. 1000, because the area in which an 
Docket No. RM10-23-001 -309-

incumbent transmission owner can claim an exemption to the elimination of the federal 

right of first refusal should not be the subject of corporate structuring.

405. Duke asserts that the primary difficulty in differentiating regional and local 

projects is that there are many ways to interpret the phrase “transmission facilities 

selected in a regional transmission plan for purposes of cost allocation.” According to 

Duke, many RTOs have adopted cost allocation approaches for all types of projects and 

that even local projects ultimately are included in the “regional plan.” In addition, Duke 

asserts that a pricing zone that consists of the retail distribution service territory of a 

single load-serving entity that was also a transmission provider is an anomaly, and that it 

is more likely that a typical pricing zone will consist of a public utility transmission 

provider and more than one retail load-serving entity with a service territory, such as, for 

instance, a non-jurisdictional distribution and/or transmission company. Accordingly, 

Duke seeks clarification that, under a zonal approach to cost allocation, a facility whose 

costs are allocated under an RTO tariff to a single RTO pricing zone, and which is 

located in that pricing zone, be deemed a local facility. 

406. Duke also adds that, under a non-RTO model or dominant provider model, all the 

load in a single zone would be network load of the public utility transmission provider, 

with any other transmission owners receiving credits for their integrated transmission 

facilities. Accordingly, Duke requests clarification that the Commission intended that 

single zone facilities may be classified as local facilities, as long as the general construct 
Docket No. RM10-23-001 -310-

under a non-RTO model, or dominant provider model, is met. Duke adds that any 

proposals for ‘re-zoning’ meant to evade the impact of the removal of a federal right of 

first refusal can be addressed on compliance. If the Commission clarifies that a single 

zone facility under no circumstances can be a local facility, then Duke asserts that the 

Commission would effectively obliterate the federal right of first refusal in virtually 

every ISO and RTO, which could cause significant exoduses from ISOs and RTOs or 

cause ISOs and RTOs to completely overhaul their entire cost allocation processes.

407. Petitioners also seek clarification that a project that is selected in the plan, but for 

which the costs are assigned to a single utility, is considered a local facility for purposes 

of the applicability of the requirement to remove the federal right of first refusal. 492 

Specifically, Duke asks whether the focus is on the result of a cost allocation method or 

the area over which the method is applied such as an entire region. Duke urges the 

Commission to adopt the results approach, and clarify that if any cost allocation approach 

results in a single zone being allocated the costs of a facility, then an RTO should be 

permitted to deem the facility as local and therefore, apply a federal right of first refusal. 

Duke seeks clarification that facilities that have any costs allocated outside a single zone, 

even if such facilities are physically in a single zone, will be presumed to be regional, 

unless they are an upgrade to existing facilities.

 492 See, e.g., Duke; AEP; and Dayton Power and Light.
Docket No. RM10-23-001 -311-

408. Dayton Power and Light also asserts that the Commission should clarify that when 

all of a facility’s costs are assigned to a single utility zone, the tariff could continue to 

permit a federal right of first refusal. However, Dayton Power and Light also seeks 

clarification as to whether a facility that is allocated solely to one utility zone using a 

regional cost allocation method should be treated differently for purposes of a federal 

right of first refusal from a facility that is allocated predominately to one utility zone, and 

if so, where the break-point should be. Sunflower, Mid-Kansas, and Western Farmers 

seek clarification (or, alternatively, rehearing) that the definition of “regionally funded” 

excludes projects where costs allocated to a region are not at least a majority of the total 

costs.

409. In addition, ITC Companies and Xcel request clarification of “selected in a 

regional transmission plan for purposes of cost allocation” as it applies to the 

transmission facilities that are approved by MISO under its MISO Transmission 

Expansion Plan or by SPP under its SPP Transmission Expansion Plan.493 Xcel states 

that Order No. 1000 creates ambiguity by assuming that the cost allocation for local zone 

projects, such as in MISO and SPP, is not identified in the regional RTO tariff process.494 

 493 ITC Companies; Xcel at 20 (citing Order No. 1000, FERC Stats. & Regs. ¶ 

31,323 at n.299).

494 Xcel at 20 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at n.299).
Docket No. RM10-23-001 -312-

Xcel states that it believes that, under Order No. 1000, the costs for a project selected in 

the MTEP or STEP may permissibly be assigned to a single zone, whether that zone 

includes the facilities of a single transmission owner or whether a transmission owner has 

facilities that are included in other zones, through a regional cost allocation method, and 

that such an allocation is not precluded by Order No. 1000.

410. ITC Companies argue that MISO cost allocation methods fall along a continuum 

that on one end includes 100 percent allocation on a systemwide basis for multi-value 

projects, and on the other end are participant funded projects assumed by project 

sponsors. They state that in SPP 100 percent of the costs of Base Plan Upgrades 300kV 

and above are allocated to a regionwide annual transmission revenue requirement and 

recovered through a regionwide charge. They thus assert that it is unclear whether 

certain projects would be considered “transmission facilities selected...for purposes of 

cost allocation” under Order No. 1000.495 ITC Companies request clarification that this 

term means those projects approved in a regional transmission plan and which are also 

approved for 100 percent regional cost allocation. They argue that if the Commission 

does not clarify this term, if a project becomes ineligible for federal rights of first refusal 

 495 ITC Companies specifically ask about the following: (1) MISO Baseline 

Reliability Projects eligible for 20 percent regional cost allocation but whose costs can be 

100 percent allocated to the host zone pursuant to power flow modeling; (2) MISO 

Market Efficiency Projects eligible for 20 percent regional cost allocation; and (3) SPP 

Base Plan Upgrades eligible for 33 percent regional cost allocation.
Docket No. RM10-23-001 -313-

when any of the costs of that project are borne by customers beyond the local zone or 

footprint in which that project is located, the construction of more efficient, cost-effective 

multi-purpose projects with broad regional benefits will be discouraged. They maintain 

that incumbent transmission owners will oppose projects with broader benefits in favor of 

less efficient projects for which their rights of first refusal are preserved. They assert that 

projects will be designed to avoid minor enhancements that would benefit a region, but 

which would not justify a stand-alone, purely economic project.

411. On the other hand, Western Independent Transmission Group argues that the 

Commission failed to provide a reasoned explanation of why it did not remove the federal 

right of first refusal for local transmission facilities, and why it is not unduly 

discriminatory or preferential to uphold the federal right of first refusal for facilities not 

in a plan for purposes of cost allocation. Western Independent Transmission Group also 

argues that Order No. 1000 did not address in adequate detail the boundary between 

transmission projects for which independent transmission developers have a right to 

compete, and those projects that are reserved solely to the incumbent transmission 

provider. According to Western Independent Transmission Group, the most obvious 

instance where the Commission’s failure to address the subject may have significant 

competitive impacts on transmission planning is the distinction between public policy 

projects and transmission projects initiated through the generation interconnection 

process. Western Independent Transmission Group argues that, particularly in 
Docket No. RM10-23-001 -314-

California, where the vast majority of approved transmission projects in the most recent 

2010/2011 planning cycle were initiated through the generator interconnection process, 

the Commission’s unwillingness to address this issue effectively left incumbent utilities 

with a total monopoly over the transmission built in response to renewable energy 

development.

412. Petitioners also seek clarification of what is to be considered an upgrade to an 

existing transmission facility such that the elimination of the federal right of first refusal 

does not apply. For example, Duke seeks clarification that if an incumbent transmission 

owner cuts into its own existing transmission line to construct a new 345 kV substation 

that is needed for stability due to local growth on its system, such a substation, even if a 

share of its costs are allocated to all pricing zones in a region, would be covered by the 

federal right of first refusal under the “upgrades to its own transmission facilities” carve 

out. If not, then Duke asserts that a region should be able to take this policy into account 

in implementing Order No. 1000, such that a region could alter its cost allocation method 

so that the type of project described above is not subject to any regional cost allocation if 

the region decides such projects merit a federal right of first refusal. 

413. Similarly, ITC Companies seek clarification that the prohibition on a federal right 

of first refusal does not apply to a transmission upgrade that requires expansion of an 

existing right-of-way in order to be expanded. ITC Companies argue that retaining a 

federal right of first refusal for upgrades that require an expansion of an existing right of 
Docket No. RM10-23-001 -315-

way is necessary to avoid unintended and adverse consequences that would undermine 

the optimal and cost-effective development of the grid.

414. Finally, petitioners also request rehearing of the Commission’s decision to 

eliminate incumbent utility transmission providers’ existing rights to construct reliability 

projects.496 Xcel believes that incumbent transmission providers, particularly franchised 

utilities with an obligation to serve, should retain the right to construct transmission 

projects necessary for the utility to provide reliable service to their native load customers 

and to comply with NERC mandatory reliability standards. Xcel asserts that this federal 

right of first refusal does not need to be unlimited and supports the inclusion of a 90-day

election period during which the incumbent transmission provider would be required to 

indicate its decision to move forward with the designated project. Xcel contends that the 

Commission’s attempt to address utility providers’ concerns by eliminating certain 

penalty responsibilities fails to recognize that utilities have an obligation to serve and are 

not merely worried about financial penalties.

c. Commission Determination

415. We affirm the decision in Order No. 1000 to require the elimination of a federal 

right of first refusal from Commission-jurisdictional tariffs and agreements for 

transmission facilities selected in a regional transmission plan for purposes of cost 

 496 See, e.g., Xcel; and Edison Electric Institute.
Docket No. RM10-23-001 -316-

allocation. In response to Northern Tier Transmission Group, the phrase “a federal right 

of first refusal” refers only to rights of first refusal that are created by provisions in 

Commission-jurisdictional tariffs or agreements.497

416. In response to petitioners’ concerns, we also clarify several of the terms used in 

Order No. 1000, starting with the term “nonincumbent transmission developer.” In doing 

so, we first affirm the definition of incumbent transmission developer/provider as “an 

entity that develops a transmission project within its own retail distribution service 

territory or footprint.”498 Given this definition, we clarify that a “nonincumbent 

transmission developer” is any entity that is not an incumbent transmission 

developer/provider. We believe that this clarification, along with the others made in this 

order, addresses the concerns expressed by Transmission Access Policy Study Group and 

APPA that the definitions of nonincumbent transmission developer and incumbent 

transmission developer/provider in Order No. 1000 would exclude certain municipal 

electric systems and electric cooperatives, as well as other public power entities.

417. However, as discussed more fully below, we find that in order for a non-public 

utility to be considered a nonincumbent transmission developer, it must satisfy the 

enrollment requirement if it or an affiliate has load in the transmission planning region 

 497 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 253 n.231.

498 Id. P 225.
Docket No. RM10-23-001 -317-

where it proposes a transmission project for selection in the regional transmission plan 

for purposes of cost allocation as would any other potential transmission developer.499 

As an initial matter, we note that the Commission did not intend through its definition of 

nonincumbent transmission developer in Order No. 1000 to exclude any transmission 

developer, including a non-public utility transmission developer, from being able to 

propose transmission projects and have them evaluated and selected by a regional 

transmission planning process for purposes of cost allocation, so long as that transmission 

developer abides by the same requirements as those imposed on public utility 

transmission providers. Allowing entities, such as non-public utility transmission 

developers, the opportunity to potentially propose a transmission project as a 

nonincumbent transmission developer furthers the Commission’s goal in Order No. 1000 

of ensuring that all transmission developers have a comparable opportunity to incumbent 

transmission developers/providers to propose a transmission project for selection in the 

regional transmission plan for purposes of cost allocation. 

418. However, we also recognize that it would be fundamentally unfair and thereby 

may lead to an unjust and unreasonable or unduly discriminatory or preferential result to 

 499 We refer to non-public utility entities that seek to propose projects in a regional 

transmission planning process as “non-public utility transmission developers,” which 

may include both non-public utility transmission providers that already own and operate 

transmission facilities and transmission-dependent non-public utilities that may wish to 

develop, construct, or own transmission facilities in the future. 
Docket No. RM10-23-001 -318-

allow a transmission developer, whether it is a public utility transmission developer or a 

non-public utility transmission developer, to seek regional cost allocation for a proposed 

transmission project in a transmission planning region in which it or an affiliate has load, 

but where neither it, nor that affiliate, has enrolled in that region where its load is located. 

Such a result would permit a transmission developer to allocate the costs of its project to 

other entities in the region pursuant to that region’s cost allocation method – without first 

enrolling itself or its affiliate in the transmission planning region in which its load is 

located and potentially being allocated costs for other transmission projects for which it is 

found to be a beneficiary.500 

419. Therefore, Order No. 1000’s reforms regarding the submission and evaluation of 

proposals for potential selection in a regional transmission plan for purposes of cost 

allocation will apply to a transmission developer that has load or an affiliate within an 

area that would normally be considered a geographic part of a transmission planning 

region if the transmission developer or its affiliate transmission provider in that area 

enrolls in the transmission planning region in which that load is located. We believe that 

in most cases, it should be clear where an entity’s load is located and therefore the region 

in which it would be expected to enroll. However, should disputes arise over the choice 

 500 For discussion of enrolling in a transmission planning region, see the Regional 

Transmission Planning Requirements section. See discussion supra at section III.A.2.c.
Docket No. RM10-23-001 -319-

of a region, we will address them on a case-by-case basis utilizing the standard found in 

Order No. 890 and Order No. 1000, which provides that “the scope of a transmission 

planning region should be governed by the integrated nature of the regional power grid 

and the particular reliability and resource issues affecting individual regions.”501 We 

emphasize that an entity, including a non-public utility transmission developer, that does 

not have load within a transmission planning region may propose a transmission project 

for evaluation and potential selection in that region’s transmission plan for purposes of 

cost allocation without enrolling in that region, as long as it satisfies the transmission 

planning region’s other requirements for doing so, such as meeting the qualification 

criteria for proposing projects found in Order No. 1000. 

420. Turning to other terms used in Order No. 1000, we also clarify that the phrase 

“retail distribution,” as used in the definitions of incumbent transmission 

developer/provider, nonincumbent transmission developer and local transmission facility, 

does not modify footprint. Instead, the term “footprint,” as used in these definitions was 

intended to include, but not be limited to, the location of the transmission facilities of a 

transmission-only company that owns and/or controls the transmission facilities of 

 501 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 160 (citing Order No. 890, 

FERC Stats. & Regs. ¶ 31,241 at P 527).
Docket No. RM10-23-001 -320-

formerly vertically-integrated utilities, as well as the location of the transmission facilities 

of any other transmission-only company. 

421. In response to Duke, we agree that a nonincumbent transmission developer will 

have a footprint at the time that its transmission facility is energized. As such, we clarify 

that a nonincumbent transmission developer will then become an incumbent transmission 

developer/provider for that energized transmission facility and will thereafter have all the 

rights and obligations that accrue to such entities under Order No. 1000, such as being 

able to maintain a federal right of first refusal for local transmission facilities and 

upgrades to those transmission facilities.

422. In response to Edison Electric Institute, we note that there are a great variety of 

fact patterns that may fall under its request. For example, Edison Electric Institute does 

not explain whether the new transmission facility would go through the retail distribution 

service territory of the incumbent transmission owning utility, that of another entity, or an 

“unassigned” territory. Thus, we decline to find generically that any particular 

transmission facility, whether it is needed to meet a reliability, economic, or transmission 

need driven by a Public Policy Requirement, developed outside of an existing retail 

distribution service territory or footprint, should be considered a part of that entity’s 

footprint.

423. We clarify that Order No. 1000 does not require elimination of a federal right of 

first refusal for a new transmission facility if the regional cost allocation method results 
Docket No. RM10-23-001 -321-

in 100% of the facility’s cost being allocated to the public utility transmission provider in 

whose retail distribution service territory or footprint the facility is to be located. 

Accordingly, we clarify that the term “selected in a regional transmission plan for 

purposes of cost allocation” excludes a new transmission facility if the costs of that 

facility are borne entirely by the public utility transmission provider in whose retail 

distribution service territory or footprint that new transmission facility is to be located. 

Although public utility transmission providers in a transmission planning region may 

determine, based on non-discriminatory evaluation criteria, that a proposed transmission 

facility is likely to have regional benefits so that the transmission facility’s costs should 

be allocated regionally, it is not until the cost allocation method is applied that the 

beneficiaries are identified. 

424. Petitioners request clarification about whether a transmission facility is a local 

transmission facility if it is selected in a regional transmission plan for purposes of cost 

allocation and the costs are allocated to a single pricing zone in which the proposed 

transmission facility is to be located, and that zone consists of more than one 

transmission provider. In general, any regional allocation of the cost of a new 

transmission facility outside a single transmission provider’s retail distribution service 

territory or footprint, including an allocation to a “zone” consisting of more than one 

transmission provider, is an application of the regional cost allocation method and that 

new transmission facility is not a local transmission facility. For example, transmission-
Docket No. RM10-23-001 -322-

owning members of an RTO may not retain a federal right of first refusal by dividing the 

RTO into East and West multi-utility zones and allocating costs just within one zone 

consisting of more than one transmission provider. However, we recognize in response 

to Duke’s request that special consideration is needed when a small transmission provider 

is located within the footprint of another transmission provider. For instance, a regional 

cost allocation method might allocate costs to an area consisting of one transmission 

provider that has within its borders one or more smaller utilities that largely depend on its 

transmission system but nevertheless own a little transmission of their own, so that they 

too are transmission providers. This situation is not necessarily “a zone consisting of 

more than one transmission provider” as this term is used in this order. If the cost of a 

new transmission facility is allocated entirely to an area consisting of one transmission 

provider that has one or more smaller transmission providers within its borders, this 

might qualify as a local cost allocation, not a regional cost allocation. However, as 

petitioners point out, there may be a continuum of examples that range from (i) one small 

municipality with a single small transmission facility located within a transmission 

provider’s footprint, to (ii) a “zone” consisting of many public utility and nonpublic 

utility transmission providers. Accordingly, we will address whether a cost allocation to 

a multi-transmission provider zone is regional on a case-by-case basis based on the 

specific facts presented. Specific situations may be included in a compliance filing along 

with the filed regional cost allocation method or methods.
Docket No. RM10-23-001 -323-

425. We disagree with Western Independent Transmission Group’s assertion that the 

Commission failed to provide a reasoned explanation of its decision not to require the 

elimination of a federal right of first refusal for local transmission facilities. In Order No. 

1000, the Commission recognized that incumbent transmission providers may have 

reliability needs or service obligations.502 Accordingly, Order No. 1000 does not prevent 

an incumbent transmission provider from meeting its reliability needs or service 

obligations by choosing to build new transmission facilities that are located solely within 

its retail distribution service territory or footprint and that are not selected in a regional 

transmission plan for purposes of cost allocation.503 Thus, we affirm the decision in 

Order No. 1000 not to require elimination from Commission-jurisdictional tariffs and 

agreements a federal right of first for a local transmission facility.504 We also note in 

response to Western Independent Transmission Group that the Commission found that 

issues related to the generator interconnection process and to interconnection cost 

 502 Id. P 262. The Commission defined a local transmission facility as a 

transmission facility located solely within a public utility transmission provider’s retail 

distribution service territory or footprint that is not selected in a regional transmission 

plan for purposes of cost allocation. An incumbent transmission provider would retain 

the option of meeting its local reliability needs or obligations to serve by building a 

transmission facility in its retail distribution service territory or footprint. Id. at P 63. 

503 Id. In P 262 of Order No. 1000, the Commission used the term “submitted for 

regional cost allocation” where we intended “selected in a regional transmission plan for 

purposes of cost allocation.” We provide that clarification here.

504 Id. P 318.
Docket No. RM10-23-001 -324-

recovery were outside the scope of Order No. 1000.505 Order No. 1000 did not establish 

any new requirements with respect to the generator interconnection process, and we are 

not persuaded to address the generator interconnection process on rehearing.

426. In response to requests for clarification regarding what the Commission considers 

to be an upgrade, we note that in Order No. 1000, the term upgrade means an 

improvement to, addition to, or replacement of a part of, an existing transmission facility. 

The term upgrades does not refer to an entirely new transmission facility. The concept is 

that there should not be a federally established monopoly over the development of an 

entirely new transmission facility that is selected in a regional transmission plan for 

purposes of cost allocation to others. However, neither is the Commission eliminating 

the right of an owner of a transmission facility to improve its own existing transmission 

facility by allowing a third-party transmission developer to, for example, propose to 

replace the towers or the conductors of a transmission line owned by another entity.506 It 

is not feasible, however, to list every type of improvement or addition, or name all the 

parts of lines, towers and other equipment that may be replaced or otherwise upgrades, 

and we will not do so here.

 505 Id. P 760.

506 Id. P 319.
Docket No. RM10-23-001 -325-

427. In response to ITC Companies, we clarify that the requirement to eliminate a 

federal right of first refusal does not apply to any upgrade, even where the upgrade 

requires the expansion of an existing right-of-way. The issue is not whether the upgrade 

would be located in an existing right-of-way, but whether the new transmission facility is 

an upgrade to an incumbent transmission provider’s own facilities. Furthermore, the 

Commission reiterates that the nonincumbent transmission developer reforms were not 

intended to alter an incumbent transmission provider’s use and control of its existing 

rights-of-way under state law.507 

428. We affirm the decision in Order No. 1000 to require the elimination of a federal 

right of first refusal for reliability projects. Allowing incumbent transmission providers 

to maintain a federal right of first refusal, even with a limited 90-day election period as 

proposed by Xcel, would discourage transmission developers from proposing 

transmission projects that may be a more efficient or cost-effective solution to meet 

regional transmission needs, resulting in rates for jurisdictional transmission services that 

are unjust and unreasonable or unduly discriminatory or preferential. The fact that a 

particular transmission facility is intended to meet a reliability need does not change our 

responsibility to eliminate practices that result in unjust and unreasonable or unduly 

discriminatory or preferential rates. Furthermore, Order No. 1000 includes several 

 507 Id.
Docket No. RM10-23-001 -326-

reforms that ensure that incumbent transmission providers will be able to satisfy their 

reliability needs and service obligations, even when they are relying on a nonincumbent 

transmission developer’s project to meet a reliability need. Specifically, Order No. 1000 

includes a reevaluation requirement that requires public utility transmission providers in a 

region to have procedures in place to identify when delays in the development of a 

transmission facility selected in a regional transmission plan for purposes of cost 

allocation require evaluation of alternative solutions to ensure that an incumbent 

transmission provider can meets its reliability needs or service obligations.508 Moreover, 

we note again that Order No. 1000 continues to permit an incumbent transmission 

provider to meet its reliability needs or service obligations by choosing to build new 

transmission facilities that are located solely within its retail distribution service territory 

or footprint and that are not selected in a regional transmission plan for purposes of cost 

allocation.509 Accordingly, we disagree with petitioners that argue that a federal right of 

first refusal for reliability project is necessary for incumbent transmission providers to 

meet reliability needs or service obligations. 

429. In response to LS Power’s concerns regarding the definition of a local 

transmission facility, we clarify that a local transmission facility is one that is located 

 508 Id. P 329.

509 Id. P 262.
Docket No. RM10-23-001 -327-

within the geographical boundaries of a public utility transmission provider’s retail 

distribution service territory, if it has one, otherwise the area is defined by the public 

utility transmission provider’s footprint. Thus, if the public utility transmission provider 

has a retail distribution service territory and/or footprint, then only a transmission facility 

that it decides to build within that retail distribution service territory or footprint, and that 

is not selected in a regional transmission plan for purposes of cost allocation, may be 

considered a local transmission facility. In the case of an RTO or ISO whose footprint 

covers the entire region, we clarify that local transmission facilities are defined by 

reference to the retail distribution service territories or footprints of its underlying 

transmission owing members. We also clarify that the extent of a public utility 

transmission provider’s retail distribution service territory or footprint is not to be 

measured as of the effective date of Order No. 1000, but is the retail distribution service 

territory or footprint in existence during the regional transmission planning cycle. We 

decline to provide any of the further clarifications regarding the definition of a local 

transmission facility as requested by LS Power and will address such matters during the 

compliance process based on a more complete record.

430. Finally, in response to petitioners’ concerns over which facilities are selected in a 

regional transmission plan for purposes of cost allocation, and for which a federal right of 

first refusal must therefore be eliminated, we clarify that if any costs of a new 

transmission facility are allocated regionally or outside of a public utility transmission 
Docket No. RM10-23-001 -328-

provider’s retail distribution service territory or footprint, then there can be no federal 

right of first refusal associated with such transmission facility, except as provided in this 

order.

3. Framework To Evaluate Transmission Projects Submitted for 

Selection in the Regional Plan for Purposes of Cost Allocation

431. In Order No. 1000, the Commission required each public utility transmission 

provider to revise its OATT to describe the features of an acceptable framework for 

project identification and selection. The Commission required that this framework 

include: (1) qualification criteria to submit a transmission project for selection in the 

regional transmission plan for purposes of cost allocation; (2) specification of the 

information that must be submitted by a prospective transmission developer in support of 

the transmission project it proposes in the regional transmission planning process and the 

date by which such information must be submitted to be considered in a given 

transmission planning cycle; (3) a description of a transparent and not unduly 

discriminatory process for evaluating whether to select a proposed transmission facility in 

the regional transmission plan for purposes of cost allocation; and (4) provisions allowing 

a nonincumbent transmission developer to have the same eligibility as an incumbent 

transmission provider to use a regional cost allocation method or methods for any 

sponsored transmission facility selected in the regional transmission plan for purposes of 

cost allocation. Last, the Commission declined to require public utility transmission 

providers to revise their OATTs to provide a transmission developer a right to construct 
Docket No. RM10-23-001 -329-

and own a transmission facility and also declined to allow a transmission developer to 

maintain for a defined period of time its right to build and own a transmission project that 

it proposed but that is not selected.510

a. Qualification Criteria To Submit a Transmission Project 

for Selection in the Regional Transmission Plan for 

Purposes of Cost Allocation

i. Final Rule

432. The Commission required each public utility transmission provider to revise its 

OATT to demonstrate that the regional transmission planning process in which it 

participates has established qualification criteria that are not unduly discriminatory or 

preferential for determining an entity’s eligibility to propose a transmission project for 

selection in the regional transmission plan for purposes of cost allocation, whether that 

entity is an incumbent transmission provider or a nonincumbent transmission 

developer.511 The Commission explained that the criteria must provide each potential 

transmission developer the opportunity to demonstrate that it has the necessary financial 

resources and technical expertise to develop, construct, own, operate, and maintain 

transmission facilities.512 The Commission found that one-size-fits-all qualification 

 510 Id. PP 323-40.

511 Id. P 323.

512 Id.
Docket No. RM10-23-001 -330-

criteria would not be appropriate, and that it is important for each transmission planning 

region to have the flexibility to formulate qualification criteria that best fits its 

transmission planning processes and addresses the particular needs of the region, so long 

as the criteria are fair and not unreasonably stringent when applied to either the 

incumbent transmission provider or a nonincumbent transmission developer.513

ii. Requests for Rehearing and Clarification

433. Several petitioners seek rehearing of the Commission’s requirement that the 

regional planning process develop qualification criteria.514 They assert that Order No. 

1000 creates an unreasonable disparity between who establishes the criteria for a 

nonincumbent to be deemed qualified to propose and construct a transmission project and 

who bears the risk if such nonincumbent does not perform.515 They state that each 

incumbent transmission provider remains responsible for meeting its reliability and 

system security obligations in the event that the nonincumbent fails to perform, but must 

rely on qualification criteria developed by the region planning process. They state that 

this disparity is unreasonable, arbitrary and capricious, and should be revised to be more 

consistent with the model provided for in Order No. 890-A, which allows the 

 513 Id. P 324.

514 See, e.g., Ad Hoc Coalition of Southeastern Utilities; and Southern Companies.

515 See, e.g., Ad Hoc Coalition of Southeastern Utilities; and Southern Companies.
Docket No. RM10-23-001 -331-

transmission provider to establish reasonable credit criteria.516 They also believe this 

would allow each incumbent transmission provider that bears the greatest risk of nonperformance of a nonincumbent to better manage such risk.517

434. Other petitioners request that the Commission standardize the qualification criteria 

or otherwise clarify that certain criteria are impermissible.518 NextEra argues that there 

should be a standardized qualification requirement rather than the flexible approach 

adopted in Order No. 1000 because it believes that such flexibility could permit 

incumbents to devise qualification criteria that create barriers to entry. NextEra states 

that, unlike other areas of Order No. 1000 that endorse flexibility, there is no reason to 

believe that financial and technical qualification criteria for new transmission entrants 

should vary by region. NextEra points to the Commission’s actions in standardizing 

generator interconnection procedures under Order No. 2003 and credit reform rules under 

Order No. 741. NextEra also suggests that the Commission look to the qualification 

criteria established by ERCOT and CAISO as examples. Alternatively, NextEra states 

 516 Ad Hoc Coalition of Southeastern Utilities at 62 (citing Order No. 890-A, 

Attachment L (Creditworthiness Procedures) to Pro Forma OATT; Order No. 890 at P 

1659); Southern Companies at 63 (citing Preventing Undue Discrimination and 

Preference in Transmission Serv., Order No. 890-A, 121 FERC ¶ 61, 297, Attachment L 

(2007)).

517 See, e.g., Ad Hoc Coalition of Southeastern Utilities; and Southern Companies. 

518 See, e.g., NextEra; LS Power; and New York Transmission Owners.
Docket No. RM10-23-001 -332-

that the Commission should initiate a negotiated rulemaking to develop consensus 

criteria, which it states is the course the Commission followed in developing Order No. 

2003. 

435. LS Power requests that the Commission clarify that the qualification criteria for 

entities that want to propose a project in the regional transmission planning process are 

limited to financial and technical matters. It also asks that the qualification criteria not 

operate as a barrier to entry and should not include a qualification that a new entrant be 

an existing public utility under state law or have upfront siting authority. It contends that 

a new entrant would not be able to achieve state public utility status at the assignment 

stage because it is most often granted after the assignment of the transmission project. 

LS Power similarly argues that the selection criteria used to evaluate a project also should 

not require that a project sponsor be an existing public utility under state law or have 

upfront siting authority before it can be assigned a project. LS Power contends that such 

selection criteria would also act as a barrier to entry in that states most often grant public 

utility status and eminent domain authority after the assignment of the transmission 

project.

436. APPA requests that the Commission require that the minimum participation 

criteria developed by incumbent transmission developers/providers be fair and not 

unreasonably stringent as applied to public power utilities.
Docket No. RM10-23-001 -333-

437. Transmission Access Policy Study Group seeks clarification that the qualification 

criteria facilitate transmission dependent utility joint ownership, and states that 

qualification criteria designed for proposals submitted by a single entity could 

unintentionally and needlessly foreclose beneficial project participation by multiple joint 

owners.

438. New York Transmission Owners request that transmission planning regions be 

permitted to require NERC registration for nonincumbent transmission developers as a 

precondition to being assigned a reliability project.

iii. Commission Determination

439. We affirm Order No. 1000’s requirement that the public utility transmission 

providers in each transmission planning region must establish, in consultation with 

stakeholders, appropriate qualification criteria for determining an entity’s eligibility to 

propose a transmission project for selection in the regional transmission plan for purposes 

of cost allocation. As required under Order No. 1000, these qualification criteria must 

not be unduly discriminatory or preferential and must provide each potential transmission 

developer the opportunity to demonstrate that it has the necessary financial resources and 

technical expertise to develop, construct, own, operate, and maintain transmission 

facilities.519 We disagree with petitioners that this approach creates an unreasonable 

 519 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 323.
Docket No. RM10-23-001 -334-

disparity between who establishes the criteria for a nonincumbent transmission developer 

to be deemed qualified to propose and construct a transmission project and who bears the 

risk if such nonincumbent transmission developer does not perform. Order No. 1000 

makes clear that it is public utility transmission providers themselves, in consultation 

with stakeholders, that are responsible for complying with Order No. 1000 and that must 

develop the qualification criteria for review by the Commission on compliance.520

440. The Commission declines to adopt standardized qualification criteria, as urged by 

NextEra. While the Commission’s acknowledges NextEra’s concern that qualification 

criteria could act as a barrier to entry, the Commission believes that there may be 

legitimate differences between regions that may justify differences in the qualification 

criteria. Each region is faced with its own set of challenges in building new transmission 

facilities, and regions should be permitted to account for those differences in their 

qualification criteria. For this same reason, the Commission will not adopt certain 

minimum qualification criteria. Regarding LS Power’s petition that the qualification 

criteria be limited to financial and technical matters, we point out that Order No. 1000 

 520 We reiterate that “the qualification criteria required [in Order No. 1000] should 

not be applied to an entity proposing a transmission project for consideration in the 

regional transmission planning process if that entity does not intend to develop the 

proposed transmission project. The Order No. 890 transmission planning requirements 

allow any stakeholder to request that the transmission provider perform an economic 

planning study or otherwise suggest consideration of a particular transmission solution in 

the regional transmission planning process.” Id. P 324 n.304.
Docket No. RM10-23-001 -335-

states that “[t]he qualification criteria must provide each potential transmission developer 

the opportunity to demonstrate that it has the necessary financial resources and technical 

expertise to develop, construct, own, operate and maintain transmission facilities,” but 

also permits each transmission planning region flexibility to formulate qualification 

criteria that best fit its transmission planning processes and addresses the particular needs 

of the region.521 

441. We clarify in response to LS Power that it would be an impermissible barrier to 

entry to require, as part of the qualification criteria, that a transmission developer 

demonstrate that it either has, or can obtain, state approvals necessary to operate in a 

state, including state public utility status and the right to eminent domain, to be eligible to 

propose a transmission facility. As the Commission emphasized in Order No. 1000, and 

reiterates here, the qualification criteria must be fair and not unreasonably stringent when 

applied to an incumbent transmission provider and a nonincumbent transmission 

developer.522 The Commission will review on compliance whether any proposed 

qualification criterion is unreasonably stringent when applied to nonincumbent 

transmission developers such that the criteria act as an unreasonable barrier to entry. 523 

 521 Id. PP 323-24.

522 Id. P 324.

523 Importantly, Order No. 1000 did not provide transmission developers with a 

(continued...)
Docket No. RM10-23-001 -336-

442. If a transmission facility is selected in the regional transmission plan for purposes 

of cost allocation, the Commission clarifies that the transmission developer of that 

transmission facility must submit a development schedule that indicates the required 

steps, such as the granting of state approvals, necessary to develop and construct the 

transmission facility such that it meets the transmission needs of the region. As part of 

the ongoing monitoring of the progress of the transmission project once it is selected, the 

public utility transmission providers in a transmission planning region must establish a 

date by which state approvals to construct must have been achieved that is tied to when 

construction must begin to timely meet the need that the project is selected to address. If 

such critical steps have not been achieved by that date, then the public utility 

transmission providers in a transmission planning region may remove the transmission 

project from the selected category and proceed with reevaluating the regional 

transmission plan to seek an alternative solution.

443. We believe that there are a number of benefits to this approach. First, it ensures 

that transmission developers that have the technical and financial capability to build a 

transmission facility, and meet other nondiscriminatory and non-preferential criteria, are 

 

right to construct; rather, it required “that a nonincumbent transmission developer must 

have the same eligibility as an incumbent transmission developer to use a regional cost 

allocation method or methods for any sponsored transmission facility selected in the 

regional transmission plan for purposes of cost allocation.” See id. P 332.
Docket No. RM10-23-001 -337-

eligible to propose a transmission facility for evaluation and selection, thereby increasing 

the universe of potential facilities evaluated and selected to meet a region’s transmission 

needs. Second, it gives a nonincumbent transmission developer the opportunity to 

propose a transmission facility while it seeks to obtain necessary state approvals or 

otherwise seeks to comply with applicable state law or regulation. Third, it provides the 

public utility transmission providers in a transmission planning region with the ability to 

monitor the development of a transmission facility selected in the regional transmission 

plan for purposes of cost allocation, as well as the ability to remove that new transmission 

facility if its developer is unable to meet an established date by which the critical 

development step of obtaining necessary state approvals must be achieved.

444. We also deny New York Transmission Owners’ request that the public utility 

transmission providers in a transmission planning region be permitted to require a 

transmission developer to demonstrate that it has registered with NERC as a precondition 

to being assigned a reliability project. As the Commission explained in Order No. 1000, 

all entities that are users, owners or operators of the electric bulk power system must 

register with NERC for performance of applicable reliability functions.524 The 

procedures for registering as a Functional Entity are set by NERC and approved-by the 

 524 Id. P 342.
Docket No. RM10-23-001 -338-

Commission under section 215,525 and it is not appropriate for the Commission to amend 

or interpret those procedures here under a section 206 action by requiring all public utility 

transmission providers to revise their tariffs to provide that a potential transmission 

developer must register with NERC if not otherwise required under the NERC 

procedures, merely to be eligible to propose a transmission project for selection in the 

regional transmission plan for purposes of cost allocation.

b. Evaluation of Proposals for Selection in the Regional 

Transmission Plan for Purposes of Cost Allocation

i. Final Rule

445. The Commission required each public utility transmission provider to amend its 

OATT to describe a transparent and not unduly discriminatory process for evaluating 

whether to select a proposed transmission facility in the regional transmission plan for 

purposes of cost allocation.526 The Commission explained that this process must comply 

with the Order No. 890 transmission planning principles, ensuring transparency, and the 

opportunity for stakeholder coordination. The Commission further explained that the 

evaluation process must culminate in a determination that is sufficiently detailed for 

stakeholders to understand why a particular transmission project was selected or not 

 525 NERC, Rules of Procedures (effective March 15, 2012), available at

http://www.nerc.com/files/NERC_ROP_Effective_20120315.pdf.

526 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 328.
Docket No. RM10-23-001 -339-

selected in the regional transmission plan for purposes of cost allocation.527 Finally, the 

Commission declined to require public utility transmission providers to revise their 

OATTs to provide a right to construct and own a transmission facility and also declined 

to allow a transmission developer to maintain for a defined period of time its right to 

build and own a transmission project that it proposed but that was not selected.528 

ii. Requests for Rehearing and Clarification

446. Western Independent Transmission Group seeks rehearing of the Commission’s 

rejection of its proposal to require the use of an independent third party observer to 

oversee evaluation and selection of competing transmission projects to ensure that the 

process is being managed fairly and efficiently.

447. Illinois Commerce Commission argues that it is necessary for the Commission to 

provide more specificity regarding the practical means by which transmission providers 

can facilitate competition between alternative proposals. It suggests that the transmission 

provider identify the planning needs to be met and then solicit developers to submit 

alternative plans to address those needs. Illinois Commerce Commission explains that 

this formalized process would provide a non-discriminatory and objective method for the 

 527 Id.

528 Id. P 338.
Docket No. RM10-23-001 -340-

transmission provider to evaluate alternative proposals, and argues that the Commission 

erred in not requiring such a process.

448. Similarly, FirstEnergy Service Company seeks clarification that regional 

transmission planning processes need only consider proposals that respond to identified 

needs, such that a “needs first” approach is acceptable. In support, FirstEnergy Service 

Company argues that a planning model that requires the regional planning process to 

analyze every individual proposal would render the process less manageable, timely, and 

effective. FirstEnergy Service Company also argues that, through Order No. 890, the 

Commission already has put in place the mechanisms necessary to encourage innovative 

transmission proposals.

449. LS Power requests that the Commission affirmatively clarify on rehearing that, if a 

region uses a sponsorship model for the assignment of projects, the regions must treat an 

application for a project by a nonincumbent transmission owner no differently from any 

other applicant, and that sponsors that meet nondiscriminatory sponsorship criteria are to 

be assigned construction and ownership of the projects they sponsor unless the regional 

planning entity adequately justifies assignment of the project to another entity, as PJM 

was required to do in the Primary Power case.

529 It states that without this explicit 

statement, some will attempt to assign projects to non-sponsor incumbent transmission 

 529 LS Power at 6 (Primary Power, LLC, 131 FERC ¶ 61,015, at P 65 (2010)).
Docket No. RM10-23-001 -341-

owners on the basis of an inaccurate reading of paragraph 338, where the Commission 

declined to adopt any right to construct or ongoing sponsorship rights.

450. LS Power also requests that the Commission clarify that in a region using a 

sponsorship model rather than a competitive bidding model, the process established by 

each public utility transmission provider must include a specific mechanism to select, in a 

nondiscriminatory manner, among competing qualified sponsors of identical projects, or, 

as a backstop if no mechanism is agreed upon, to assign such projects equally among 

qualified entities that have sponsored identical projects. It explains that to the extent that 

only one of the sponsors has sponsored the same project in an immediately prior planning 

cycle, that the entity should have preference over those entities newly sponsoring the 

project. LS Power further suggests that the Commission should include a provision for 

ongoing sponsorship rights, with some recognition or benefit to an entity for continuing 

to advocate viable projects, at least between the continuing sponsor and new sponsors of 

the same project. Additionally, LS Power states that another mechanism to select among 

multiple sponsors of identical projects is to select the entity that is willing to guarantee 

the lowest net present value of its annual revenue requirement.

451. In addition, LS Power requests that the Commission clarify that to meet the “not 

unduly discriminatory process” requirement, the selection criteria must meet certain 

minimum standards. It states that the Commission should clarify that when cost 
Docket No. RM10-23-001 -342-

estimates are part of selection criteria, costs must be scrutinized in an equal manner 

whether the project is sponsored by an incumbent or independent. 

iii. Commission Determination

452. The Commission affirms the decision in Order No. 1000 to require each public 

utility transmission provider to amend its OATT to describe a transparent and not unduly 

discriminatory process for evaluating whether to select a proposed transmission facility in 

a regional transmission plan for purposes of cost allocation.530 We also affirm the 

Commission’s decision not to require public utility transmission providers to use an 

independent third party observer to oversee the evaluation and selection of competing 

transmission projects. In Order No. 1000, the Commission encouraged public utility 

transmission providers to consider ways to minimize disputes, such as through additional 

transparency mechanisms.531 However, the Commission did not mandate any particular 

approach, and is not persuaded now that an independent third party observer is necessary 

or appropriate in all regions. Moreover, the Commission noted that the requirements of 

the dispute resolution principle of Order No. 890 apply to the regional transmission 

planning process.532 Thus, if a dispute cannot be resolved by public utility transmission 

 530 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 328.

531 Id. P 330.

532 Id. P 330 n.306.
Docket No. RM10-23-001 -343-

providers in the regional transmission planning process, entities may take advantage of 

that transmission planning region’s dispute resolution provision. Additionally, as noted 

in Order No. 1000, public utility transmission providers in consultation with other 

stakeholders in a region may, if they choose, propose to use an independent third-party 

observer and we will review any such proposal on compliance.533

453. While Order No. 1000 permits the public utility transmission providers in a region 

to adopt a “needs first” approach to transmission planning such as that advocated by the 

Illinois Commerce Commission and FirstEnergy Service Company, the Commission 

declined to adopt a one-size-fits-all approach to transmission planning. The Commission 

believes that there are many different approaches to transmission planning and requires 

only that the transmission planning process adopted by a transmission planning region 

satisfy the transmission planning principles discussed in Order No. 1000 and this order. 

Thus, we decline to rule in the abstract in advance of the compliance filings whether any 

particular transmission planning process is the only appropriate process for all regions. 

454. The Commission clarifies that the public utility transmission providers in a 

transmission planning region must use the same process to evaluate a new transmission

facility proposed by a nonincumbent transmission developer as it does for a transmission 

facility proposed by an incumbent transmission developer. In Order No. 1000, the 

 533 Order No. 1000, FERC Stats. & Regs. ¶ 31,323.
Docket No. RM10-23-001 -344-

Commission required each public utility transmission provider to adopt a transparent and 

not unduly discriminatory evaluation process that complies with the Order No. 890 

transmission planning principles.534 However, this requirement does not preclude public 

utility transmission providers in regional transmission planning processes from taking 

into consideration the particular strengths of either an incumbent transmission provider or 

a nonincumbent transmission developer during its evaluation.535 

455. The Commission denies LS Power’s other requests for rehearing regarding the 

selection of a transmission developer. The Commission declined to address the selection 

of a transmission developer in Order No. 1000. Aside from requiring the public utility 

transmission providers in a region to establish criteria to assess a transmission 

developer’s qualifications to have its proposed transmission project considered for 

selection in a regional transmission plan for purposes of cost allocation, Order No. 1000 

also requires public utility transmission providers in a region to adopt transparent and not 

unduly discriminatory criteria for selecting a new transmission project in a regional 

transmission plan for purposes of cost allocation. We decline to set certain minimum 

 534 Id. P 328.

535 See id. P 260 (“An incumbent public utility transmission provider is free to 

highlight its strengths to support transmission project(s) in the regional transmission plan, 

or in bids to undertake transmission projects in regions that choose to use solicitation 

processes.”).
Docket No. RM10-23-001 -345-

standards for the criteria used to select a transmission facility in a regional transmission 

plan for purposes of cost allocation other than to require that these selection criteria be 

transparent and not unduly discriminatory. We also find that this purpose is met 

adequately by the transmission planning principles of Order No. 890. We also anticipate 

that selection criteria will vary from transmission planning region to transmission 

planning region in accordance with each transmission planning region’s needs, just as 

other aspects of regional transmission planning processes will vary, and LS Power has 

not persuaded us that such flexibility is inappropriate. However, we clarify that when 

cost estimates are part of the selection criteria, the regional transmission planning process 

must scrutinize costs in the same manner whether the transmission project is sponsored 

by an incumbent or nonincumbent transmission developer.

456. If a transmission project is selected in a regional transmission plan for purposes of 

cost allocation, Order No. 1000 requires that the transmission developer of that 

transmission facility (whether incumbent or nonincumbent) must be able to rely on the 

relevant cost allocation method or methods within the region should it move forward with 

its transmission project.536 We are not persuaded to change this approach on rehearing. 

Further, we reiterate that we do not require public utility transmission providers in a 

region to adopt a provision for ongoing sponsorship rights, for the reasons set out in 

 536 Id. P 339.
Docket No. RM10-23-001 -346-

Order No. 1000. The Commission concluded that granting transmission developers an

ongoing right to build sponsored transmission projects could adversely impact the 

regional transmission planning process.537 We are not persuaded to reverse our decisions 

on the selection of transmission developers. While we acknowledge LS Power’s 

concerns, we do not believe they warrant any revision of the selection of transmission 

developers at this time given the diversity of methods for selecting transmission 

developers used around the nation.

c. Reevaluation of Regional Transmission Plans When 

There Is a Project Delay and Reliability Compliance 

Obligations of Transmission Developers

i. Final Rule

457. In Order No. 1000, the Commission required each public utility transmission 

provider to amend its OATT to describe the circumstances and procedures under which 

public utility transmission providers in the regional transmission planning process will 

reevaluate the regional transmission plan to determine if delays in the development of a 

transmission facility selected in a regional transmission plan for purposes of cost 

allocation require evaluation of alternative solutions, including those proposed by the 

 537 Id.
Docket No. RM10-23-001 -347-

incumbent transmission provider, to ensure the incumbent transmission provider can 

meet its reliability needs or service obligations.538

458. The Commission also explained that if a violation of a NERC reliability standard 

by an incumbent would result from a nonincumbent transmission developer’s decision to 

abandon a transmission facility meant to address such a violation, the incumbent 

transmission provider does not have the obligation to construct the nonincumbent’s 

project.539 Rather, the incumbent transmission provider must identify the specific NERC 

reliability standard(s) that would be violated and submit a mitigation plan to address the 

violation.540 The Commission explained that if the incumbent public utility transmission 

provider follows the NERC-approved mitigation plan, the Commission will not subject it 

to enforcement action for the specific NERC reliability standard violation(s) caused by a 

nonincumbent transmission developer’s decision to abandon a transmission facility.541

459. The Commission also noted that, when a nonincumbent transmission developer 

becomes subject to the requirements of FPA section 215 and the regulations thereunder, it 

will be required to comply with all applicable reliability obligations, including registering 

 538 Id. P 329.

539 Id. P 344.

540 Id.

541 Id.
Docket No. RM10-23-001 -348-

with NERC for performance of applicable reliability functions.542 The Commission 

stated that if there are concerns about when compliance with NERC registration and 

reliability standards would be triggered, the appropriate forum to raise these questions 

and request clarification is the NERC process.543

ii. Requests for Rehearing and Clarification

460. Some petitioners question whether the reevaluation requirement set forth in Order 

No. 1000 are sufficient to protect incumbent transmission providers from the 

repercussions related to a nonincumbent’s failure to build a project in time.544 For 

instance, these petitioners argue that the Commission failed to protect incumbent 

transmission providers from the increased risk of violations of state reliability or resource 

adequacy requirements, and other state service obligations.545 MISO Transmission 

Owners Group 2 also adds that the incumbent utility could face civil liability, state 

regulatory sanctions, and financial harm resulting from damage to its own facilities or the 

facilities of another entity caused by the action of the nonincumbent. 

 542 Id. P 342.

543 Id. P 343.

544 See, e.g., Southern Companies; Edison Electric Institute; MISO Transmission 

Owners Group 2; and Xcel.

545 See, e.g., Edison Electric Institute; and MISO Transmission Owners Group 2.
Docket No. RM10-23-001 -349-

461. Some commenters argue that incumbent developers should not be burdened with 

monitoring the status of a nonincumbent developer’s progress. Specifically, if the 

reevaluation requirement would obligate incumbents to discover or address 

nonincumbent delays prior to being notified by the nonincumbent, Southern Companies 

request rehearing of this requirement in Order No. 1000.546 Southern Companies also 

request rehearing of the reevaluation requirement to the extent it could inhibit, prevent or 

slow an incumbent’s decision to address a delay or the implementation of its corrective 

plan. Similarly, Southern California Edison requests that the Commission require 

regional transmission planning entities to develop protocols for how such transmission 

planning entities will: (1) be kept apprised by nonincumbent developers of the status of 

their projects; and (2) notify the applicable incumbent transmission owner that it needs to 

develop a mitigation plan because a project has been delayed or abandoned by a 

nonincumbent developer. In addition, Southern Companies contend that each incumbent 

transmission provider and planning authority should be permitted to reevaluate its own 

local transmission plan to determine whether a nonincumbent’s delay in constructing a 

regional facility will adversely impact reliability on the incumbent’s system. In addition, 

Southern Companies argue that because the reevaluation requirement does not protect 

 546 Southern Companies at 78 (citing McElroy Electronics Corp. v. FCC, 990 F.2d 

1351, 1358 (D.C. Cir. 1993)). 
Docket No. RM10-23-001 -350-

against the need to implement operational adjustments, Order No. 1000 fails to protect 

against service reliability problems and fails to weigh the adverse impacts against the 

benefits that the Commission foresees.

462. Ad Hoc Coalition of Southeastern Utilities and Large Public Power Council also 

assert that there is no substantial evidence for concluding, as the Commission does in 

paragraph 263 of Order No. 1000, that the potential costs associated with a delayed or 

abandoned nonincumbent transmission facility are remediable by a reevaluation of the 

regional plan. For example, Large Public Power Council explains that by the time 

construction delays place a system at risk, the damage will have been done, since such 

delays will postdate the planning that contemplated the facilities at issue, often by several 

years. As such, it maintains that even if the incumbent utility can step in with sufficient 

lead-time so that reliability is not threatened, and the cost of this activity is recoverable, 

there is little that can be done to save ratepayers from the associated costs, and there is no 

basis to conclude that nonincumbent participation in the transmission development 

process will therefore be worth it.

463. Several petitioners seek rehearing and clarification of the Commission’s decision 

to allow incumbent transmission providers to implement a NERC mitigation plan to 

avoid an enforcement action if a nonincumbent transmission developer abandons a 

project needed to meet a reliability need. For example, Xcel asserts that Order No. 

1000’s discussion of a NERC mitigation plan may involve interrupting load under certain 
Docket No. RM10-23-001 -351-

conditions, or implementing rolling outages. Xcel argues that this degradation of service 

to end use customers is contrary to the fundamental purposes of FPA section 215 and 

would also result in a loss of revenues to the utility. 

464. Transmission Dependent Utility Systems argue that Order No. 1000 sheds no light 

on whether its mitigation plan solution is realistic or available and does not address who 

will be responsible for maintaining power if neither the incumbent nor the nonincumbent 

transmission provider can be held accountable for completion or maintenance of 

reliability-driven projects. Similarly, PSEG Companies argue that the problem of 

abandonment by a nonincumbent of a project needed for reliability cannot be fixed by 

reliability standards or by mitigation plans submitted in “compliance” with those 

standards. They state that the Commission failed to recognize that NERC reliability 

standards will not be applicable to a nonincumbent developer unless and until the project 

is constructed and in-service.

465. Petitioners point out possible difficulties that may arise because similar terms have 

distinct meanings in a public utility transmission provider’s OATT under FPA 205 and 

the reliability standards under FPA 215. Several petitioners argue that it is not always a 

public utility transmission provider that is responsible for conducting a reevaluation or 

developing a mitigation plan.547 For instance, Southern Companies argue that public 

 547 See, e.g., PSEG Companies; and Southern Companies.
Docket No. RM10-23-001 -352-

utility transmission providers do not conduct transmission planning or evaluate or 

reevaluate transmission plans. Instead, Southern Companies argue that planning 

authorities and transmission planners are the appropriate entities to determine the impacts 

of a delay on local plans and are responsible for meeting reliability and service 

obligations, including the state-mandated duty to serve native load. Southern Companies 

argue that the Commission cannot remove or dilute that responsibility by delegating it to 

another entity without preempting state law. Southern Companies state that if Order No. 

1000 does not intend the term “public utility transmission provider” to mean 

Transmission Service Provider under the NERC Functional Model, the Commission must 

grant rehearing to determine what category of Registered Entity is meant, or extend the 

commencement of the 12-month compliance window until NERC has determined which 

category of Registered Entity is appropriate to conduct the activities required by Order 

No. 1000.548 Furthermore, Edison Electric Institute seeks clarification that an incumbent 

transmission provider need not have a retail distribution service territory and need not 

construct the new facilities entirely within its retail distribution service territory to qualify 

for protection from an enforcement action as described in paragraph 344 of Order No. 

1000. 

 548 We note that the capitalized terms refer to specific terms used in the NERC 

Reliability Standards.
Docket No. RM10-23-001 -353-

466. In addition, PSEG Companies argue that using the term “transmission provider” 

creates confusion because, under the NERC Functional Model, the term could apply to a 

number of different functions, and these different functions are very different even if in 

ISO/RTO regions the “transmission provider” is the ISO/RTO. PSEG Companies argue 

that the Commission erred by seeking to impose the responsibility to develop a 

“mitigation plan” onto incumbent transmission owners, and that this requirement 

demonstrates that the Commission misunderstands the NERC process. Thus, according 

to PSEG Companies, the process for addressing nonincumbents’ abandonment of 

facilities would not work as envisioned, at least in the ISO/RTO context where the 

transmission owner is not responsible for planning the system and would not be 

responsible for filing a mitigation plan in the event of abandonment.

467. Other petitioners request clarification regarding the scope of the waiver. Edison 

Electric Institute recommends that the Commission use NERC terminology to clarify the 

scope of the waiver. Other petitioners argue that if the waiver applies only to the 

incumbent transmission provider as defined in Order No. 1000, the application is too 

narrow.

549 In addition to the incumbent transmission provider, Edison Electric Institute 

argues that the protection from an enforcement action should extend to other entities that 

might be found in violation of a reliability standard, such as balancing authorities and 

 549 See, e.g., Edison Electric Institute; Southern California Edison; and APPA.
Docket No. RM10-23-001 -354-

reliability coordinators. APPA agrees and adds that all of the transmission providers will 

be adversely affected to at least some extent due to the interconnected nature of the 

transmission network. Transmission Dependent Utility Systems add that third parties 

with NERC reliability obligations for certain transmission facilities, such as municipal 

utilities and rural electric cooperatives, also should be held harmless from penalties and 

NERC enforcement actions if a nonincumbent transmission developer abandons or fails 

to maintain a project needed to address reliability concerns. For example, even though 

Southern California Edison considers CAISO to be the transmission provider, Southern 

California Edison asserts that it develops and implements NERC mitigation plans as the 

NERC registered transmission owner and therefore should be entitled to protection.

468. Southern Companies also request rehearing of Order No. 1000’s failure to explain 

its departure from existing policy and regulations regarding mitigation plans. Southern 

Companies argue that requiring an incumbent to submit a mitigation plan for a 

nonincumbent’s abandonment of necessary facilities would bestow upon the incumbent 

the impossible task of ensuring that another entity will not make poor business decisions, 

go bankrupt, or otherwise abandon or cancel its projects. Furthermore, Southern 

Companies state that Order No. 1000 indicates the incumbent may need to construct 

redundant and duplicate facilities to guard against the potential of nonincumbent delay or 

abandonment of its project. In addition, Southern Companies request rehearing to the 

extent incumbents are required to propose a corrective action for review by the regional 
Docket No. RM10-23-001 -355-

process because such a requirement would impair service reliability.550 Southern 

Companies also request clarification that the costs of the delayed regional facility will not 

be allocated to an incumbent that constructs a local transmission solution to meet its 

reliability or service needs in the face of delay.

469. Petitioners also argue that the protection from an enforcement action should be 

applicable to any project that an incumbent relies on to satisfy its reliability obligations, 

including reliability, public policy or economic-based projects.551 Southern California 

Edison points out that a project intended to address a NERC violation or other reliability 

concerns may be dependent on another transmission project being completed first, 

including a public policy or economic project. Ameren argues that such other projects, 

which may have received regional cost allocation, will almost certainly have some 

measure of reliability effect because the grid is interconnected and that the failure of any 

such project could cause a blackout.

470. Some petitioners seek clarification that the protections found in paragraph 344 will 

prevent the Commission, NERC, or a Regional Entity from considering a violation that is 

covered by this protection, or a mitigation plan developed to address such a violation, as 

 550 Southern Companies at 81-82 (citing Motor Vehicle Mfrs. Assoc. of the United 

States, Inc. v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 43 (1983)). 

551 See, e.g., Southern California Edison; Xcel; Ameren; and Edison Electric 

Institute.
Docket No. RM10-23-001 -356-

a prior violation when determining the penalty for a new violation.552 Moreover, Edison 

Electric Institute seeks clarification that the protections described in paragraph 344 will 

apply to any Reliability Standard violation, including an operationally-focused violation, 

resulting from abandonment of a project by a nonincumbent transmission developer. 

Edison Electric Institute asserts that it is unfair to provide protection only for violations 

specifically envisioned at the time the project was conceived. Finally, Edison Electric 

Institute seeks clarification that the safe harbor provision will prevent the Commission, 

NERC, or a Regional Entity from considering a violation that is covered by this safe 

harbor protection or a mitigation plan developed to address such a violation as a prior 

violation when determining the penalty for a new violation.

471. Southern California Edison requests that the Commission clarify that an 

incumbent transmission owner will not be subject to an enforcement action or any other 

sanction or penalty if it cannot follow or implement an approved mitigation plan for 

reasons beyond its control. It states that after Order No. 1000, a transmission owner may 

be asked to develop a mitigation plan without much of the key information, which means 

an incumbent transmission owner may not be able to develop an infallible mitigation plan 

and should not be penalized if implementation of its plan is delayed or if the plan needs 

 552 See, e.g., Edison Electric Institute; and Southern California Edison.
Docket No. RM10-23-001 -357-

to be revised to reflect new information that becomes known to the incumbent when the 

mitigation efforts are underway.

472. In addition, Southern California Edison requests that the Commission clarify that 

penalties, sanctions, or enforcement actions also will not be levied against an incumbent 

transmission owner for reliability problems that arise from the actions of a nonincumbent 

transmission developer in connection with delays of a transmission facility, or the 

operation or maintenance thereof.

473. Southern California Edison also argues that the Commission should clarify that, as 

long as the incumbent transmission owner submits its mitigation plan to an appropriate 

regional entity, the transmission owner should not face any enforcement actions, 

penalties or sanctions while the mitigation plan is pending approval. Southern California 

Edison states that it does not submit mitigation plans directly to NERC, but instead 

initially submits its plan for approval to the Regional Entity. Therefore, Southern 

California Edison states that there will be some inevitable delay between the time that a 

transmission owner submits a mitigation plan and the time that the plan is approved by 

NERC, and argues that it should not be penalized for such inevitable delay.

474. Some petitioners argue that the Commission’s reevaluation and enforcement 

provisions in Order No. 1000 are inconsistent with section 215 of the FPA, and fail to 
Docket No. RM10-23-001 -358-

adequately protect incumbents.553 For example, Edison Electric Institute asserts that if an 

incumbent transmission provider violates state resource adequacy or reliability 

requirements, it may be subject to significant monetary penalties and other sanctions, 

which the Commission’s grant of protection from a section 215 enforcement action has 

no effect on and cannot preempt. Edison Electric Institute argues that the Commission 

failed to discuss these implications and has thus engaged in arbitrary and capricious 

decision-making and should grant rehearing to remove the right of first refusal for 

reliability projects. 

475. Xcel argues that Order No. 1000 ignores the substantial record evidence that the 

policies adopted are inconsistent with the objectives of section 215 of the FPA and the 

Commission’s initiatives to improve electric system reliability through mandatory 

standards. Xcel contends that forcing utility transmission providers to rely on a third 

party to fulfill section 215 obligations does not constitute reasoned decision-making. 

Southern Companies add that Order No. 1000’s nonincumbent requirements pose threats 

to reliability and economic service by forcing disintegration of the transmission network. 

MISO Transmission Owners Group 2 argues that nothing in EPAct 2005 authorizes the 

Commission to provide blanket waivers of critical reliability standards for the purposes of 

 553 See, e.g., Xcel; Southern Companies; and MISO Transmission Owners Group 

2.
Docket No. RM10-23-001 -359-

achieving some policy preference unrelated to the enforcement of mandatory reliability 

standards.

476. Southern Companies also argue that the Commission impermissibly uses section 

206 to impose reliability requirements instead of using its section 215 authority. 

Southern Companies argue that this action violates the Whole Act Rule by making 

section 215’s goal of protecting reliability subservient to section 206.554 Accordingly, 

Southern Companies assert that the Commission should have gone through the 

Commission-approved NERC standards and enforcement processes established pursuant 

to section 215 of the FPA, the Commission’s regulations, and Commission precedent, 

rather than unilaterally developing these reliability-related reevaluation and enforcement 

protections and imposing their requirements onto users, owners, and operators of the 

bulk-power system. Southern Companies argue the enforcement action waiver is 

inconsistent with, and may conflict with existing NERC Reliability Standards.

iii. Commission Determination

477. The Commission affirms its decision to require each public utility transmission 

provider to amend its OATT to describe the circumstances and procedures under which 

public utility transmission providers in the regional transmission planning process will 

reevaluate the regional transmission plan to determine if delays in the development of a 

 554 Southern Companies at 77 n.251 (citing 5 U.S.C. 706).
Docket No. RM10-23-001 -360-

transmission facility selected in a regional transmission plan for purposes of cost 

allocation require evaluation of alternative solutions, including those proposed by the 

incumbent transmission provider, to ensure the incumbent transmission provider can 

meet its reliability needs or service obligations.555 As the Commission explained in 

Order No. 1000, the focus here is on ensuring that adequate processes are in place to 

determine whether delays associated with completion of a transmission facility selected 

in a regional transmission plan for purposes of cost allocation have the potential to 

adversely affect an incumbent transmission provider’s ability to fulfill its reliability needs 

or service obligations. We believe that if these processes are followed, incumbent 

transmission providers should be able to meet reliability related requirements.

478. In response to Xcel’s and Southern Companies’ argument that the reevaluation 

requirement does not protect against the need to implement operational adjustments, the 

present operationally-focused NERC reliability standards require Functional Entities to 

operate so that the portion of the system that is in service at that time will be capable of 

delivering the output of generation to firm demand and transfers within the applicable 

performance criteria. Accordingly, a Functional Entity must prepare its system to operate 

regardless of whether a transmission project is delayed or abandoned. Thus, the 

 555 Order 1000, FERC Stats. & Regs. ¶ 31,323 at P 329.
Docket No. RM10-23-001 -361-

Commission concludes that there is no need to set requirements in addition to those 

already established in the applicable NERC reliability standards.

479. In response to those petitioners concerned that they must individually monitor the 

status of a nonincumbent transmission developer’s progress in developing its 

transmission facility selected in the regional transmission plan for purposes of cost 

allocation, we note that transmission planners and transmission developers already 

routinely communicate regarding the status of the construction of a transmission project. 

Consistent with applicable NERC Reliability Standards, a Functional Entity remains 

responsible for complying with all applicable Reliability Standards, such as studying 

performance of its system and deciding when it must develop corrective plans to ensure 

that its system responds reliably as prescribed by those standards.556 As such, we 

emphasize that Order No. 1000 does not change any obligations an incumbent 

transmission provider, as a Functional Entity, may have under the NERC Reliability 

Standards to monitor a nonincumbent transmission developer’s progress in developing its 

transmission facility selected in the regional transmission plan for purposes of cost 

allocation. Furthermore, Order No. 1000 left it to public utility transmission providers in 

 556 NERC Reliability Standards in the Facility Connection and Transmission

Planning series ensure evaluation of the reliability impact of the new facilities 

connections, and coordination and results sharing by the entities involved, as well as 

development of corrective plans if reliability requirements are not met when projects are 

delayed or abandon.
Docket No. RM10-23-001 -362-

a transmission planning region to adopt procedures in their OATTs for reevaluating 

transmission facilities selected in the regional transmission plan for purposes of cost 

allocation. We continue to believe this approach is appropriate.

480. The Commission also affirms, with certain clarifications, its decision in Order No. 

1000 to not subject an incumbent public utility transmission provider to a penalty for a 

violation of a NERC reliability standard caused by a nonincumbent transmission 

developer’s decision to abandon a transmission facility if the incumbent public utility 

transmission provider has identified the violation and submitted a NERC mitigation plan 

to address it.557 The Commission used “enforcement action” in Order No. 1000, but is 

not using this term here because “enforcement action” also could imply that Registered 

Entities are not going to be required to mitigate any NERC reliability standards 

violations. The Commission clarifies that, although it will not seek penalties, it will 

ensure that Registered Entities implement appropriate mitigation plans.

481. The Commission agrees with petitioners that argue that entities other than 

incumbent public utility transmission providers may violate a NERC reliability standard 

in the event that a nonincumbent transmission developer abandons a transmission facility. 

In some regions, the incumbent public utility transmission provider may not be the entity 

responsible for complying with the NERC reliability standards implicated by the 

 557 Order 1000, FERC Stats. & Regs. ¶ 31,323 at P 344.
Docket No. RM10-23-001 -363-

abandonment of a nonincumbent transmission developer’s project. We also agree with 

Ameren and other petitioners that argue that the abandonment of a nonincumbent 

transmission project that is designed to meet economic needs or transmission needs 

driven by a Public Policy Requirement could impact reliability. Therefore, we clarify 

that the Commission will not subject a Registered Entity558 to a penalty for a violation of 

a NERC reliability standard caused by a nonincumbent transmission developer’s decision 

to abandon any type of transmission facility selected in the regional transmission plan for 

purposes of cost allocation if, on a timely basis, that Registered Entity identifies the 

violation and complies with all of its obligations under the NERC reliability standards to 

address it.

482. The remaining requests for rehearing or clarification posit enforcement situations 

that are uncertain or speculative. We decline to rule on these requests for rehearing or

clarification because we find that they are premature. We believe that, with the 

clarifications granted above, entities have sufficient information to understand when the 

Commission will not subject a Registered Entity to enforcement action for a violation of 

 558 We use the term Registered Entity to refer an owner, operator, or user of the 

Bulk Power System, or the entity registered as its designee for the purpose of compliance, 

that is included in the NERC Compliance Registry. See, North American Electric 

Reliability Corporation, Compliance Monitoring and Enforcement Program, Appendix

4C to the Rules of Procedures (effective Jan. 31, 2012), available at: 

http://www.nerc.com/files/Appendix_4C_CMEP_20120131.pdf.
Docket No. RM10-23-001 -364-

a NERC reliability standard caused by a nonincumbent transmission developer’s decision 

to abandon a transmission facility. Furthermore, many of these petitions in effect argue 

that the Commission should not have required public utility transmission providers to 

eliminate a federal right of first refusal from Commission jurisdictional-tariffs and 

agreements in Order No. 1000. The Commission has adequately explained in Order No. 

1000 and in this order the need for eliminating a federal right of first refusal. 

483. Finally, contrary to arguments by petitioners, the Commission was not required to 

use its section 215 authority to adopt the reevaluation requirements or to state the 

circumstances under which it would exercise its enforcement discretion. Rather, the 

reevaluation requirement is a tariff obligation not a reliability obligation under section 

215. Furthermore, in stating the circumstances under which the Commission would 

exercise its enforcement discretion, the Commission did not create new, or modify 

existing, NERC reliability standards. Had the Commission done so, it would be required 

to adopt a reliability standard through its authority set out in section 215. Instead, the 

Commission appropriately exercised its discretion under section 215 enforcement 

authority to set forth a particular circumstance when it will not e penalize a Registered 

Entity.
Docket No. RM10-23-001 -365-

d. Recovery of Abandoned Plant Costs and Backstop 

Authority

i. Final Rule

484. In Order No. 1000, the Commission found that when an incumbent transmission 

provider is called upon to complete a transmission project that it did not sponsor, there 

would be a basis for the incumbent transmission provider to be granted abandoned plant 

recovery for that transmission facility, upon the filing of a petition for declaratory order 

requesting such rate treatment or a request under section 205 of the FPA.559 

ii. Requests for Rehearing

485. APPA and Transmission Access Policy Study Group question the Commission’s 

decision to grant abandoned plant cost recovery to an incumbent transmission provider in 

certain circumstances. Transmission Access Policy Study Group and APPA argue that 

granting incumbent transmission providers abandoned cost recovery under Order No. 

1000 is an unjustified deviation from Order No. 679’s case-by-case approach. 

Transmission Access Policy Study Group raises several questions that it asserts highlight 

the need for the Commission to look at the facts of each request for abandoned plant 

recovery rather than committing the public in all circumstances to pay for unfinished 

projects. APPA argues that abandoned plant cost recovery is an incentive that should be 

 559 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 267.
Docket No. RM10-23-001 -366-

granted on a case-by-case basis where the granting of such an incentive is shown to be 

necessary and appropriate.

486. Southern California Edison also notes that Order No. 1000 states in paragraph 344 

that the incumbent transmission owner does not have an obligation to construct a 

transmission facility intended to address a possible NERC violation, but then states in 

paragraph 267 that there may be circumstances when an incumbent may be called upon to 

complete a project that it did not sponsor. Southern California Edison requests that the 

Commission clarify: (1) how the statements in paragraphs 267 and 344 should be 

reconciled so that they are consistently interpreted and implemented; (2) in which 

situations a transmission provider may be required to complete a transmission facility it 

did not sponsor; and (3) what that completion obligation entails.

487. Southern California Edison also seeks clarification that Order No. 1000 does not 

preclude regions from applying backstop transmission development obligations to all 

participating transmission owners in the region and allows regions that impose backstop 

obligations to apply them on an equivalent basis among incumbents and nonincumbents. 

Southern California Edison argues that to require only incumbents to serve as the safetynet for all nonincumbent projects would impose a burden upon incumbents that could 

impede their ability to compete for projects. On the other hand, Xcel recommends that 

tariffs incorporate a backstop that reflects the incumbent utility’s obligation as provider 
Docket No. RM10-23-001 -367-

of last resort to build transmission needed for reliability even if the incumbent does not 

exercise a right of first refusal and no one else offers to build it.

488. Southern California Edison requests clarification that the incumbent transmission 

owner will be fully compensated for mitigation costs through “grid-wide” rates to offset 

the substantial burden of developing and implementing mitigation plans. In addition, 

Edison Electric Institute seeks clarification that an incumbent transmission provider that 

steps in to complete an abandoned reliability project in the circumstances discussed in 

paragraph 344 of Order No. 1000, it has no obligation to purchase the facilities, materials, 

or any other assets related to the abandoned project, at cost or otherwise. It argues that 

such a requirement would provide unwarranted financial protections for nonincumbent 

transmission developers, and remove one of the key incentives to complete a project once 

begun. Similarly, Southern Companies argue that Order No. 1000 will discriminate in 

favor of third party developers at the expense of an incumbent’s native load and OATT 

customers unless the Commission ensures that developers of regional projects are held 

responsible and accountable for any and all adverse effects of their construction delays or 

abandonments upon incumbents, including any increased costs caused thereby.560

 560 Southern Companies at 83-84 (citing Chicago v. FPC, 385 F.2d 629, 637 (D.C. 

Cir. 1967)). 
Docket No. RM10-23-001 -368-

iii. Commission Determination

489. In response to Transmission Access Policy Study Group and APPA, we clarify 

that we will, consistent with Order No. 679,561 grant abandoned plant recovery on a caseby-case basis. Order No. 1000 did not provide a blanket grant of abandoned plant 

recovery, but merely stated that where an incumbent transmission provider is called upon 

to complete a transmission project that another entity has abandoned, this would be a 

basis for the incumbent transmission provider to be granted abandoned plant recovery for 

that transmission facility, upon the filing of a petition for declaratory order requesting 

such rate treatment or a request under section 205 of the FPA.562 

490. In response to Southern California Edison, nothing in Order No. 1000 requires an 

incumbent transmission provider to construct a nonincumbent transmission developer’s 

transmission project selected in the regional transmission plan for purposes of cost 

allocation if it abandons a transmission facility.563 We note, however, that some RTOs 

and ISOs may have the authority under their tariff or membership agreements to direct a 

member to build a transmission facility under certain circumstances.564 Further, Order 

 561 Order No. 679, FERC Stats. & Regs. ¶ 31,222.

562 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 267.

563 Id. P 344.

564 See, e.g., PJM Consolidated Transmission Owners Agreement at section 

4.2.1.We note that a nonincumbent transmission developer that becomes a member of an 

(continued...)
Docket No. RM10-23-001 -369-

No. 1000 did not address the issue of backstop construction authority or responsibility for 

any transmission project, whether undertaken initially by an incumbent or a 

nonincumbent transmission developer. Accordingly, this issue is beyond the scope of 

this proceeding, and we will not address it on rehearing. 

491. In response to Southern California Edison’s request that incumbent transmission 

providers be compensated for the cost of developing implementing a mitigation plan 

through “grid-wide” rates, we did not provide a generic answer in Order No. 1000 and do 

not do so here. That is, we are not deciding here whether a transmission provider may 

recover, or how it may recover, the costs that result from complying with the Reliability 

Standards if a nonincumbent transmission developer delays or abandons a needed 

transmission project.

492. In response to Edison Electric Institute, the Commission does not require under 

Order No. 1000 that an incumbent transmission developer purchase the facilities, 

materials, or any other assets related to an abandoned project that the incumbent 

transmission provider determines it must complete. However, Order No. 1000 also does 

not preclude an incumbent transmission developer from purchasing such facilities, 

materials or other assets if it believes it is prudent to do so. 

 

RTO or ISO may be subject to an obligation to build that applies to transmission-owning 

members.
Docket No. RM10-23-001 -370-

C. Interregional Transmission Coordination

1. Interregional Transmission Coordination Requirements

a. Interregional Transmission Coordination Procedures and 

Geographical Scope

i. Final Rule

493. In Order No. 1000, the Commission required each public utility transmission 

provider, through its regional transmission planning process, to establish further

procedures with each of its neighboring transmission planning regions for the purpose of 

(1) coordinating and sharing the results of respective regional transmission plans to 

identify possible interregional transmission facilities that could address transmission 

needs more efficiently or cost-effectively than separate regional transmission facilities; 

and (2) jointly evaluating such facilities, as well as jointly evaluating those transmission 

facilities that are proposed to be located in more than one transmission planning 

region.565 Furthermore, the Commission required each public utility transmission 

provider, through its regional transmission planning process, to describe the methods by 

which it will identify and evaluate interregional transmission facilities and to include a 

description of the type of transmission studies that will be conducted to evaluate 

 565 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 396.
Docket No. RM10-23-001 -371-

conditions on neighboring systems for the purpose of determining whether interregional 

transmission facilities are more efficient or cost-effective than regional facilities.566

494. In Order No. 1000, the Commission also required each public utility transmission 

provider through its regional transmission planning process to coordinate with the public 

utility transmission providers in each of its neighboring transmission planning regions 

within its interconnection to implement the interregional transmission coordination 

requirements.567 The Commission defined an interregional transmission facility as one 

that is located in two or more transmission planning regions.

568 The Commission 

declined to require, but did not prohibit, joint evaluation of other facilities or study of the 

effects in a second region of a new transmission facility proposed to be located in a single 

transmission planning region.569 The Commission explained that to do otherwise could 

 566 Id. P 398.

567 Id. P 415.

568 Id. P 482 n.374.

569 Nevertheless, consistent with Cost Allocation Principle 4, each regional 

transmission planning process must identify the consequences of a proposed new 

transmission facility for other transmission planning regions. The Commission also 

stated that Order No. 1000 did not affect any obligations that public utility transmission 

providers may otherwise have to assess the effects of new transmission facilities on other 

systems, including, but not limited to, any other requirement of the OATT for 

interconnection studies, any requirement under the NERC reliability standards, and the 

requirements of Good Utility Practice. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at 

P 416 n.351.
Docket No. RM10-23-001 -372-

have the effect of mandating interconnectionwide transmission planning, because a 

transmission facility located within one transmission planning region can have effects on 

many systems in the interconnection, which could trigger a chain of multiregional 

evaluation processes. Furthermore, the Commission observed that its interregional 

transmission coordination requirements will assist transmission planners in understanding 

and managing the effects of a transmission facility located in one region on a neighboring 

region.570

ii. Requests for Rehearing and Clarification

495. AEP asks the Commission to ensure that the interregional coordination 

requirements apply to transmission needs driven by public policy requirements. 

Otherwise, AEP states, planners will settle on less efficient and less cost-effective 

solutions, which increase costs. AEP argues that it is arbitrary and capricious for the 

Commission not to require consideration of needs driven by public policy requirements 

as part of interregional coordination, in light of its findings on the importance of public 

policy considerations in the Final Rule. AEP also argues that requiring consideration of 

transmission needs driven by public policy requirements within a region but not between 

regions places too much emphasis and importance on the decisions about configuration of 

 570 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 416.
Docket No. RM10-23-001 -373-

the planning regions given that the Commission has declined to prescribe the geographic 

scope of any transmission planning region. 

496. Bonneville Power states that certain aspects of Order No. 1000 indicate that 

formal procedures need to cover only identification and joint evaluation rather than 

planning and developing interregional transmission facilities. If this is what the 

Commission meant, then Bonneville Power requests that the Commission so clarify.

497. On rehearing, MISO Transmission Owners Group 1 and Wisconsin PSC request 

that the Commission expand the definition of an interregional transmission facility. 

Specifically, MISO Transmission Owners Group 1 requests that the Commission find that 

transmission facilities physically located within one region can be considered 

interregional transmission facilities when they provide sufficient benefits as determined 

in accordance with the applicable interregional agreement or OATTs, and can be eligible 

for interregional cost allocation pursuant to criteria set forth in that agreement or those 

OATTs. Wisconsin PSC makes a similar argument. Wisconsin PSC also requests that 

the Commission remove the single-region limitation, and instead limit evaluation of a 

single-region project to interregional transmission planning processes that involve no 

more than two transmission planning regions. Wisconsin PSC adds that the Commission 

could further limit consideration by requiring the project sponsor to publicly identify a 

single-region transmission facility as benefiting the other affected region to ensure that a 
Docket No. RM10-23-001 -374-

project does not “fly under the radar.”571 Both Wisconsin PSC and MISO Transmission 

Owners Group 1 argue that their respective definitions eliminate the Commission’s 

concern that expanding the scope of interregional transmission coordination would lead 

to interconnectionwide transmission planning. 

498. Furthermore, MISO Transmission Owners Group 1 argues that the Commission 

should expand the definition because the expanded definition would help ensure that the 

costs of such facilities are allocated in a manner that is at least roughly commensurate 

with the benefits received. Wisconsin PSC asserts that requiring regions to jointly 

consider single-region projects in the interregional planning process would diminish the 

risk of inadvertent free ridership, ensure that intended beneficiaries of a project are 

allocated a share of the project costs, and expand the set of potential cost-effective 

transmission solutions to regional transmission needs. Wisconsin PSC adds that not 

eliminating this exclusion may create a specific violation of the application of the cost 

causation/beneficiaries pay principles articulated in Illinois Commerce Comm’n v. FERC, 

which require beneficiaries of a transmission project to pay a roughly commensurate 

share of project costs.572 

 571 Wisconsin PSC at 6-7.

572 Wisconsin PSC at 5 (citing 576 F.3d 470 (7th Cir. 2009)). 
Docket No. RM10-23-001 -375-

499. Wisconsin PSC and MISO Transmission Owners Group 1 also argue that it is 

especially important to expand the definition because MISO has extensive seams with 

neighboring RTOs and other regions. Wisconsin PSC adds that it is virtually impossible 

for MISO to plan a transmission line in those areas without providing potential benefits to 

PJM load. Thus, it argues that the single-region limitation would increase the free 

ridership that the Commission seeks to deter.

iii. Commission Determination

500. We deny AEP’s arguments that Order No. 1000’s interregional transmission 

coordination requirements do not adequately provide for consideration of transmission 

needs driven by Public Policy Requirements. In Order No. 1000, the Commission 

determined that interregional transmission coordination neither requires nor precludes 

longer-term interregional transmission planning, including the consideration of 

transmission needs driven by Public Policy Requirements.573 Order No. 1000 stated that 

whether and how to address this issue with regard to interregional transmission facilities 

is a matter for public utility transmission providers, through their regional transmission 

planning processes, to resolve in the development of compliance proposals.574 We clarify 

that Order No. 1000 does not require or prohibit consideration of transmission needs 

 573 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 401.

574 Id. P 401.
Docket No. RM10-23-001 -376-

driven by Public Policy Requirements as part of interregional transmission coordination. 

However, such considerations are required through the regional transmission planning 

process, which is an integral part of interregional transmission coordination because all 

interregional transmission projects must be selected in both of the relevant regional 

transmission planning processes in order to receive interregional cost allocation. 

Therefore, consideration of transmission needs driven by Public Policy Requirements is 

an essential part of the evaluation of an interregional transmission project, not as part of 

interregional transmission coordination, but rather as part of the relevant regional 

transmission planning processes. As such, we continue to believe that the decision of 

whether and how to address these issues with regard to interregional transmission 

facilities in the regional transmission planning processes is a matter for public utility 

transmission providers to work out with their stakeholders in the development of 

compliance proposals.575

501. We clarify for Bonneville Power that Order No. 1000 only requires the 

development of a formal procedure to identify and jointly evaluate interregional 

transmission facilities that are proposed to be located in neighboring transmission 

planning regions.576 We emphasize, however, that while the Commission does not 

 575 Id.

576 Id. P 435.
Docket No. RM10-23-001 -377-

require any particular type of studies to be conducted, the purpose of identifying and 

jointly evaluating interregional transmission facilities is to determine whether they may 

more efficiently or cost-effectively meet transmission needs than regional transmission 

facilities.577 

502. We decline to expand the definition of an interregional transmission facility 

adopted in Order No. 1000, as requested by MISO Transmission Owners Group 1 and 

Wisconsin PSC. As the Commission explained in Order No. 1000, requiring joint 

evaluation of the effects of a new transmission facility proposed to be located solely in a 

single transmission planning region could, in effect, mandate interconnectionwide 

transmission planning. This is because transmission facilities located in one transmission 

planning region often have effects on multiple neighboring systems, which could trigger 

a chain of multilateral evaluation processes.578 While the definitions of an interregional 

transmission facility proposed by MISO Transmission Owners Group 1 and Wisconsin 

PSC could help to restrict the range of proposed new transmission facilities subject to 

joint evaluation, we disagree that they are sufficient to address the Commission’s concern 

that expanding the definition of an interregional transmission facility adopted in Order 

No. 1000 could mandate interconnectionwide transmission planning. Adopting MISO 

 577 Id. P 398.

578 Id. P 416.
Docket No. RM10-23-001 -378-

Transmission Owners Group 1 and Wisconsin PSC’s expanded definitions of an 

interregional transmission facility could still, in effect, mandate that certain transmission 

projects located solely in a single transmission planning region be planned on a 

multilateral, if not interconnectionwide, basis, and we are not persuaded that such a 

requirement is necessary at this time. The Commission exercised its discretion in this 

rulemaking to improve regional transmission planning and bilateral interregional 

transmission coordination in a manner that does not have the effect of requiring 

interconnectionwide planning. Moreover, we reiterate here the Commission’s conclusion 

in Order No. 1000 that imposing multilateral or interconnectionwide transmission 

coordination requirements at this time could frustrate the progress being made in the 

ARRA-funded transmission planning initiatives.579 

503. We also do not believe it is necessary to expand the definition of an interregional 

transmission facility, as argued by Midwest ISO Transmission Owners Group 1 and 

Wisconsin PSC, in order to ensure that the costs of a transmission facility located in a 

single transmission planning region that benefits a neighboring transmission planning 

region are allocated commensurately with the benefits it provides. As we explain more 

fully below,580 these arguments fail to take into account the relationship between the 

 579 Id. P 417.

580 See discussion infra at section IV.D.5.c.
Docket No. RM10-23-001 -379-

Commission’s cost allocation reforms and the other reforms contained in Order No. 1000 

and the need to balance a number of factors to ensure that the reforms achieve the goal of 

improved transmission planning. In particular, as we stated in Order No. 1000, these 

reforms establish a closer link between regional transmission planning and cost 

allocation, both of which involve the identification of beneficiaries. In light of that closer 

link, we continue to find that allowing one region to allocate costs unilaterally to entities 

in another region would effectively impose an affirmative burden on stakeholders to 

actively monitor transmission planning processes in numerous other regions in which 

they could be identified as beneficiaries and thus be subject to cost allocation. This 

would essentially result in interconnectionwide transmission planning with corresponding 

cost allocation, albeit conducted in a highly inefficient manner.581 

504. We note, however, that the public utility transmission providers in neighboring 

transmission planning regions may negotiate an agreement to share the costs of a 

particular transmission facility with the beneficiaries in another transmission planning 

region, as they always have been free to do.582 Further, nothing in Order No. 1000 

precludes public utility transmission providers in consultation with stakeholders from 

voluntarily developing and proposing interregional transmission coordination procedures 

 581 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 660.

582 Id. P 658.
Docket No. RM10-23-001 -380-

providing for the joint evaluation by more than one transmission planning region of a 

transmission facility located solely in one transmission planning region should the public 

utility transmission providers in neighboring transmission planning regions agree to do 

so.583 Also, we reiterate that Order No. 1000’s limited requirements for bilateral 

interregional transmission coordination do not prohibit either voluntary multilateral 

interregional transmission coordination or planning, or the development of stronger 

bilateral coordination agreements than the rule requires. 

505. Finally, Wisconsin PSC specifically mentions that transmission lines in MISO 

often provide potential benefits to PJM load. As the Commission recognized in Order 

No. 1000, MISO and PJM developed a cross-border cost allocation method in response to 

Commission directives related to their intertwined configuration that permits them, in 

certain cases, to allocate to one RTO or ISO the cost of a transmission facility that is 

located entirely within the other RTO or ISO. We reiterate here that Order No. 1000 does 

not require MISO and PJM to revise their existing cross-border cost allocation method in 

response to Cost Allocation Principle 4.584

2. Implementation of the Interregional Transmission Coordination 

Requirements

 583 Id. P 416.

584 Id. P 662.
Docket No. RM10-23-001 -381-

a. Procedure for Joint Evaluation

i. Final Rule

506. The Commission required the developer of an interregional transmission project to 

first propose its transmission project in the regional transmission planning processes of 

each of the neighboring regions in which the transmission facility is proposed to be 

located. The submission of an interregional transmission project in each regional 

transmission planning process will trigger the procedure under which the public utility 

transmission providers, acting through their regional transmission planning processes, 

will jointly evaluate the proposed transmission project.585 The Commission required that 

joint evaluation be conducted in the same general timeframe as, rather than subsequent 

to, each transmission planning region’s individual consideration of the proposed 

transmission project.586 For an interregional transmission facility to receive cost 

allocation under the interregional cost allocation method or methods developed pursuant 

to Order No. 1000, the Commission required that the transmission facility be selected in 

both of the relevant regional transmission plans for purposes of cost allocation.587 

Finally, the Commission directed each public utility transmission provider, through its 

 585 Id. P 436.

586 Id. P 439.

587 Id. P 436.
Docket No. RM10-23-001 -382-

transmission planning region, to develop procedures by which differences in planning 

criteria can be identified and resolved for purposes of jointly evaluating a proposed 

interregional transmission facility.588

ii. Requests for Rehearing and Clarification

507. Joint Petitioners and ITC Companies seek rehearing of the Commission’s 

requirement that both neighboring transmission planning regions must agree to include a 

proposed interregional transmission facility in their respective regional transmission 

plans for it to be eligible for interregional cost allocation. Instead, Joint Petitioners argue 

that the Commission should require the preparation and approval of an interregional plan, 

or at the very least, provide a mechanism by which a sponsor of an interregional 

transmission project can obtain Commission review of a disagreement or failure to act by 

and among affected planning regions. They assert that requiring each region to include 

an interregional facility in its respective plan is counterproductive because the 

Commission did not require the consistent use of specific planning horizons or the 

performance of particular scenario analyses for purposes of regional planning. 

Additionally, Joint Petitioners contend that even if a project is determined to be the most 

efficient, cost-effective project for the broader region composed of both planning regions, 

 588 Id. P 437.
Docket No. RM10-23-001 -383-

either region may veto the project because those broader benefits are not considered in 

the individual regional plans.

508. WIRES states that the planning experiences of RTOs and ISOs and the record in 

this proceeding contain many examples of planning procedures and criteria that are 

suitable for two regions to coordinate their planning efforts. WIRES adds that adopting 

these procedures, which establish fixed timelines for decision, data exchange 

requirements, planning assumptions, and standard modeling techniques, along with clear 

opportunities for exceptions where necessary, would shorten and rationalize planning 

processes without dictating outcomes. WIRES asserts that technical conferences could 

be useful for developing a consensus on these matters.

iii. Commission Determination

509. We deny Joint Petitioners’ and ITC Companies’ request for rehearing of Order 

No. 1000’s requirement that an interregional transmission facility must be selected in 

each relevant regional transmission plan for purposes of cost allocation to be eligible for 

cost allocation under the interregional cost allocation method or methods.589 Rather, we 

reaffirm this requirement. As stated above, Order No. 1000 establishes a closer link 

between transmission planning and cost allocation. As discussed more fully below in the 

 589 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 436.
Docket No. RM10-23-001 -384-

section on stakeholder participation,590 Order No. 1000 provides for stakeholder 

involvement in the consideration of an interregional transmission facility primarily 

through the regional transmission planning processes.591 We therefore conclude that this 

requirement is necessary to ensure that stakeholders have an opportunity to provide 

meaningful input with respect to proposed interregional transmission facilities before 

such facilities are selected in each relevant regional transmission plan for purposes of 

cost allocation.

510. We disagree with Joint Petitioners’ contention that Order No. 1000 did not require 

consistency in planning horizons or scenario analyses. In Order No. 1000, the 

Commission directed each public utility transmission provider, through its transmission 

planning region, to develop procedures by which differences in the data, models, 

assumptions, planning horizons, and criteria used to study a proposed interregional 

transmission project can be identified and resolved for purposes of jointly evaluating an 

interregional transmission project.592 This approach allows regions the flexibility to 

develop procedures that work for them, while still addressing the concern that joint 

evaluation of a proposed interregional transmission facility cannot be effective without 

 590 See discussion infra at section III.C.2.b.iii.

591 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 465; see also id. P 443.

592 Id. P 437.
Docket No. RM10-23-001 -385-

some effort by neighboring transmission planning regions to harmonize differences in the 

data, models, assumptions, planning horizons, and criteria used to study a proposed 

transmission project.593 We therefore decline to adopt WIRES’ suggestion that we 

require that public utility transmission providers implement certain specific planning 

procedures or criteria, or that we hold a technical conference to consider such matters. 

511. Moreover, we decline to require the preparation and approval of an interregional 

transmission plan or to adopt a mechanism for the Commission to review neighboring 

transmission planning regions’ disagreements about or failure to act on a proposed 

interregional transmission facility as requested by Joint Petitioners. Joint Petitioners have 

not convinced us that such measures are necessary in this generic rulemaking. As the 

Commission found in Order No. 1000, the interregional transmission coordination 

reforms do not require the creation of a distinct interregional transmission planning 

process to produce an interregional transmission plan or the formation of interregional 

transmission planning entities. Rather, the requirement is for public utility transmission 

providers to consider whether the local and regional transmission planning processes 

result in transmission plans that meet local and regional transmission needs more 

efficiently and cost-effectively, after considering opportunities for collaborating with 

 593 Id.
Docket No. RM10-23-001 -386-

public utility transmission providers in neighboring transmission planning regions.594 

However, as the Commission stated in Order No. 1000, public utility transmission 

providers may voluntarily engage in interregional transmission planning and, as relevant, 

rely on such a planning process to comply with the interregional transmission 

coordination requirements of Order No. 1000.595

512. Finally, we understand Joint Petitioners’ concern that a transmission planning 

region may decline to select an interregional transmission project in its regional 

transmission plan for purposes of cost allocation if the project does not sufficiently 

benefit that region, even if it is the more efficient or cost-effective project for the broader 

multiregional area. This is another version of the argument made by petitioners that 

prefer interconnectionwide transmission planning to regional transmission planning. 

However, we decline to require interconnectionwide planning in this rulemaking for the 

reasons set out in Order No. 1000 and summarized above. We understand that, under the 

interregional transmission coordination procedures of Order No. 1000, an interregional 

transmission facility is unlikely to be selected for interregional cost allocation unless each 

transmission planning region benefits or the transmission planning region that benefits 

compensates the region that does not through a separate agreement—and that this feature 

 594 Id. P 399.

595 Id.
Docket No. RM10-23-001 -387-

would not necessarily apply for interconnectionwide planning. We continue to believe 

however that, under the regional transmission planning approach adopted in Order No. 

1000, it is appropriate for each transmission planning region to determine for itself 

whether to select in its regional transmission plan for purposes of cost allocation an 

interregional transmission facility that extends partly within its regional footprint based 

on the information gained during the joint evaluation of an interregional transmission 

project. 

b. Stakeholder Participation

i. Final Rule

513. In Order No. 1000, the Commission did not require the interregional transmission 

coordination procedures to meet the requirements of the transmission planning principles 

required for local planning (under Order No. 890) and regional planning (under Order 

No. 1000).596 The Commission explained that stakeholders will have the opportunity to 

participate fully in the consideration of interregional transmission facilities during the 

regional transmission planning process, because each region must select such a facility in 

its regional transmission plan for purposes of cost allocation in order for it to be eligible 

for interregional cost allocation.597 The Commission also required public utility 

 596 Id. P 465.

597 Id.
Docket No. RM10-23-001 -388-

transmission providers to make transparent the analyses undertaken and determinations 

reached by neighboring transmission planning regions in the identification and evaluation 

of interregional transmission facilities.598 Last, the Commission required that each public 

utility transmission provider give stakeholders the opportunity to provide input into the 

development of its interregional transmission coordination procedures and the commonly 

agreed-to language to be included in its OATT.599

ii. Requests for Rehearing and Clarification

514. Transmission Dependent Utility Systems and PSEG Companies argue that the 

Commission should have required public utility transmission providers to provide for 

more stakeholder participation in the interregional coordination process and procedures. 

Transmission Dependent Utility Systems also seek clarification or, in the alternative, 

argue that the Commission should require on rehearing, that stakeholders have a 

meaningful opportunity to participate in the development of the interregional

coordination process before it is submitted to the Commission in a compliance filing, 

whether the process is reflected in the OATT or in a bilateral agreement. 

515. In addition, Transmission Dependent Utility Systems argue that stakeholders must 

be allowed to participate throughout the process to ensure that load-serving transmission 

 598 Id.

599 Id. P 466.
Docket No. RM10-23-001 -389-

customers receive treatment comparable to the treatment transmission providers accord 

their retail and wholesale merchant functions, as required by sections 205 and 217(b)(4), 

Order No. 890, and the judicial requirement for reasoned decision-making.600 PSEG 

Companies argue that Order No. 1000’s assumption that this issue will be addressed 

under the regional processes is unsupported. They also argue that the lack of a specific 

requirement for stakeholder participation is inconsistent with some of the other 

interregional coordination requirements in Order No. 1000, including requirements 

related to joint evaluation of interregional projects and the determination of beneficiaries 

of such projects.

516. Moreover, Transmission Dependent Utility Systems argue that stakeholders must 

have a meaningful opportunity to participate in the early stages of the process for 

identifying and evaluating possible interregional solutions to transmission customer 

concerns. Similarly, PSEG Companies recommend that the Commission require that 

interregional coordination procedures include information on: (1) how transmission 

providers will facilitate stakeholder participation; (2) how market participants can 

propose ideas for cross-border projects and identify and submit concerns about problems 

in one region caused by activity in another (and how to address those concerns); and (3) 

 600 Transmission Dependent Utility Systems at 18 (citing Motor Vehicle Mfrs. 

Ass’n v. State Farm Mut. Auto Ins. Co., 463 U.S. 29, 43 (1983)). 
Docket No. RM10-23-001 -390-

how transmission providers will accommodate and track in a transparent manner all 

questions, comments, and other input from stakeholders regarding data posted on 

coordination activities, as well as transmission providers’ responses.

517. Transmission Dependent Utility Systems also assert that Order No. 1000 fails to 

address their larger concern, which is that the interregional coordination processes fail to 

obligate public utility transmission providers to share with stakeholders the data 

exchanged among themselves, including study results, models, input data, and 

assumptions used in running those studies. Transmission Dependent Utility Systems are 

concerned that public utility transmission providers may contend that the obligation to 

share does not include load-serving customers. Further, Transmission Dependent Utility 

Systems state the Commission should clarify that the interregional planning data that is 

shared with load-serving entities must be sufficient to allow them to replicate the 

interregional planning study results, including models, base cases, data inputs, and 

assumptions. Transmission Dependent Utility Systems also believe it is important that 

benefit-to-cost analyses of interregional projects be transparent and verifiable to protect 

customers, ensure accuracy, and minimize ex post facto disputes regarding regional and 

interregional cost allocation.

iii. Commission Determination

518. First, we clarify for Transmission Dependent Utility Systems that each public 

utility transmission provider must provide stakeholders with a meaningful opportunity to 
Docket No. RM10-23-001 -391-

provide input into the development of its interregional transmission coordination 

procedures before those procedures are submitted to the Commission in its compliance 

filing, whether those procedures are included in its OATT or reflected in an interregional 

transmission coordination agreement.601 Accordingly, stakeholders must be afforded 

sufficient time to meaningfully comment on a public utility transmission provider’s 

proposed interregional transmission coordination procedures as they are being developed. 

519. In response to those petitioners that raise concerns regarding stakeholder 

participation in the interregional transmission coordination process, we reiterate the 

Commission’s statement in Order No. 1000 that stakeholder participation in the 

consideration of interregional transmission facilities is an important component of 

interregional transmission coordination. Moreover, we also reiterate that stakeholders 

will have the opportunity to provide input with respect to the consideration of 

interregional transmission facilities when these facilities are being considered in the 

regional transmission planning process. As stated above, Order No. 1000 provides that 

only if an interregional transmission facility is selected in each region’s transmission plan 

for purposes of cost allocation will that facility’s cost be allocated to either region.602 It 

is therefore through participation in the regional transmission planning process that 

 601 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 466.

602 Id. P 465.
Docket No. RM10-23-001 -392-

stakeholders will have the primary opportunity to participate fully in the consideration of 

interregional transmission facilities. While nothing in Order No. 1000 prohibits an 

interregional transmission coordination process from providing for more direct 

stakeholder involvement in interregional transmission coordination, it may be the case 

that much of the interregional transmission coordination would occur through sharing 

computer modeling results regarding the effects and benefits of a proposed interregional 

transmission facility, which may be harder for a broad community of stakeholders to 

participate in than would face to face meetings be. If we are being asked to require there 

be in-person meetings for interregional transmission coordination with all stakeholders 

attending, we would be concerned about requiring a cumbersome process that could 

necessitate significant expense and travel time to multiple neighboring regions by the 

large number of stakeholders in each region. We continue to believe it is sufficient and 

appropriate to allow for consideration of stakeholder interests by requiring that any 

decision on interregional cost allocation be affirmed by each of the transmission planning 

regions involved. 

520. For similar reasons, we decline to expand the requirements of Order No. 1000 

regarding the types and sufficiency of interregional transmission coordination 

information to be exchanged between regions and provided to stakeholders. We 

therefore affirm Order No. 1000’s requirement that, in order to facilitate stakeholder 

involvement, public utility transmission providers must, subject to appropriate 
Docket No. RM10-23-001 -393-

confidentiality protections and CEII requirements, make transparent the analyses 

undertaken and determinations reached by neighboring transmission planning regions in 

the identification and evaluation of interregional transmission facilities.603 

521. Further, we decline to adopt PSEG Companies’ recommendation that the 

Commission require the interregional transmission coordination procedures to include 

information on how stakeholders in one transmission planning region can raise issues and 

solutions regarding activity in another transmission planning region. The regional 

transmission planning process already provides stakeholders with the opportunity to 

present such concerns, and we continue to believe that these concerns are best addressed 

in the first instance through the regional transmission planning process, particularly as the 

solution may not involve an interregional transmission facility.

522. In light of this, however, we clarify that each public utility transmission provider 

must describe in its OATT how its regional transmission planning process will enable 

stakeholders to provide meaningful and timely input with respect to the consideration of 

interregional transmission facilities. Moreover, as requested by PSEG Companies, we 

require that each public utility transmission provider must explain in its OATT how 

stakeholders and transmission developers can propose interregional transmission facilities 

for the public utility transmission providers in neighboring transmission planning regions 

 603 Id.
Docket No. RM10-23-001 -394-

to evaluate jointly. This is consistent with Order No. 1000’s requirement that on 

compliance, public utility transmission providers must describe the methods by which 

they will identify and evaluate interregional transmission facilities.604 

IV. Cost Allocation

523. In Order No. 1000, the Commission required that each public utility transmission 

provider have in its OATT a method, or set of methods, for allocating the costs of new 

regional transmission facilities selected in the regional transmission plan for purposes of 

cost allocation (“regional cost allocation”); and that each public utility transmission 

provider within two (or more) neighboring transmission planning regions develop a 

method or set of methods for allocating the costs of new interregional transmission 

facilities that each of the two (or more) neighboring transmission planning regions 

selected for purposes of cost allocation because such facilities would resolve the 

individual needs of each region more efficiently or cost-effectively (“interregional cost 

allocation”).605 The OATTs of all public utility transmission providers in a region must 

include the same cost allocation method or methods adopted by the region. 

 604 Id. P 398.

605 Id. P 482. For purposes of Order No. 1000, a regional transmission facility is a 

transmission facility located entirely in one region. An interregional transmission facility 

is one that is located in two or more transmission planning regions. A transmission 

facility that is located solely in one transmission planning region is not an interregional 

transmission facility. Id. P 482 n.374.
Docket No. RM10-23-001 -395-

524. The regional and interregional cost allocation methods each must adhere to six 

regional and interregional cost allocation principles: (1) costs must be allocated in a way 

that is roughly commensurate with benefits; (2) there must be no involuntary allocation 

of costs to non-beneficiaries; (3) a benefit to cost threshold ratio cannot exceed 1.25; (4) 

costs must be allocated solely within the transmission planning region or pair of regions 

unless those outside the region or pair of regions voluntarily assume costs; (5) there must 

be a transparent method for determining benefits and identifying beneficiaries; and (6) 

there may be different methods for different types of transmission facilities.606 The 

Commission directed that, subject to these general cost allocation principles, public 

utility transmission providers in consultation with stakeholders would have the 

opportunity to agree on the appropriate cost allocation methods for their new regional and 

interregional transmission facilities, subject to Commission approval.607 The 

Commission also found that if public utility transmission providers in a region or pair of 

regions could not agree, the Commission would use the record in the relevant compliance 

filing proceeding(s) as a basis to develop a cost allocation method or methods that meets 

the Commission’s requirements.608 Finally, the Commission emphasized that its cost 

 606 Id. PP 622-93.

607 Id. P 588.

608 Id. P 482.
Docket No. RM10-23-001 -396-

allocation requirements are designed to work in tandem with its transmission planning 

requirements to identify more appropriately the benefits and the beneficiaries of new 

transmission facilities so that transmission developers, planners and stakeholders can take 

into account in the transmission planning process who would bear the costs of 

transmission facilities, if constructed.609

A. Legal Authority for Cost Allocation Reforms 

1. Final Rule

525. In Order No. 1000, the Commission determined that its jurisdiction is broad 

enough to allow it to ensure that all beneficiaries of services provided by specific 

transmission facilities bear the costs of those benefits regardless of their contractual 

relationship with the owner of those transmission facilities.610 The Commission stated 

that this comports fully with the specific characteristics of transmission facilities and 

transmission services, and that the provisions of Order No. 1000 are necessary to fulfill 

the Commission’s statutory duty of ensuring rates, terms and conditions of jurisdictional 

service are just and reasonable and not unduly discriminatory or preferential.611 

 609 Id. P 483.

610 Id. P 531.

611 Id.
Docket No. RM10-23-001 -397-

526. The Commission based its finding on the language of section 201(b)(1) of the 

FPA, which gives the Commission jurisdiction over “the transmission of electric energy 

in interstate commerce.”612 The Commission concluded that its jurisdiction therefore 

extends to the rates, terms and conditions of transmission service, rather than merely 

transactions for such transmission service specified in individual agreements.613 

Moreover, the Commission found that section 201(b)(1) gives the Commission 

jurisdiction over “all facilities” for the transmission of electric energy, and this 

jurisdiction is not limited to the use of those transmission facilities within a certain class 

of transactions.614 As a result, the Commission stated that it has jurisdiction over the use 

of these transmission facilities in the provision of transmission service, which includes 

consideration of the benefits that any beneficiaries derive from those transmission 

facilities in electric service regardless of the specific contractual relationship that the 

beneficiaries may have with the owner or operator of these transmission facilities.615 

 612 Id. P 532.

613 Id.

614 Id.

615 Id.
Docket No. RM10-23-001 -398-

527. The Commission also explained that neither section 205 nor section 206 of the 

FPA state or imply that an agreement is a precondition for any transmission charges.616 

The Commission also concluded that cost allocation cannot be limited to voluntary 

arrangements because if it were the Commission could not address free rider problems 

associated with new transmission investment, and it could not ensure that rates, terms and 

conditions of jurisdictional service are just and reasonable and not unduly 

discriminatory.617 

528. In addition, the Commission explained that its approach is consistent with the 

concept of cost causation, because a full cost causation analysis may involve “an 

extension of the chain of causation”618 beyond those causes captured in voluntary 

arrangements. The Commission explained that in order to identify all causes, it is 

necessary to some degree to begin with their effects, i.e., the benefits that they engender 

and then work back to their sources.619 The Commission noted that this point was 

 616 Id. P 533.

617 Id. P 535.

618 Id. P 536 (quoting KN Energy, 968 F.2d 1295 at 1302). 

619 Id.
Docket No. RM10-23-001 -399-

acknowledged in the Seventh Circuit’s characterization of cost causation in Illinois 

Commerce Commission.

620 The Seventh Circuit stated that:

To the extent that a utility benefits from the costs of new facilities, it may 

be said to have “caused” a part of those costs to be incurred, as without 

the expectation of its contributions the facilities might not have been built, 

or might have been delayed.621

The court fully recognized that, to identify causes of costs, one must to some degree 

begin with benefits.622

529. Last, the Commission emphasized that its cost allocation reforms are a component 

of its transmission planning reforms, which require that, to be eligible for regional or 

interregional cost allocation, a proposed new transmission facility first must be selected 

in a regional transmission plan for purposes of cost allocation, which depends on a full 

assessment by a broad range of regional stakeholders of the benefits accruing from 

transmission facilities planned according to the reformed transmission planning 

processes. 

2. Requests for Rehearing or Clarification 

 620 Id. P 537.

621 Id. (quoting Illinois Commerce Commission, 576 F.3d at 476 (emphasis 

supplied)).

622 Id.
Docket No. RM10-23-001 -400-

a. Petitioners’ Arguments That The FPA Requires a 

Contract before Costs Are Allocated

530. Several petitioners argue that the Commission does not have the jurisdiction to 

require that beneficiaries of service provided by specific transmission facilities bear the 

costs of those benefits regardless of their contractual relationship with the owner of those 

facilities.623 They contend that the Commission’s requirement to allocate costs without 

regard to whether there is a contract or service provided is inconsistent with the FPA.624 

For example, Ad Hoc Coalition of Southeastern Utilities and Large Public Power Council 

assert that the Commission has confused the FPA’s expression of jurisdiction in section 

201 with the grant of substantive authority, and that the Commission’s interpretation of 

what section 201 allows would make sections 205 and 206 superfluous. They also assert 

 623 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Coalition for Fair 

Transmission Policy; Large Public Power Council; National Rural Electric Coops; New 

York ISO at 4 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 539); New 

York PSC; New York Transmission Owners; Northern Tier Transmission Group at 5 

(citing Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002) (stating that in the 

absence of statutory authority authorization for its act, an agency’s action is plainly 

contrary to law and cannot stand)); Sacramento Municipal Utility District; Southern 

Companies at 96-97 (citing Illinois Commerce Comm’n, 576 F.3d 470 (2009); Morgan 

Stanley Capital Group, Inc. v. Pub. Util. Dist. No. 1 of Snohomish County, Washington et 

al., 554 U.S. 527, 533 (2008); Ottertail Power Co. v. United States, 410 U.S. 366, 374 

(1973); In re Permian Basin Area Rate Cases, 390 U.S. 747, 822 (1968); United Gas 

Pipeline Co. v. Mobile Gas Service Corp., 350 U.S. 332, 343 (1956)); and Vermont 

Agencies at 6, 10 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 532).

624 See, e.g., Coalition for Fair Transmission Policy; Southern Companies; 

National Rural Electric Coops; and Ad Hoc Coalition of Southeastern Utilities.
Docket No. RM10-23-001 -401-

that the Commission’s view of section 201 would also render section 203 superfluous and 

allow the Commission to compel sales or purchases of jurisdictional facilities when the 

public interest required it. 

531. National Rural Electric Coops state that a contractual relationship is required as a 

basis for a jurisdictional rate or charge. They maintain that in providing for Commission 

regulation of rates “for or in connection with the transmission or sale of electric energy,” 

the FPA ties the Commission’s rate authority directly to the jurisdictional service 

provided by those public utilities.625 They argue that where an entity takes no 

jurisdictional service from a public utility, the Commission cannot permit the public 

utility to collect charges from that entity. Several other petitioners make similar 

arguments.626 Large Public Power Council argues that the natural implication of terms in 

section 205 and 206 such as “made,” “demanded,” “received,” “observed,” “charged,” or 

“collected” is that they pertain to rates assessed to utility customers in connection with an 

agreement to take service.627

 625 National Rural Electric Coops at 14 (quoting 16 U.S.C. 824d(a)).

626 See, e.g., National Rural Electric Coops; New York ISO; Northern Tier 

Transmission Group; Sacramento Municipal Utility District; Southern Companies; and 

Vermont Agencies.

627 Large Public Power Council at 35.
Docket No. RM10-23-001 -402-

532. Large Public Power Council argues that the approach taken in Order No. 1000 to 

cost allocation for new transmission development is at odds with the Commission’s 

requirement that interstate gas pipeline projects be self-sustaining and not be subsidized 

by existing services. Large Public Power Council states that courts have held that the 

Natural Gas Act and the FPA should be interpreted similarly, and the Commission must 

explain substantial discrepancies.

533. Sacramento Municipal Utility District argues that if the rates that the Commission 

regulates are for transmission service, it logically follows that only customers who 

receive the transmission service can be charged for it. Vermont Agencies contend that 

even if the statute were ambiguous, it would still be unreasonable to allocate costs on the 

beneficiary theory because it would not follow logically from the Commission’s 

acknowledgement that it only regulates the provision of transmission service. 

534. Sacramento Municipal Utility District argues that the Commission never disputed 

its arguments that: (1) in theory, a utility could build a facility and then claim that 

because it provided a benefit to someone remote from the facility, that entity – customer 

or not – should bear some of the costs; and (2) it cannot force unwilling customers to pay 

for additional service.628 Sacramento Municipal Utility District argues that Order No. 

 628 Sacramento Municipal Utility District at 9 (citing Exxon Mobil Corp. v. FERC, 

430 F.3d 1166, 1176-77 (D.C. Cir. 2005)). 
Docket No. RM10-23-001 -403-

1000 allows “beneficiaries” of new transmission facilities to be charged even if they are 

not getting a new service.629 

535. National Rural Electric Coops also argue that FPA sections 205 and 206 require 

that costs and benefits be fairly allocated between the two parties providing and receiving 

jurisdictional service. They contend that the fact that there may be third-party 

beneficiaries to an agreement does not change the analysis. They state that, even though 

other utilities may look more like transmission customers than entities that benefit 

indirectly from increased transmission capacity and are not subject to jurisdictional rates, 

this does not mean that those utilities have greater legal or contractual obligations.

536. Coalition for Fair Transmission Policy argues that the Commission is incorrect in 

finding that it has the legal authority to authorize public utilities to charge third party 

beneficiaries for transmission facilities because the issue has not been squarely addressed 

by the courts.630 It asserts that the matter has not merited analysis or discussion because 

it is an undisputed maxim that lawful rates are founded on privity of contracts. 

 629 Sacramento Municipal Utility District at 9 & n.4. 

630 Coalition for Fair Transmission Policy at 20 (citing Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 at P 540).
Docket No. RM10-23-001 -404-

537. Several petitioners disagree that free rider problems are a basis for the cost 

allocation requirements established in Order No. 1000.631 Southern Companies argue 

that under Order No. 1000, the mere potential of free riders is absolute poison to the 

justness and reasonableness of a cost allocation methodology. They contend that Order 

No. 1000 does not explain who these free riders may be, what benefits might be taken 

without compensation, or whether in the absence of the new transmission, they would 

require and financially support their own new transmission. Southern Companies add 

that Order No. 1000 does not explain why complaints under section 206 are insufficient 

for resolving free rider problems.

538. Southern Companies also assert that the FPA does not allow the allocation of costs 

to third-party non-customers because it does not allow the Commission to regulate cost 

allocations or rate structures that apply to the conveyance of abstract nonjurisdictional 

“benefits” other than electricity. Southern Companies assert that the FPA requires that 

cost allocations and rate structures must apply to the conveyance of benefits that are the 

actual use of transmission facilities or services (or support services required to provide 

the same). They argue that Mobil Oil Corp. v. FPC supports this conclusion.632 In that 

 631 See, e.g., Ad Hoc Coalition of Southeastern Utilities; Large Public Power 

Council; and National Rural Electric Coops. 

632 483 F.2d 1238 (D.C. Cir. 1973).
Docket No. RM10-23-001 -405-

case, the court found that the Commission exceeded its authority when it required cost 

allocation and rate structures for certain nonjurisdictional liquids as part of the 

transportation of natural gas.633 

539. Sacramento Municipal Utility District argues that the Commission is incorrect in 

determining that it can require non-public utilities participating in a regional planning 

organization to accept an allocation of costs for new transmission facilities approved by 

the regional entity as a condition of reciprocity, even if they have no customer 

relationship with the transmission provider. It also states that the Commission’s 

longstanding position is that without evidence that two systems are in fact acting as one, 

the Commission cannot mandate the use of a single joint rate.634 Sacramento Municipal 

Utility District argues that if the Commission cannot mandate the use of joint rates, it 

cannot mandate that an entity pay the rates charged by a utility with which it has no 

contractual or tariff-based customer/provider relationship at all. 

 633 Southern Companies at 100-101 (citing Mobil Oil, 483 F.2d 1238, 1248; also

Office of Consumers’ Counsel v. FERC, 655 F.2d 1132, 1148 (D.C. Cir. 1980)). 

634 Sacramento Municipal Utility District at 15 (citing Ft. Pierce Utils. Comm’n v. 

FERC, 730 F.2d 778 (D.C. Cir. 1984); Richmond Power & Light v. FERC, 574 F.2d 610 

(D.C. Cir. 1978); Alabama Power Co. v. FERC, 993 F.2d 1557 (D.C. Cir. 1993); Illinois 

Power Co., 95 FERC ¶ 61,183, at 61,144 (2002)). 
Docket No. RM10-23-001 -406-

540. Several petitioners argue that the courts have rejected attempts to impose cost 

liability without a contract for Commission-jurisdictional service.635 For example, 

Southern Companies and Coalition for Fair Transmission Policy argue that the entire 

design of the FPA is based on the premise that those who impose charges have a service 

relationship with those on whom charges are levied.636 They assert that this is supported 

by the Supreme Court’s finding in Morgan Stanley, where it stated that “the regulatory 

system created by the FPA is premised on contractual agreements voluntarily devised by 

the regulated companies.”637 Coalition for Fair Transmission Policy states that in Otter 

 635 See, e.g., Coalition for Fair Transmission Policy at 19-20 (citing Morgan 

Stanley Capital Group, Inc. v. Public Utility District No. 1 of Snohomish County, 

Washington, 554 U.S. 527, 533 (2008)); Illinois Commerce Commission; National Rural 

Electric Coops; New York PSC; Ad Hoc Coalition of Southeastern Utilities; and Large 

Public Power Council. 

636Southern Companies at 97 (citing Morgan Stanley Capital Group Inc. v. Pub. 

Util. Dist. No. 1 of Snohomish County, Washington, 554 U.S. 527, 533 (2008); Otter Tail 

Power Co. v. United States, 410 U.S. 366, 374 (1973); In re Permian Basin Area Rate 

Cases, 390 U.S. 747, 822 (1968); United Gas Pipeline Co. v. Mobile Gas Service Corp., 

350 U.S. 332, 343 (1956)). See also Coalition for Fair Transmission Policy at 20-21.

637 Southern Companies at 97-98 (quoting Morgan Stanley, 554 U.S. at 533 (2008) 

(citing and quoting with approval Permian Basin Rate Cases, 390 U.S. at 822); also 

citing KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) (“[I]t has been 

traditionally required that all approved rates reflect to some degree the costs actually 

caused by the customer who must pay them.”) (emphasis added); Alabama Electric 

Cooperative, Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982) (“Properly designed rates 

should produce revenue from each class of customers which match, as closely as 

practicable, the costs to serve each class or individual customer.”) (emphasis added)). 

See also Coalition for Fair Transmission Policy at 20-21; New York PSC at 6. 
Docket No. RM10-23-001 -407-

Tail Power Co. v. United States, the Supreme Court wrote that Congress had rejected a 

pervasive regulatory scheme for transmission planning and cost allocation “in favor of 

voluntarily contractual relationships.”638

541. Ad Hoc Coalition of Southeastern Utilities also asserts that a utility’s ability to 

collect rates is a matter of its contractual relationship with its customers, and the 

Commission’s authority is limited to reviewing rates and, if unlawful, to remedying them. 

It asserts that this is apparent on the face of the FPA, and it has been a fundamental 

building block of energy law since the Supreme Court articulated the Mobile-Sierra 

doctrine.639 Ad Hoc Coalition of Southeastern Utilities argues that the Mobile-Sierra 

doctrine makes it clear that the Commission’s oversight of utility rates is subordinate to 

parties’ contractual rights. It argues that the Commission errs in its attempt to distinguish 

Mobile-Sierra on the ground that “we are dealing here with conditions under which costs 

can be recovered in rates, not conditions under which contracts can be altered.”640 Large 

Public Power Council makes similar arguments and also asserts that while the 

 638 Coalition for Fair Transmission Policy at 20-21 (quoting Otter Tail Power Co. 

v. United States, 410 U.S. 366, 374 (1973)).

639 Ad Hoc Coalition of Southeastern Utilities at 68 (citing United Gas Pipe Line 

Co. v. Mobile Corp., 350 U.S. 332 (1955 (Mobile); FPC v. Sierra Pacific Co., 350 U.S. 

348 (1956) (Sierra)); see also Northern Tier Transmission Group at 6.

640 Ad Hoc Coalition of Southeastern Utilities at 70 (quoting Order No. 1000,

FERC Stats. & Regs. ¶ 31,323 at P 540).
Docket No. RM10-23-001 -408-

Commission has the authority to alter the terms of a contract for service under FPA 

section 206, subject to the “public interest” standard, it cannot establish a right to recover 

costs where no contractual authority exists. 

542. National Rural Electric Coops state that a central holding of the Mobile-Sierra

cases was that the Commission’s authority to review and modify jurisdictional rates does 

not confer new rights on the public utilities subject to the Commission’s jurisdiction. 

They argue that Order No. 1000 is inconsistent with Mobile-Sierra in concluding that 

costs may be allocated to entities in the absence of contractual privity because neither 

section 205 nor section 206 of the FPA state or imply that an agreement is a precondition 

for any transmission charges. National Rural Electric Coops maintain that it is 

impermissible for the Commission to infer authority to act based on the lack of an 

express Congressional denial of such authority.641

543. Several petitioners maintain that both court and Commission precedent show that 

a section 205 filing requires a customer or other contractual relationship between the 

filing utility and the ratepayer.642 New York Transmission Owners assert that FPA 

 641 National Rural Electric Coops at 16 (citing American Petroleum Institute v. 

EPA, 52 F.3d 1113 (D.C. Cir. 1995); Mobil Oil Corp. v. FPC, 483 F.2d 1238 (D.C. Cir. 

1973)).

642 New York ISO at 4 (citing In re Permian Basin Area Rate Cases, 390 U.S. 747, 

822 (1968)). See also New York ISO at 5-9 (citing Midwest Indep. Transmission Sys. 

Operator, Inc., 131 FERC ¶ 61,173 (2010) and Commonwealth Edison Co., 129 FERC ¶ 

(continued...)
Docket No. RM10-23-001 -409-

section 205 does not authorize a utility to submit (and does not authorize the Commission 

to accept) a rate filing where the utility lacks a contractual or customer relationship with 

the entities to which the rate will be charged. They state that an administrative agency 

cannot exceed the authority granted to it by Congress and that the agency’s role is not to 

preempt Congressional action or to fill gaps where it believes federal action is needed.643 

544. Ad Hoc Coalition of Southeastern Utilities asserts that there is no Commission or 

court case approving an allocation of costs outside a contractual relationship. National 

Rural Electric Coops state that the Commission cited Illinois Commerce Commission for 

the proposition that to identify causes of costs, one must begin with benefits, but this 

statement does not address cost allocation in the absence of contractual privity when a 

non-customer is shown to benefit from a particular transmission project. They maintain 

that the court in Illinois Commerce Commission strongly suggested that costs must be 

recovered from customers when it noted that rates must “reflect to some degree the costs 

actually caused by the customer who must pay them.”644 Southern Companies makes 

 

61,298 (2009), order on reh’g, 132 FERC ¶ 61,268 (2010)); Ad Hoc Coalition of 

Southeastern Utilities at 68-69 (citing 16 U.S.C. § 824d(a)); and New York Transmission 

Owners at 4.

643 New York Transmission Owners at 5-6 (citing California Indep. Sys. Operator 

Corp. v. FERC, 372 F.2d 395, 398 (D.C. Cir. 2004) and Office of Consumers’ Counsel v. 

FERC, 655 F.2d 1132, 1152 (D.C. Cir. 1980)).

644 National Rural Electric Coops at 20-21 (quoting Illinois Commerce 

(continued...)
Docket No. RM10-23-001 -410-

similar arguments. National Rural Electric Coops argue that Commission forbid cost 

allocations to non-customers when it refused to allow MISO to charge Green Mountain 

Energy Company (Green Mountain) for Seams Elimination Charge/Cost 

Adjustments/Assignment (SECA) costs under MISO’s tariff because Green Mountain did 

not directly contract with MISO for transmission service, even though Green Mountain 

purportedly benefited from the transmission service.645 

545. Vermont Agencies similarly argue that if the Commission is now asserting 

authority to allocate costs to non-customers, it failed to provide a reasonable basis for its 

change in course.646 They state that AEP recognizes that utilities, in limited 

circumstances, can seek protection when they are forced to transmit for others, but an 

entity cannot build a transmission facility and then seek compensation for the benefit it 

provides to an entity that did not ask for it. Sacramento Municipal Utility District states 

that AEP provides no basis for charging an entity that simply benefits in some way from 

the new line’s existence but has not caused loop flow through unscheduled deliveries.

 

Commission, 576 F.3d 470, 476 (7th Cir. 2009) (emphasis added by National Rural 

Electric Coops)). 

645 National Rural Electric Coops at 18 (citing MISO, 131 FERC ¶ 61,173 (2010) 

(SECA Order)). 

646 Vermont Agencies at 14-15 (citing American Elec. Power Co., 49 FERC ¶ 

61,377, at 62,381 (1986) (AEP); Southern Cal. Edison Co., 70 FERC ¶ 61,087 (1995); 

Midwest Indep. Transmission Sys. Operator, Inc., 131 FERC ¶ 61,173, at P 421 (2010)). 
Docket No. RM10-23-001 -411-

546. Sacramento Municipal Utility District also reiterates its argument that the 

Commission relied upon cases for authority to allocate costs to non-customers that are 

inapt because they all involved situations where a customer/provider relationship 

existed.647 It states that the Commission dismissed this argument in Order No. 1000 by 

stating that the issue was not before the court in any of those cases. It argues that the 

Commission did not defend its interpretation of these cases.648 Moreover, Sacramento 

Municipal Utility District and Vermont Agencies assert that if the rationale for charging 

non-customers rests on cases the Commission now concedes are inapplicable, saying that 

those cases do not preclude it from allocating costs to non-customers does not answer just 

what does authorize the Commission to do so.

547. Sacramento Municipal Utility District also argues that the Commission’s policy on 

cost allocation in Order No. 1000 would do more harm than good. For example, it 

contends that the risk of facing charges as an incidental beneficiary of a facility that a 

 647 Sacramento Municipal Utility District at 10-11 (citing Midwest Indep. 

Transmission Sys. Operator, Inc., 109 FERC ¶ 61,168, P 60 (2004); see also Midwest 

Indep. Transmission Sys. Operator, Inc., 113 FERC ¶ 61,194, P 1-4, 10 (2005); Midwest 

Indep. Transmission Sys.Operator, Inc., 122 FERC ¶ 61,084, P22 (2008); Midwest ISO 

Transmission Owners v. FERC, 373 F.3d 1361 (D. C.Cir. 2004)).

648 Sacramento Municipal Utility District at 11 (citing Tennessee Gas 

Transmission Co. v. FERC, 789 F.2d 61, 62-63 (D.C. Cir. 1986)). 
Docket No. RM10-23-001 -412-

party did not want and will not use may discourage, rather than promote, regional 

cooperation. 

b. Arguments That Order No. 1000’s Cost Allocation 

Reforms Are Inconsistent With the Cost Causation 

Principle

548. Illinois Commerce Commission contends that the Commission misinterpreted the 

cost causation principle and failed to recognize the important distinction between cost 

causers and beneficiaries. It maintains that the applicable court decisions do not support 

equating cost causers and beneficiaries for purposes of cost allocation. It argues that the 

cost causation principle associates beneficiaries with cost causers only to the extent that 

the facilities might be delayed or not built without the revenues expected from them. 

Illinois Commerce Commission asserts that costs must be allocated primarily to such cost 

causers. Allocations to any other beneficiaries must be substantiated through an 

appropriate process.

549. Illinois Commerce Commission asserts that Illinois Commerce Commission 

makes it clear that when a line is planned to address the reliability concerns of one 

subregion of an RTO, there should be no cost allocations to others when the benefits to 

them are trivial or nonexistent.649

 649 Illinois Commerce Commission contends that this is the case with respect to the 

projects at issue on remand in the PJM Interconnection, LLC matter in Docket No. EL06-

121-006.
Docket No. RM10-23-001 -413-

550. New York ISO states that transmission facilities may provide some greater or 

lesser degree of “benefit” to a broad range of system users, but showing that an entity 

receives some incidental benefit (based on a standard that has not yet been articulated) 

does not prove that the entity is receiving transmission service over that facility and 

should be assessed costs. 

c. Arguments That The Commission Did Not Show That 

Existing Rates Are Unjust and Unreasonable

551. FirstEnergy Service Company and California ISO argue that the FPA does not 

authorize the Commission to require the filing of new rates without first finding that the 

existing rate is unjust, unreasonable, or unduly discriminatory or preferential. 

FirstEnergy Service Company maintains that the Commission concludes that the absence 

of clear cost allocation rules can impede the development of transmission facilities, 

which may adversely affect jurisdictional rates.650 FirstEnergy Service Company argues 

that where no methodologies exist, the Commission cannot fulfill the basic requirement 

of section 206 that it find existing contracts or rates unjust, unreasonable, or unduly

discriminatory or preferential. It maintains that section 206 applies to rates “demanded, 

observed, charged or collected,” not to rates that might apply to a future jurisdictional 

 650 FirstEnergy Service Company at 14 (quoting Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 579).
Docket No. RM10-23-001 -414-

service.651 FirstEnergy Service Company asserts that, if, on the other hand, there is an 

existing rate that applies to cost allocation for regional and interregional transmission 

facilities, then the Commission’s conclusion that the absence of a rate is inapplicable, and 

the Commission does not find any such existing rates unjust or unreasonable. California 

ISO makes a similar argument. It also argues that the Commission cannot use section 

206 to promote goals such as cost-effectiveness and transmission expansion, and rates are 

not unjust and unreasonable simply because another rate might be more just and 

reasonable.652 California ISO states that its tariff already includes provisions that ensure 

the construction of needed projects, and it takes cost-effectiveness into consideration 

when choosing projects.

552. FirstEnergy Service Company also asserts that the courts have admonished the 

Commission for seeking to impose new rates without first determining that the existing 

rate is unjust, unreasonable, or unduly discriminatory or preferential.653 It cites Public 

 651 FirstEnergy Service Company at 18.

652 California ISO at 18 (citing Duke Energy Trading and Marketing, LLC, 315 

F.3d 377, 382 (D.C. Cir. 2003)).

653 FirstEnergy Service Company at 16 (citing Western Resources, Inc. v. FERC, 9 

F.3d 1568, 1578 (D.C. Cir. 1993); Tenn. Gas Pipeline Co. v. FERC, 860 F.2d 446 (D.C. 

Cir. 1988); Northern Natural Gas Co. v. FERC, 827 F.2d 779 (D.C. Cir. 1987); Sea 

Robin Pipeline Co. v. FERC, 795 F.2d 182 (D.C. Cir. 1986); ANR Pipeline Co. v. FERC, 

771 F.2d 507 (D.C. Cir. 1985); Panhandle E. Pipe Line Co. v. FERC, 613 F.2d 1120 

(D.C. Cir. 1980)).
Docket No. RM10-23-001 -415-

Service Commission of New York v. FERC in which the court disagreed with the 

Commission that it could act under section 4 of the NGA rather than section 5 in finding 

that an existing zone allocation in the utility’s rates was unlawful and prescribing a new 

allocation because the utility had proposed a rate increase under section 4 of the NGA.654 

FirstEnergy Service Company states that the court reversed the Commission’s decision 

because the Commission did not make a finding under section 5 of the NGA. 

FirstEnergy Service Company also cites other cases in which it states that the court 

rejected Commission filing requirements as an impermissible attempt to avoid the 

strictures of sections 4 and 5 of the NGA.655

553. FirstEnergy Service Company argues that the Supreme Court has found that the

right to file new rates and contracts belongs solely to public utilities under the FPA.656 It 

disagrees with the Commission’s assertion that it is setting standards for filings under 

 654 FirstEnergy Service Company at 16-17 (citing Public Service Commission of 

New York v. FERC, 642 F.2d 487 at 1344-45). FirstEnergy Service Company states that 

although the Court was describing the NGA, the FPA and NGA are interpreted in 

parallel. FPC v. Sierra Pacific Power Co., 350 U.S. 348, at 353 (1956).

655 FirstEnergy Service Company at 17)FirstEnergy Service Company at 17 (citing 

Public Service Commission of New York v. FERC, 866 F.2d 487 (D.C. Cir. 1989) and 

Consumers Energy Co. v. FERC, 226 F.3d 777 (6th Cir. 2000)).

656 FirstEnergy Service Company at 13 (quoting United Gas Pipeline Co. v. 

Mobile Gas Ser. Co., 350 U.S. 332 at 341). 
Docket No. RM10-23-001 -416-

section 205 rather than interfering with public utilities’ rights to file new rates,657 it 

argues that Order No. 1000 directs transmission providers to amend their tariffs to 

include cost allocation provisions for regional and interregional facilities. FirstEnergy 

Service Company contends that the Commission may issue guidelines that will be used to 

determine whether future rates for regional and interregional facilities will be just and 

reasonable, but section 205 does not permit it to compel filings of rates or contracts.

554. Ad Hoc Coalition of Southeastern Utilities argues that the Commission cannot 

support its determination by simply finding that rates will be unjust and unreasonable 

without a cost allocation mechanism. As support for this position, Ad Hoc Coalition of 

Southeastern Utilities argues that the Commission’s authority over practices affecting 

rates under section 206 is limited to practices that directly affect rates,658 and effectively 

requires utilities to pay transmission developers for investments that the utilities do not 

use indirectly affects rates for jurisdictional service. Large Public Power Council makes 

similar arguments.

 657 FirstEnergy Service Company at 18 (quoting Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 547).

658 Ad Hoc Coalition of Southeastern Utilities at 73 (citing California Independent 

System Operator v. FERC, 372 F.3d at 403).
Docket No. RM10-23-001 -417-

3. Commission Determination

555. Many petitioners object to the Commission’s cost allocation reforms in Order No. 

1000 based on what they consider to be fundamental principles concerning both the 

Commission’s jurisdiction as well as the nature of transmission operations and the 

benefits they provide. Many of the arguments raised by petitioners share common 

themes, and we thus will address them collectively as far as possible. In order to do this 

comprehensively, we think it is important first to state briefly what the Commission did, 

and did not, require in Order No. 1000 with respect to cost allocation and to address some 

of the basic principles that inform those decisions. 

556. The cost allocation reforms in Order No. 1000 are grounded in our determination 

that it is necessary to establish a closer link between regional transmission planning and 

cost allocation, both of which involve the identification of beneficiaries of new 

transmission facilities. Planning of new transmission facilities in a regional transmission 

planning process involves assessing how such facilities will affect the existing 

transmission grid and how they will benefit users of the grid within the relevant region.659 

Cost allocation for new transmission facilities that are selected in a regional transmission 

 659 Users of the regional transmission grid could be, for example, public utility 

transmission providers that may effectively rely on transmission facilities of another 

transmission provider in order to provide transmission service, whether or not there is a 

service agreement between those public utility transmission providers. 
Docket No. RM10-23-001 -418-

plan for purposes of cost allocation similarly involves assigning the costs of those 

facilities in a manner that accounts for the identified benefits. Recognizing this 

relationship, the Commission found that the lack of clear ex ante cost allocation methods 

that identify beneficiaries of proposed regional and interregional transmission facilities 

may be impairing the ability of public utility transmission providers to implement more 

efficient or cost-effective transmission solutions identified during the transmission 

planning process. The Commission also found that linking transmission planning and 

cost allocation through the regional transmission planning process would increase the 

likelihood that transmission facilities in regional transmission plans are constructed.

557. This emphasis on a closer link between regional transmission planning and cost 

allocation also informs the cost allocation principles that the Commission adopted in 

Order No. 1000. The Commission found that in light of the need for a closer link 

between regional transmission planning and cost allocation, allowing one region to 

allocate costs unilaterally to entities in another region would impose too heavy a burden 

on stakeholders to actively monitor transmission planning processes in numerous other 

regions, from which they could be identified as beneficiaries and be subject to cost 

allocation. The Commission also stated that if it expected such participation, the 

resulting regional transmission planning processes could amount to interconnectionwide 

transmission planning with corresponding cost allocation. The Commission stated 

clearly that Order No. 1000 does not require either interconnectionwide transmission 
Docket No. RM10-23-001 -419-

planning or interconnectionwide cost allocation. We reaffirm these findings here, as 

discussed further below with respect to Cost Allocation Principle 4.660

558. Against this backdrop, we note the actions that the Commission took in Order No. 

1000 with respect to cost allocation are based on its jurisdiction under section 201(b)(1) 

of the FPA over the transmission of electric energy in interstate commerce and the 

facilities for such transmission and its duty to exercise it authority under sections 205 and 

206 of the FPA to ensure that Commission-jurisdictional rates are just and reasonable and 

not unduly discriminatory or preferential.661 The nature and scope of this authority must 

be viewed in the context of the specific characteristics of transmission facilities and their 

operation, among other considerations. 662

559. Transmission operations are characterized by a number of unique features that are 

essential for understanding the Commission’s position, and therefore they merit 

summarizing here. Electric energy does not travel on a preset path but rather along all 

available pathways in accordance with the laws of physics.663 Continuous fluctuations in 

 660 See discussion infra at section IV.D.5.c.

661 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 532, 535.

662 As discussed further below, the Commission finds that there is a need to 

balance a number of factors to ensure that the reforms adopted in Order No. 1000 achieve 

the goal of improved planning and cost allocation for transmission in interstate 

commerce. See discussion infra at section IV.D.5.c.

663 An interconnected AC transmission grid essentially functions as a single piece 

(continued...)
Docket No. RM10-23-001 -420-

the demand for power and in generation operations affect power flows throughout the 

transmission grid. This means that electric energy received by an individual customer at 

any one time could be delivered over any number of transmission facilities that constitute

the transmission grid. Changes in demand for or supply of electricity at any point in the 

system will change flows on all the transmission lines to varying degrees, often in ways 

that are not easily controlled.664 

560. The courts have recognized this fundamental fact and have acknowledged that it 

has important implications for the Commission’s regulation of transmission service. The 

D.C. Circuit has stated:

. . . In order to determine a utility’s cost of providing a 

transmission service, the Commission typically treats a 

transmission network . . . as an integrated system. In other 

words, all of the individual facilities used to transmit 

electricity are treated as if they were part of a single machine. 

The Commission takes this approach on the ground that a 

transmission system performs as a whole; the availability of 

multiple paths for electricity to flow from one point to 

another contributes to the reliability of the system as a whole. 

This principle has a strong basis in the physics of electrical 

transmission for there is no way to determine what path 

electricity actually takes between two points or indeed 

 

of equipment. See, e.g., Tampa Electric Co., 99 FERC ¶ 61,192, at 61,796 (2002).

664 See, e.g., Jack A. Casazza, Transmission Access and Retail Wheeling: The Key 

Questions, in ELECTRICITY TRANSMISSION PRICING AND TECHNOLOGY 81 (Michael 

Einhorn and Riaz Siddiqi eds., 1996); Narain G. Hingorani, Flexible AC Transmission 

System (Facts), in id. 242; Karl Stahlkopf, The Second Silicon Revolution, in id. 263. 
Docket No. RM10-23-001 -421-

whether the electricity at the point of delivery was ever at the 

point of origin.

As a corollary, in determining permissible prices for 

transmission services, the Commission treats each 

transmission customer not as using a single transmission path 

but rather as using the entire transmission system.

665

In other words, in the case of transmission, there is only one service—service over the 

entire grid.666

561. The Commission appreciates that these prior decisions related to transmission 

rates for a single public utility transmission provider’s facilities. However, the principle 

underlying those decisions is equally applicable across larger regions of the transmission 

system. Given the physics of power flows, and the ownership of transmission facilities in 

the United States, the actual transmission facilities that are affected by a particular 

transaction are owned by multiple, interconnected transmission providers irrespective of 

whether the transaction involves a single contract for transmission service with one of the 

 665 Northern States Power Co. v. FERC, 30 F.3d 177, 179 (D.C. Cir. 1994) 

(emphasis supplied) (Northern States); see also Western Massachusetts Electric 

Company v. FERC, 165 F.3d 922, 927 (D.C. Cir. 1999) (stating that “[w]hen a system is 

integrated, any system enhancements are presumed to benefit the entire system”). 

666 We note that this principle is not, in itself, determinative of what would 

constitute a just and reasonable cost allocation method. For example, a regional cost 

allocation method must satisfy the principles set forth in Order No. 1000 and affirmed 

here, including that the costs of transmission facilities must be allocated to those within 

the transmission planning region that benefit from those facilities in a manner that is 

roughly commensurate with estimated benefits. See, e.g., Order No. 1000, FERC Stats. 

& Regs. ¶ 31,323 at P 622.
Docket No. RM10-23-001 -422-

owners of the transmission facilities or multiple contracts with all of the owners of the 

transmission facilities along a contract path. That is, the transmission grid constitutes a 

common infrastructure, “a cohesive network moving energy in bulk.”667 Entities that 

contract for service on the transmission grid cannot “choose” to affect only the

transmission facilities for which they have entered into a contract, as some petitioners 

contend. Similarly, those entities cannot claim that they are not using or benefiting from 

such transmission facilities simply because they did not enter a contract to use them. 

562. We also note that in an interconnected electric transmission system, the 

enlargement of one path between two points can provide greater system stability, lower 

line losses, reduce reactive power needs, and improve the throughput capacity on other 

facilities. Given the nature of transmission operations, it is possible that an entity that 

uses part of the transmission grid will obtain benefits from transmission facility 

enlargements and improvements in another part of that grid regardless of whether they 

have a contract for service on that part of the grid and regardless of whether they pay for 

those benefits. This is the essence of the “free rider” problem the Commission is seeking 

to address through its cost allocation reforms.668 Any individual beneficiary of a new 

transmission facility has an incentive to defer investment in the anticipation that other 

 667 Public Serv. Co. of Colo., 62 FERC ¶ 61,013, at 61,061 (1993).

668 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 534-35.
Docket No. RM10-23-001 -423-

beneficiaries in the region will value the project enough to fund its development. This 

can lead to situations in which no developer moves forward, adversely affecting 

development of transmission facilities and, as a result, rates for jurisdictional services.

563. The Supreme Court has stated that the Commission’s jurisdiction is “to follow the 

flow of electric energy, an engineering and scientific, rather than a legalistic or 

governmental, test.”669 Indeed, the Supreme Court described the entire FPA as “couched 

largely in the technical language of the electric art.”670 

564. Despite these considerations, many petitioners argue that the costs of new 

transmission facilities can only be allocated within a preexisting contractual relationship. 

These arguments are based on the assumption that only preexisting contracts define 

jurisdictional transmission service. In relying exclusively on contracts to perform this

role, petitioners are advocating a legalistic test for assessing the scope of the 

Commission’s jurisdiction that is inconsistent with the Supreme Court’s interpretation of

the FPA in Connecticut Light & Power Co. Contracts do not reflect the actual flow of 

electric energy on the transmission grid. Nor do contracts define or limit the benefits that 

an entity receives from its use of the transmission grid. To argue that costs for new 

 669 Connecticut Light & Power Co. v. F.P.C., 324 U.S. 515, 529 (1945)

(Connecticut Light & Power Co.).

670 Id.
Docket No. RM10-23-001 -424-

transmission facilities can be allocated only through preexisting contractual relations 

means that some entities that will benefit from those transmission facilities simply cannot 

be allocated costs roughly commensurate with the benefits that they receive. This is 

inconsistent with the well-established Commission and judicial interpretation of the FPA 

and contrary to the requirement that transmission rates be just and reasonable and not 

unduly discriminatory or preferential.671

565. This explains why the cost allocation provisions of Order No. 1000, which seek to 

allocate costs to beneficiaries in a region roughly commensurate with benefits they 

receive, are consistent with the statement in Illinois Commerce Commission that “[a]ll 

approved rates [must] reflect to some degree the costs actually caused by the customer 

who must pay them.”672 Petitioners argue that because the court in Illinois Commerce 

Commission used the word “customer” in the quote above, it suggests that costs must be 

recovered from entities that have a preexisting contractual relationship with the entity 

seeking the cost allocation. However, given the nature of cost causation itself, some 

 671 We also note that Order No. 1000 states: “Neither section 205 nor section 206 

of the FPA state or imply that an agreement is a precondition for any transmission 

charges. These statutory provisions speak of rates and charges that are ‘made,’ 

‘demanded,’ ‘received,’ ‘observed,’ ‘charged,’ or ‘collected’ by a public utility.” Order 

No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 533.

672 Illinois Commerce Commission, 576 F.3d 470 at 476 (internal citations 

omitted).
Docket No. RM10-23-001 -425-

entities that actually cause costs would not be required to pay them if they could utilize 

the absence of a contractual relationship to shield themselves from an allocation of costs. 

Rather than contractual relationships, the benefits received by users of the regional 

transmission grid provide a basis for how costs should be allocated. Petitioners’ 

argument would inappropriately revise the Illinois Commerce Commission court’s 

explanation that the cost causation principle requires that “all approved rates [must] 

reflect to some degree the costs actually caused by the customer who must pay them” by 

adding a further requirement that the customer also agree to be responsible for such costs. 

The court did not, however, reach such a conclusion. We thus reject the claim by Ad Hoc 

Coalition of Southeastern Utilities that the Commission’s adherence to the cost causation 

principle is subordinate to parties’ contractual rights. 

566. Moreover, our interpretation of the court’s use of “customer” in Illinois Commerce 

Commission is consistent with the statements that the court makes immediately thereafter. 

The court first notes that compliance with the principle involved is evaluated “‘by 

comparing the costs assessed against a party to the burdens imposed or benefits drawn by 

that party.’”673 The court did not condition its statement on a need for a preexisting 

contractual relationship. Rather, the court allowed for a full comparison of costs for any 

party that imposed burdens on, and benefited from enhancement of, the network 

 673 Id. (internal citations omitted). 
Docket No. RM10-23-001 -426-

transmission grid. Furthermore, the court follows this by stating that “[t]o the extent that 

a utility benefits from the costs of new facilities, it may be said to have ‘caused’ a part of 

those costs to be incurred, as without the expectation of its contributions the facilities 

might not have been built, or might have been delayed.”674 That is precisely the role that 

the Commission’s cost allocation reforms play within the context of its planning reforms. 

That the lack of ex ante cost allocation methods that identify the beneficiaries of 

proposed regional and interregional transmission facilities may be impairing the ability of 

public utility transmission providers to implement more efficient or cost-effective 

transmission solutions identified in the transmission planning process.675

567. Some petitioners also argue that the Supreme Court’s statement in Morgan Stanley

that “the regulatory system created by the [FPA] is premised on contractual agreements 

voluntarily devised by the regulated companies”676 means that a preexisting contractual 

relationship is an essential precondition of cost allocation. Given the nature of 

transmission grid operations, we disagree that this statement by the Supreme Court means 

that contracts, which will not fully reflect how transmission facilities are impacted by

power flows, are the only device that defines what rates are just and reasonable and not 

 674 Id.

675 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 499. 

676 Morgan Stanley, 554 U.S. at 533.
Docket No. RM10-23-001 -427-

unduly discriminatory or preferential. We do not read the importance that the Supreme 

Court ascribes to voluntary contracts in Morgan Stanley to imply that entities that use the 

transmission grid are entitled to structure their contractual arrangements so that they are 

shielded from paying costs that are roughly commensurate with the benefits that they 

receive. In any event, Morgan Stanley never stated that, by refusing to sign a contract, an 

entity benefiting from another’s improvement of the regional transmission grid can limit 

its obligation to something less than an obligation to pay for all benefits that it receives. 

568. The obligation under the FPA to pay costs allocated under a regional or 

interregional cost allocation method is imposed by a Commission-approved tariff 

concerning the charges made by a public utility transmission provider for the use of the 

public utility transmission provider’s facility. Such use is voluntary, and it does not 

become less so because it is determined in part by immutable laws of physics. Voluntary 

use therefore also entails voluntary acceptance of the terms and conditions of use set forth 

in the tariff, including an applicable cost allocation.

569. We disagree with National Rural Electric Coops’ argument that Order No. 1000 is 

conferring new rights on public utility transmission providers. We are not conferring 

new rights on public utility transmission providers when we seek to ensure that they can 

allocate the costs of their new transmission facilities to the beneficiaries of those 

facilities. Nor are we claiming a power based solely on the fact that there is not an 

express withholding of such power, as National Rule Electric Coops claim. We are 
Docket No. RM10-23-001 -428-

acting under the provisions of section 206 of the FPA applied in accordance with the 

reasoning that we have set forth both here and in Order No. 1000. 

570. In response to Large Public Power Council’s argument that the references in 

sections 205 and 206 to rates “made,” “demanded,” “received,” “observed,” “charged,” 

or “collected” pertain to rates assessed to utility customers in connection with an 

agreement to take transmission service, we reiterate the Commission’s finding in Order 

No. 1000 that “nothing in these sections precludes flows of funds to public utility 

transmission providers through mechanisms other than agreements between the service 

provider and the beneficiaries of those transmission facilities.”677 As explained in further 

detail above, an entity that uses the transmission grid will necessarily use transmission 

facilities owned by multiple owners, and the FPA permits a public utility transmission 

provider to charge for the costs of using its transmission facilities. 

571. Contrary to the claim of National Rural Electric Coops, all cost allocation 

contemplated by Order No. 1000 pertains to rates “for or in connection with the 

transmission . . . of electric energy.” Order No. 1000 does not permit a public utility 

transmission provider to collect charges other than in connection with the use of the 

transmission grid. In suggesting that it does, National Rural Electric Coops misconstrues 

the criteria for identifying the scope of transmission usage. That scope is defined by the 

 677 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 533.
Docket No. RM10-23-001 -429-

transmission grid operations, not simply the terms of individual contracts, which can 

diverge from the underlying transmission grid operations. It is the purpose of the cost 

allocation method or methods required by Order No. 1000 to align cost responsibility 

with the reality of transmission grid operations in the case of new transmission facilities 

selected in the regional transmission plan for purposes of cost allocation.678

572. Moreover, contrary to Large Public Power Council’s argument, the cost allocation 

provisions of Order No. 1000 do not alter any existing contract provisions governing the 

use of existing transmission facilities and, therefore, are not inconsistent with MobileSierra doctrine regarding revision of contracts. Order No. 1000 requires each public 

utility transmission provider to revise its OATT to include a method, or set of methods, 

for allocating the costs of new transmission facilities selected in a regional transmission 

plan for purposes of cost allocation – not transmission facilities already in service.

573. We reject the characterization of the cost allocation requirements of Order No. 

1000 as authorizing allocation of costs to third-party beneficiaries. Order No. 1000 

authorizes allocation of costs to entities that benefit in their own right from new 

transmission facilities selected in a regional transmission plan for purposes of cost 

allocation. To the extent that an entity is not required to pay for a benefit that it receives, 

 678 As explained above, providing for such cost allocation will help to ensure that 

rates are just and reasonable and not unduly discriminatory or preferential as required by 

section 205 of the FPA. 16 U.S.C. 824d.
Docket No. RM10-23-001 -430-

it is a free rider not a third party beneficiary. The fact that a free rider benefits from a 

transaction between two other entities does not make it a third party beneficiary, which is 

a legal concept that refers to parties that have a right to a benefit under a contract between 

two other entities. Such rights are not at issue here. 

574. We thus also disagree with National Rural Electric Coops that Order No. 1000 

suggests that charges could be imposed on “third party beneficiaries” such as “[s]teel 

producers, crane operators, and wind turbine manufacturers who may find more 

customers for their products and services as a result of increased transmission capacity. . . 

.”679 We note that Regional Cost Allocation Principle 1 provides that: 

in determining the beneficiaries of interregional transmission 

facilities, transmission planning regions may consider 

benefits including, but not limited to, those associated with 

maintaining reliability and sharing reserves, production cost 

savings and congestion relief, and meeting Public Policy 

Requirements.680

While this statement explicitly is not intended to be an exhaustive recitation of possible 

benefits, our expectation is that additional types of benefits would be “in connection 

with” transmission of electric energy. We do not intend that these benefits should 

include such things as increased sales of goods and services used in the construction of 

new transmission facilities. 

 679 National Rural Electric Coops at 21.

680 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 622.
Docket No. RM10-23-001 -431-

575. Likewise, in response to Southern Companies, Order No. 1000 does not authorize 

cost allocations or rate structures that apply to conveyance of “benefits [that] are not the 

actual use of transmission facilities or services (or support services required to provide 

same).”681 We see no inconsistency between the cost allocation provisions of Order No. 

1000 and Mobil Oil Corp. v. FPC, as Southern Companies claim. In that case, the court 

held that the Commission had jurisdiction over rates for the transportation of natural gas 

on an interstate pipeline but not over rates for the transportation of certain nonjurisdictional liquid hydrocarbons that were also transported on the pipeline. The court 

held that the Natural Gas Act restricted the Commission’s jurisdiction to rates for natural 

gas transportation.682 Southern Companies maintains that Order No. 1000 authorizes 

rates for non-jurisdictional benefits that are analogous to the non-jurisdictional liquid 

hydrocarbons in Mobil Oil Corp. v. FPC. However, Order No. 1000 does not do this. It 

authorizes cost allocation for benefits consistent with Regional Cost Allocation Principle 

1, which explicitly refers to matters that are subject to Commission jurisdiction. For the 

same reasons, we disagree with the claim of Vermont Agencies that Order No. 1000 

authorizes allocation of costs to persons that benefit in some way from the existence of a 

transmission facility even if they use no transmission service at all. 

 681 Southern Companies at 99.

682 Mobil Oil Corp. v. FPC, 483 F.2d 1238, 1246-47 (D.C. Cir. 1973).
Docket No. RM10-23-001 -432-

576. In response to Southern Companies regarding free riders, we note that free riders 

for purposes of Order No. 1000 are entities who do not bear cost responsibility for 

benefits that they receive in their use of the transmission grid, specifically benefits they 

receive from new transmission facilities selected in a regional transmission plan for 

purposes of cost allocation. Such benefits include the traditional benefits that 

transmission facilities can provide, such as lowered congestion, increased reliability, and 

access to generation resources. Southern Companies state that the Commission does not 

address whether such entities would pursue or support new transmission facilities in the 

absence of a transmission project that is entitled to cost allocation, but this overlooks the 

purpose of the cost allocation requirements of Order No. 1000. They are intended to 

promote regional and interregional transmission planning that facilitates more efficient or 

cost-effective transmission infrastructure development. The lack of ex ante cost 

allocation methods that identify the beneficiaries of proposed regional and interregional 

transmission facilities may be impairing the ability of public utility transmission 

providers to implement more efficient or cost-effective transmission solutions identified 

in the transmission planning process. For this reason, individual complaints under 

section 206 of the FPA would not suffice to overcome the free rider problem because 

litigating complaints burdens and unduly delays the transmission planning process. 

Individual complaint procedures thus do not permit effective transmission planning. 
Docket No. RM10-23-001 -433-

577. The Commission has not confused the FPA’s expression of jurisdiction in section 

201 with a grant of substantive authority. Ad Hoc Coalition of Southeastern Utilities and 

Large Public Power Council argue that according to the Commission’s rationale, its 

jurisdiction under section 201 over transmission service and transmission facilities would 

also cover the matters for which specific authority is granted in sections 205 and 206, as 

well as section 203, thereby rendering those sections superfluous. As the Commission 

found in Order No. 1000, section 201 simply sets forth the facilities and transactions in 

interstate commerce that are subject to the Commission’s jurisdiction under Part II of the 

FPA. Our authority to act in Order No. 1000 on matters subject to our jurisdiction arises 

under section 206 of the FPA, specifically our authority to establish requirements 

regarding transmission planning and cost allocation which are practices affecting rates. 

The Commission’s jurisdiction permits that authority to be applied in a way that follows 

“the flow of electric energy, an engineering and scientific, rather than a legalistic or 

governmental, test,”683 and Order No. 1000’s application of the principle of cost 

causation is a reasonable exercise of that authority. However, such action is not based 

directly on section 201. It is based on section 206, which we apply to matters that are 

within the scope of our jurisdiction set forth in section 201. Moreover, we disagree with 

those petitioners that argue that our interpretation of section 201 in Order No. 1000 could 

 683 Connecticut Light & Power Co., 324 U.S. at 529.
Docket No. RM10-23-001 -434-

render either section 203, section 205, or section 206 of the FPA superfluous, because as 

we explain above, section 201 sets forth the subject matter over which the Commission 

exercises its jurisdiction pursuant to those other sections. 

578. Contrary to Large Public Power Council’s contention, the cost allocation 

requirements of Order No. 1000 are not at odds with the Commission’s policy on 

interstate gas pipeline development regarding subsidization of development by existing 

shippers. The requirements of Order No. 1000 are based on the principle of cost 

causation, which requires that costs be allocated in a way that is roughly commensurate 

with benefits. The principle of cost causation is intended to prevent subsidization by 

ensuring that costs and benefits correspond to each other. Indeed, in seeking to eliminate 

free riders on the transmission grid, Order No. 1000 seeks to eliminate a form of 

subsidization, as free riders by definition are entities who are being subsidized by those 

who pay the costs of the benefits that free riders receive for nothing.

579. We disagree with Sacramento Municipal Utility District’s assertion that Order No.

1000 fails to prevent a utility from building a transmission facility and then simply 

claiming that a remote entity receives benefits from it and thus must bear some of the 

costs. Under Order No. 1000, for a regional cost allocation method to apply to a new 

regional or interregional transmission facility, the transmission facility must first be 

selected in a regional transmission plan or plans for purposes of cost allocation. This 

means that the public utility transmission providers in a region, in consultation with 
Docket No. RM10-23-001 -435-

stakeholders, have evaluated a given facility and determined that it provides benefits that 

merit cost allocation under a regional method. As such, a developer of a transmission 

facility will not be entitled to recover costs from other entities without its facility being 

subject to the requirements of the regional transmission planning process, including the 

selection of its facility in the regional transmission plan for purposes of cost allocation. 

580. We also disagree with Sacramento Municipal Utility District that Order No. 1000 

forces unwilling customers to pay for additional transmission service or to be charged 

even if they are not getting a new transmission service. Order No. 1000 requires that new

costs be allocated in a way that is roughly commensurate with the benefits derived from 

the new transmission facilities that are eligible for cost allocation in accordance with 

Order No. 1000. As discussed above, entities that receive benefits from these facilities in 

the course of their use of the transmission grid cannot be characterized as “unwilling 

customers.” New York ISO notes that benefits come in various degrees, and it maintains 

that entities should not be charged for an “incidental benefit.” But again, Order No. 1000 

requires that costs be allocated in a way that is roughly commensurate with benefits, and 

the court stated in Illinois Commerce Commission that entities cannot be allocated costs 

for benefits that are trivial in relation to those costs.684 All cost allocation methods will 

 684 Illinois Commerce Commission, 576 F.3d at 476.
Docket No. RM10-23-001 -436-

be subject to Commission review and approval, and issues related to the appropriateness 

of a particular method or methods can be raised at that time. 

581. Sacramento Municipal Utility District’s argument that joint rates are necessary for 

cost recovery in the case of a regional cost allocation under Order No. 1000, describes a 

false dilemma. It argues that without evidence that two systems are in fact acting as one, 

the Commission cannot mandate the use of a single joint rate, and if it cannot mandate 

the use of joint rates, it cannot mandate that an entity pay the rates charged by a utility 

with which it has no contractual or tariff-based customer/provider relationship. However, 

our position regarding the role of preexisting contractual relationships goes to the 

problem of cost allocation, not cost recovery, which Sacramento Municipal Utility 

District focuses on when it speaks of the payment of charges and which Order No. 1000 

does not address.685 Moreover, Order No. 1000 requires that the tariffs of transmission 

providers in a region contain the regional cost allocation method or methods, which 

means that in any event, there will be a tariff basis for implementing a cost allocation. 

We thus reject the claim that a regional cost allocation could be implemented only 

through a joint rate. 

582. Turning to arguments that Order No. 1000 represents a change in policy expressed 

in prior cases, we disagree with National Rural Electric Coops’ contention that the cost 

 685 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 563.
Docket No. RM10-23-001 -437-

allocation provisions of Order No. 1000 are contradicted by the Commission’s refusal to 

allow MISO to charge Green Mountain for SECA costs under MISO’s tariff because 

Green Mountain did not directly contract with MISO for transmission service. In the 

SECA Order, the Commission found merely that Green Mountain’s affiliate BP Energy, 

not Green Mountain, was responsible for paying the SECA charges because the contract 

between the affiliate and Green Mountain stipulated that BP Energy was responsible for 

paying MISO for network transmission service.686 The Commission found that since 

SECA charges were intended to be surcharges assessed to the transmission customer 

taking transmission service, and BP Energy, not Green Mountain, was taking 

transmission service from MISO, BP Energy was responsible for paying the SECA 

charges.687 The Commission emphasized on rehearing of the SECA Order that MISO’s 

tariff specifically provided for its transmission customers to pay SECA charges, and 

therefore the fact that BP Energy was the transmission customer, not Green Mountain, 

was pivotal to the Commission’s conclusion that BP Energy was responsible for the 

SECA charges.688 This conclusion was based on a reading of the requirements of the 

MISO tariff, and as such, it cannot be read as establishing general principles regarding 

 686 SECA Order, 131 FERC ¶ 61,173 at P 422.

687 Id. P 423.

688 136 FERC ¶ 61,244 at P 205.
Docket No. RM10-23-001 -438-

the authority of a public utility transmission provider to collect charges for the 

transmission of electric energy, as National Rural Electric Coops argue. 

583. Vermont Agencies and Sacramento Municipal Utility District argue that the cost 

allocation reforms of Order No. 1000 represent a change in policy from the position that 

the Commission took in AEP, and they maintain that the Commission has failed to 

explain this change in policy. AEP dealt with unintended loop flows on existing 

facilities, which the Commission viewed as an operational issue that “in the first 

instance” was to be dealt with by “the interconnected parties” establishing “mutually 

acceptable operating practices.”689 The Commission also stated that if the party 

complaining of unintended loop flows on its facilities could show that they created “a 

burden on its system, [it] can file a transmission service rate for Commission 

consideration which would account for any unauthorized loop flows.”690 Vermont 

Agencies and Sacramento Municipal Utility District describe Order No. 1000 as 

containing a policy change on this point because in their view, the Commission maintains 

in Order No. 1000 that “it could allocate the costs of new transmission facilities to 

entities that somehow benefit from their existence – whether or not they take service from 

the utility,” whereas AEP “addresses the issue of compensation where the utility is 

 689 AEP, 49 FERC ¶ 61,377, at 62,381.

690 Id.
Docket No. RM10-23-001 -439-

involuntarily forced to provide service.”691 However, we see no fundamental difference 

between AEP and Order No. 1000 precisely because individual owners of facilities on an 

interconnected grid “can file a transmission service rate for Commission consideration”

under AEP. Additionally, it is because such owners will often forgo grid enlargements 

that benefit many owners of other facilities who will not pay for these enlargements that 

Order No. 1000 seeks to ensure that the former may be compensated through a cost 

allocation to the latter.

584. We also disagree with Vermont Agencies and Sacramento Municipal Utility 

District that Order No. 1000 represents a change in policy because the Commission has 

“rejected assessment of charges” in situations such as that presented in AEP.

692 The 

Commission did not reject an assessment of charges in AEP. It stated that the operational 

issue in question was in the first instance to be dealt with through mutually acceptable 

operating practices, but a rate filing would be appropriate if the loop flows created a 

burden on the system. Moreover, Order No. 1000 does not deal with operating problems 

on existing transmission facilities but rather solely with benefits to be derived from new 

transmission facilities that regional participants themselves select as having broad 

regional benefits, and it deals with cost allocation for such new facilities as integral to 

 691 Vermont Agencies at 16; Sacramento Municipal Utility District at 14.

692 Vermont Agencies at 16-17; Sacramento Municipal Utility District at 14.
Docket No. RM10-23-001 -440-

transmission planning. In this respect, Order No. 1000 does not express a change a 

policy position taken in AEP because AEP does not deal with planning and cost 

allocation for new transmission facilities and expresses no policy with regard to these 

matters.

585. In response to Illinois Commerce Commission’s argument that beneficiaries are to 

be associated with cost causers only to the extent that transmission facilities might be 

delayed or not built without the revenues expected from them, we note that it is for this

reason that the cost allocation requirements of Order No. 1000 are necessary. By 

allocating costs in a way that is roughly commensurate with benefits, the requirements 

help to ensure that more efficient and cost-effective transmission solutions are 

implemented and that this occurs without undue delay. In addition, one of the purposes 

of the regional transmission planning process is to identify the beneficiaries of a proposed 

transmission facility. This addresses Illinois Commerce Commission’s concern about the 

substantiation of benefits through an appropriate process.

586. We also disagree with Sacramento Municipal Utility District that the 

Commission’s position on cost allocation is likely to do more harm than good by 

discouraging regional cooperation. On the contrary, Order No. 1000 is intended to 

encourage the development of more efficient and cost-effective transmission solutions to 

regional transmission needs, which will promote considerable economic benefits in the 

form of lower congestion, greater reliability, and greater access to generation resources. 
Docket No. RM10-23-001 -441-

Therefore, we do not believe that the Commission’s reforms will discourage cooperation 

when the potential gains from cooperation are so great.

587. Finally, several petitioners also argue that the Commission must first find an 

existing rate to be unjust, unreasonable or unduly discriminatory or preferential before it 

can take the actions regarding cost allocation that it took in Order No. 1000. We disagree 

that such a finding must be made case-by-case rather than generically. As explained 

above,693 the Commission is not required to make individual findings concerning the 

rates of individual public utility transmission providers when proceeding under FPA 

section 206 by means of a generic rule.694 Nor do we agree with FirstEnergy Service 

Company that Commission actions taken in a rulemaking cannot apply to future 

jurisdictional transmission service. Commission rulemakings are prospective in their 

effect, and when the Commission proceeds by rule it can conclude that “any tariff 

violating the rule would have such adverse effects . . . as to render it ‘unjust and 

unreasonable’” within the meaning of section 206 of the FPA.695 The effects that a tariff 

would have include effects on future jurisdictional transmission service. 

 693 See discussion supra at section II.

694 Associated Gas Distributors v. FERC, 824 F.2d at 1008.

695 Id. (emphasis in original).
Docket No. RM10-23-001 -442-

588. We further disagree with FirstEnergy Service Company’s assertion that where no 

cost allocation method or methods exist, the Commission cannot use section 206 as a 

basis for requiring them. The basis for the Commission’s reforms in Order No. 1000 is 

that transmission planning for transmission service and the associated allocation of costs 

for new transmission facilities are practices that affect rates for purposes of section 

206.696 The Commission also explained that the allocation of transmission costs is often 

contentious and prone to litigation,697 and that the lack of ex ante cost allocation methods 

that identify the beneficiaries of proposed regional and interregional transmission 

facilities may be impairing the ability of public utility transmission providers to 

implement more efficient or cost-effective transmission solutions identified in the 

transmission planning process.698 The absence of a cost allocation method or methods 

also has an adverse effect on rates by making it difficult to deal with free rider problems 

related to new facilities. The Commission’s authority to require the adoption of a cost 

allocation method or methods arises directly from its authority under section 206 to 

ensure that practices that affect transmission rates, such as transmission planning, are just 

and reasonable and not unduly discriminatory or preferential. 

 696 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 58.

697 Id. P 498.

698 Id. P 499. 
Docket No. RM10-23-001 -443-

589. FirstEnergy Service Company’s argument that section 205 does not permit the 

Commission to require the filing of rates or contracts is equally flawed. Here, 

FirstEnergy Service Company is simply arguing that all rates are initially to be proposed 

by public utility transmission providers. However, the Commission is not requiring the 

proposal of a particular rate. It is requiring that public utility transmission providers have 

a cost allocation method or methods in their OATTs to ensure that the costs of new 

transmission facilities selected in a regional transmission plan for purposes of cost 

allocation are properly allocated to beneficiaries. It is for public utility transmission 

providers to propose an actual method or methods. The Commission is simply requiring 

that any cost allocation method or methods that are proposed meet certain general 

principles established in Order No. 1000. 

590. The case law cited by FirstEnergy Service Company to support the proposition 

that the Commission cannot impose a new rate without first determining that an existing 

rate is unjust, unreasonable, or unduly discriminatory or preferential reinforces our above 

points. All the cases that FirstEnergy Service Company cites in this connection involve 

situations in which the court found that the Commission had moved beyond rejecting a 

proposed rate to the task of redesigning it.699 The Commission is not here “imposing” 

 699 See, e.g., Western Resources, Inc. v. FERC, 9 F.3d 1568, 1578-79 (D.C. Cir. 

1993).
Docket No. RM10-23-001 -444-

any rates, as it is not specifying, designing, or redesigning any rates. Instead it is 

requiring that all public utility transmission providers have a cost allocation method or 

methods for certain new transmission facilities that comply with a broad set of general 

principles. 

591. We agree with California ISO that rates are not unjust and unreasonable simply 

because another rate might be more just and reasonable. However, this point applies in a 

situation where the status quo has been found to be just and reasonable and not unduly 

discriminatory or preferential, which is not the case here. California ISO argues that in 

its case such a finding is necessary because it has voluntarily included in its tariff 

provisions that ensure the construction of needed transmission projects, and it takes into 

account cost-effectiveness in choosing these transmission projects. This argument 

misconstrues the Commission’s actions here, which are to ensure that certain minimum 

requirements pertaining to transmission planning and cost allocation are in place. 

California ISO’s practices may already satisfy some of these requirements, in which case 

it need only explain how it satisfies them in its compliance filing.700 This, however, does 

not show that there is no need for such requirements. 

592. Ad Hoc Coalition of Southeastern Utilities questions the Commission’s ability to 

require a cost allocation method or methods on the grounds that section 206 limits the 

 700 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 565, 583.
Docket No. RM10-23-001 -445-

Commission’s authority over practices affecting rates to those that directly affect rates. 

Cost allocation is a practice that affects rates because the effect of a cost allocation 

method or methods is quite direct, as it determines who is responsible for specific costs. 

As explained above, Order No. 1000 found that the lack of a regional cost allocation 

method known in advance to transmission planners and the existence of free riders, result 

in inefficient transmission planning that impedes the development of more efficient and 

cost effective new transmission facilities, with the result that jurisdictional rates are 

higher than they would otherwise be. As we have noted previously, we disagree with Ad 

Hoc Coalition of Southeastern Utilities’ contention that requiring utilities to pay for 

facilities that they do not use does not directly affect rates for jurisdictional transmission 

service and is therefore beyond the Commission’s authority. This argument ignores the 

reality that any entity connected to the transmission grid may benefit from a transmission 

facility whether or not it is connected to, or specifically requests service from, a particular 

transmission facility for which costs have been allocated.701 Order No. 1000’s cost 

allocation reforms are therefore intended to ensure that all of these beneficiaries are 

allocated costs roughly commensurate with the benefits they receive in their use of the 

transmission grid, and we believe that such a requirement can be seen as directly 

affecting the rates for jurisdictional transmission service.

 701 Id. P 625.
Docket No. RM10-23-001 -446-

B. Cost Allocation Method for Regional Transmission Facilities

1. Final Rule

593. In Order No. 1000, the Commission required that each public utility transmission 

provider have in place a method, or set of methods, for allocating the costs of new 

transmission facilities selected in the regional transmission plan for purposes of cost 

allocation.702 The Commission stated that if the public utility transmission provider is an 

RTO or ISO, then the cost allocation method or methods must be set forth in the RTO or 

ISO OATT.703 In a non-RTO/ISO transmission planning region, the Commission 

required each public utility transmission provider located within the region to set forth in 

its OATT the same language regarding the cost allocation method or methods used in its 

transmission planning region.704 In either instance, the Commission required that such 

cost allocation method or methods be consistent with the regional cost allocation 

principles adopted in Order No. 1000.705

 702 Id. P 558.

703 Id.

704 Id.

705 Id.
Docket No. RM10-23-001 -447-

594. The Commission did not specify how the costs of an individual regional 

transmission facility should be allocated.706 It noted, however, that while each 

transmission planning region may develop a method or methods for different types of 

transmission projects, each such method or methods should apply to all transmission 

facilities of the type in question and would have to be determined in advance for each 

type of facility.707 Additionally, the Commission acknowledged that cost containment is 

important, but declined to establish a corresponding cost allocation principle, primarily 

because cost containment concerns the level of costs, not how costs should be allocated 

among beneficiaries.708 

595. With respect to cost allocation for a proposed transmission facility located entirely 

within one public utility transmission owner’s service territory, the Commission found 

that a public utility transmission owner may not unilaterally apply the regional cost 

allocation method or methods developed pursuant to Order No. 1000.709 However, the 

Commission also found that a proposed transmission facility located entirely within a 

public utility transmission owner’s service territory could be determined by the public 

 706 Id. P 560.

707 Id.

708 Id. P 704.

709 Id. P 564.
Docket No. RM10-23-001 -448-

utility transmission providers in the region to provide benefits to others in the region and 

thus be selected in the regional transmission plan for purposes of cost allocation; then the 

cost of that transmission facility would be allocated according to that region’s regional 

cost allocation method or methods.710

596. In Order No. 1000, the Commission also declined to make new findings with 

respect to pancaked rates, stating that it was beyond the scope of the proceeding.711 The 

Commission further stated that it was not making any modifications to the Commission’s 

pancaked rate provisions for an RTO under Order No. 2000.712 However, the 

Commission noted that if rate pancaking was an issue in a particular transmission 

planning region, stakeholders could raise their concerns in the consultations leading to 

the compliance proceedings for Order No. 1000 or make a separate filing with the 

Commission under section 205 or 206 of the FPA, as appropriate.713

2. Requests for Rehearing and Clarification

597. North Carolina Agencies argue that the Commission’s planning and cost allocation 

reforms represent major changes that have the potential to preempt state authority over 

 710 Id.

711 Id. P 764.

712 Id.

713 Id.
Docket No. RM10-23-001 -449-

bundled retail rates. They state that to date, the Commission has declined to exercise its 

authority over the transmission component of bundled retail rates and service despite 

pressure to do so and the U.S. Supreme Court’s decision in New York v. FERC.714 North 

Carolina Agencies assert that the Commission must recognize that the applicability of 

any cost allocation methods that result from Order No. 1000 is limited to unbundled 

transmission and cannot impinge on state jurisdiction with respect to bundled retail rates. 

Ad Hoc Coalition of Southeastern Utilities likewise contends that the allocation of the 

cost of regional transmission facilities to entities performing a retail sales function would 

preempt state commissions in setting bundled retail rates because under the Supremacy 

Clause, utilities will be entitled to recover their costs in retail rates. 

598. Northern Tier Transmission Group also states that the Commission should clarify 

that it does not intend to set retail rates. It states that the Commission has not explained 

the relationship between the mandatory cost allocation process and the ability of a project 

proponent to recover the costs of a selected transmission facility.

 714 North Carolina Agencies at 4 (citing 535 U.S. 1 (2002)). North Carolina 

Agencies state that while New York v. FERC includes dicta suggesting that the 

Commission’s authority is an open issue, the Court found that the jurisdictional issue is a 

difficult one. North Carolina Agencies at 5.
Docket No. RM10-23-001 -450-

599. In a related argument, Alabama PSC argues that Order No. 1000 fails to satisfy the 

requirements of the Administrative Procedure Act (APA)715 because it lacks definiteness 

on how cost allocation will translate into recovery. It is concerned that the rule will result 

in stranded costs if a transmission provider cannot recover allocated costs because of the 

absence of an appropriate contractual vehicle and lead to cost shifting to others within the 

region. Alabama PSC also asserts that Commission is being inconsistent when it does 

not address cost recovery but then does not accept participant funding, which Alabama 

PSC describes as a form of cost recovery, as a regional cost allocation method. Southern 

Companies argue that if there is no payment obligation coinciding with a cost 

assignment, industry cannot presume that Order No. 1000’s objective is to create a rate 

structure to induce transmission developers to participate more fully in regional 

transmission planning processes. They state that the Commission should address this 

issue in order to prevent parties from engaging in a futile exercise over the next eighteen 

months.

600. Several other petitioners also take issue with the Commission’s determination to 

not address cost recovery issues in Order No. 1000. Sacramento Municipal Utility 

District argues that the issue with respect to cost recovery mechanisms is not the identity 

of the transmission provider, but whether the party being assessed charges is one of the 

 715 Administrative Procedure Act, 5 U.S.C. 706(2)(A).
Docket No. RM10-23-001 -451-

provider’s customers. It maintains that “it is not a mere concern over form” to expect an 

explanation of the mechanism for recovering a rate when the party being charged is not a 

customer.

601. Edison Electric Institute, NV Energy and Southern Companies argue that the 

Commission does not explain how costs can be allocated under a regional transmission 

plan in a non-RTO/ISO region without a contractual mechanism permitting the charging 

and collection of such costs. Edison Electric Institute acknowledges that a tariff could 

provide a contractual mechanism for the collection of allocated costs, but states that 

Order No. 1000 does not identify any mechanism for requiring the payment of costs in 

the absence of such an applicable tariff or agreement. Edison Electric Institute thus 

asserts that the Commission is not engaging in reasoned decision making when it 

concludes that it “would permit recovery of costs from a beneficiary in the absence of a 

voluntary arrangement.”716 

602. In the alternative, Edison Electric Institute argues that the Commission should 

clarify: (1) whether allocation in a regional plan of costs to a beneficiary in a nonRTO/ISO region without a voluntary arrangement to pay creates an obligation of the 

beneficiary to pay those costs; and (2) if so, the mechanism for collecting such costs, 

 716 Edison Electric Institute at 7-8.
Docket No. RM10-23-001 -452-

including the source of the obligation of the beneficiary to pay. Southern Companies 

make a similar argument.

603. National Rural Electric Coops argue that the distinction between cost allocation 

and cost recovery in Order No. 1000 has no practical significance. NARUC argues that if 

cost allocation is distinct from cost recovery, it is not clear that the Commission’s 

authority to set rates for transmission under the FPA provides the Commission with 

jurisdiction over cost allocation. 

604. Northern Tier Transmission Group requests that the Commission clarify the 

relationship between cost allocation and cost recovery. It states that the ability to recover 

costs appears to be merely a factor that can be considered and acknowledged in the cost 

allocation process. Northern Tier Transmission Group asserts that this issue is material to 

the decision to participate in the construction of a project. Therefore a clarification of the 

intended relationship between cost allocation and cost recovery will better inform the 

methods developed for and the analysis performed by the regional and interregional 

transmission planning processes. 

605. Northern Tier Transmission Group also asserts that the Commission has no 

authority under the FPA to require the imposition of transmission construction costs on 

non-jurisdictional beneficiaries or to impose cost recovery on the United States or any 
Docket No. RM10-23-001 -453-

state including any political subdivision.717 Edison Electric Institute states that paragraph 

629 of Order No. 1000 states that non-jurisdictional transmission providers that do not 

participate in the regional planning process are not responsible for costs allocated in that 

process. It states that it is arbitrary and capricious to treat jurisdictional transmission 

providers and non-public utility transmission providers differently with respect to any 

obligation they may have, in the absence of a voluntary agreement, to pay costs allocated 

to them in a regional planning process.

606. Arizona Cooperative and Southwest Transmission argue that paragraph 629 in 

Order No. 1000 suggests that a non-public utility will be forced to accept the regional 

cost allocation, and may effectively forfeit its right to avoid an unduly discriminatory cost 

assignment if participating in the process means that it loses the ability to exercise its 

right to seek relief from the Commission. Arizona Cooperative and Southwest 

Transmission argue that non-participation is not a desirable answer to this problem, 

especially as an entity that does not participate could still get saddled with costs and 

would also forego the opportunity to have its own contributions to a more robust grid 

included in the regional plan.

 717 Northern Tier Transmission Group at 6 (citing 16 U.S.C. 824(e) and (f); 

Bonneville Power Admin. v. FERC, 422 F.3d 908 (9th Cir. 2005)).
Docket No. RM10-23-001 -454-

607. Alabama PSC argues that if the regional planning process supersedes or replaces 

the output of a state integrated resource plan that relies on participant funding, it will 

infringe on a state’s prerogative to manage the costs borne by its consumers. Alabama 

PSC also states that Order No. 1000 incorrectly asserts that the cost allocation 

requirements conform fully with the position taken by the Alabama PSC. Instead, it 

states that its concern is that a regional process may identify electricity consumers in 

Alabama as receiving benefits from a new transmission project selected in a regional 

transmission plan for purposes of cost allocation, even if the supposed benefits are 

completely at odds with Alabama PSC’s conclusions. Thus, even though Order No. 1000 

states that consumers will not be assigned costs from which they derive no benefit, 

Alabama PSC remains concerned about this and maintains that states should have the 

option of vetoing such a course or opting out of any cost allocation.

608. Florida PSC argues that the cost allocation provisions of Order No. 1000 infringe 

on its jurisdiction. Florida PSC states that Florida utilities are vertically-integrated, and 

no part of the state is a member of an RTO or ISO. It thus retains authority over cost 

allocation. Florida PSC asserts that planning decisions under the new processes will 

affect wholesale rates that will flow to retail customers. Florida PSC thus argues that 

regions may find themselves paying higher retail rates for benefits realized only in a 

neighboring region. Florida PSC argues that the Commission does not have authority to 
Docket No. RM10-23-001 -455-

assign cost recovery to retail rates for benefits not defined as such in the retail customers’ 

region.

609. Transmission Access Policy Study Group argues that Order No. 1000 erred in 

finding that comments on access to regionally cost allocated facilities through regional 

tariffs at non-pancaked rates were beyond the scope of the proceeding.718 It asserts that 

failing to address these issues leaves a void that must be filled before regional cost 

allocations can be implemented in non-RTO regions.719 It believes that a regional tariff, 

with non-pancaked rates covering both existing and new facilities, is the best way to 

address these issues because such tariffs can solve cost allocation implementation issues 

and avoid the creation of new rate pancakes. Transmission Access Policy Study Group 

suggests that if the Commission does not grant rehearing, it should use its authority to 

induce transmission providers to adopt regional rates that eliminate pancaking and foster 

transmission investment. 

610. Alternatively, Transmission Access Policy Study Group states that the 

Commission should require a process to address access issues at the compliance stage. It 

also argues that access should be addressed when a specific cost allocation is applied to a 

 718 Transmission Access Policy Study Group at 40 (citing Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 at PP 549, 764).

719 Transmission Access Policy Study Group asserts that Order No. 1000’s focus 

on cost allocation as disassociated from service relationships heighten these concerns.
Docket No. RM10-23-001 -456-

project. Transmission Access Policy Study Group states that in non-RTO regions, the 

Commission should require that access issues be addressed in the regional process for 

selection of an upgrade and the application of the regional cost allocation to a facility, as 

well as require filing of the specific cost allocation as applied to the particular project 

selected for regional cost allocation, with a description of how access will be provided 

and on what rates, terms, and conditions. Transmission Access Policy Study Group 

believes that specific applications of the regional cost allocation should be filed as soon 

as the constructor of the facility is identified, with access issues addressed at that time 

rather than when the facility is completed.720 According to Transmission Access Policy 

Study Group, this will help address uncertainty caused by the absence of regional tariffs 

and Order No. 1000’s preference for flexibility. Finally, Transmission Access Policy 

Study Group urges prompt public disclosure of the mechanism to provide access to 

regionally cost allocated–facilities, and it states that it is essential to address access issues 

before a proposed facility proceeds through the permitting and siting process.

611. Several petitioners question the Commission’s decision not to address cost 

containment issues in Order No. 1000. For example, Illinois Commerce Commission 

argues that the Commission does not provide a good reason for not addressing cost 

 720 Transmission Access Policy Study Group notes that Order No. 1000 does not 

address timing of the filing of specific applications of the regional cost allocation. 
Docket No. RM10-23-001 -457-

containment, and that it must be addressed to prevent excessive costs, which is a 

fundamental part of any appropriate cost allocation method. Illinois Commerce 

Commission asserts that even if Order No. 1000 is not the appropriate forum, the 

Commission erred in failing to identify an alternative forum.

612. Wisconsin PSC requests that there be a mandate to consider cost overrun 

containment mechanisms. It argues that uncontained costs are as likely to undermine 

needed transmission development as a flawed cost allocation method or no method at all 

would. Wisconsin PSC states that Order No. 1000’s distinction between the allocation of 

costs and the amount of costs is a hollow one because the key question for states and the 

customers who pay for the lines is the cost/benefit of the buildout.721 It also argues that 

since the Commission saw fit to develop a fallback mechanism for situations where a 

project developer abandons a line that a transmission provider had depended upon for 

reliability and supply purposes; it should also have a fallback mechanism for cost 

overruns, which pose a much greater prospect of harm to the consuming public. 

3. Commission Determination

613. We affirm Order No. 1000’s requirement that each public utility transmission 

provider have in place a method, or set of methods, for allocating the costs of new 

 721 Wisconsin PSC at 10-11 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323

at PP 704-05 (2007)).
Docket No. RM10-23-001 -458-

transmission facilities selected in the regional transmission plan for purposes of cost 

allocation.722 In Order No. 1000, the Commission did not specify how the costs of an 

individual regional transmission facility should be allocated.723 It noted, however, that 

while each transmission planning region may develop a method or methods for different 

types of transmission projects, each such method or methods should apply to all 

transmission facilities of the type in question and would have to be determined in 

advance for each type of facility.724 We continue to believe that such an approach is 

necessary to ensure that the rates, terms, and conditions of jurisdictional service are just 

and reasonable and not unduly discriminatory or preferential. This is because in the 

absence of clear cost allocation rules, there is a greater potential that pubic utility 

transmission providers and nonincumbent transmission developers may be unable to 

develop transmission facilities that are determined by the region to meet their needs.725 

614. In response to Alabama PSC’s argument that a state should be permitted to veto 

any particular cost allocation if it disagrees with the outcome, we reiterate Order No. 

1000’s finding declining to mandate veto rights for state committees. However, as stated 

 722 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 558.

723 Id. P 560.

724 Id.

725 Id. P 559.
Docket No. RM10-23-001 -459-

in Order No. 1000, the Commission does not preclude public utility transmission 

providers from proposing such mechanisms on compliance if they choose to do so.726 

We emphasize that any such mechanisms must be consistent with the goals of Order No. 

1000’s transmission planning and cost allocation reforms, an important part of which are 

to provide that costs are allocated to beneficiaries roughly commensurate with the 

benefits that they receive. 

615. In response to Alabama PSC’s concern that the Commission’s cost allocation 

reforms could lead to stranded transmission costs due to the absence of a necessary 

contractual vehicle, we note that entities that receive benefits are subject to a 

Commission-approved transmission tariff. The existence of obligation arising under such 

a tariff is sufficient to ensure that there will be no stranded costs, and the question of 

specific recovery mechanisms is beyond the scope of this proceeding. This point applies 

equally to Southern Companies’ concern about payment obligations that correspond to 

cost assignments. 

616. Additionally, we find no merit in the arguments advanced to challenge our 

position in Order No. 1000 that cost allocation and cost recovery are distinct issues and 

our determination not to address matters of cost recovery there.727 We therefore affirm 

 726 Id. P 502.

727 Id. P 563.
Docket No. RM10-23-001 -460-

the Commission’s decision in Order No. 1000 that cost recovery is a separate issue, and 

we will not specify how costs can be recovered for transmission projects that are selected 

in the regional transmission plan for purposes of cost allocation. The U.S. Supreme 

Court has found that the Commission has broad discretion in determining which issues to 

address in a particular proceeding.728 While we will not address cost recovery in this 

proceeding, we note that cost recovery may be considered as part of a region’s 

stakeholder process in developing a cost allocation method or methods to comply with 

Order No. 1000. Therefore, to the extent that cost recovery provisions are considered in 

connection with a cost allocation method or methods for a regional or interregional 

transmission facility, public utility transmission providers may include cost recovery 

provisions in their compliance filings. 

617. We thus reject Sacramento Municipal Utility District’s contention that Order No. 

1000 is deficient because it does not explain the mechanism for recovering a cost “when 

the party being charged is not a customer.”729 Sacramento Municipal Utility District’s 

claim of deficiency is premised on the proposition that costs cannot be allocated in a 

situation where an entity does not have a preexisting contractual relationship with the 

 728 Mobil Oil Exploration & Producing Southeast, Inc. v. United Distribution 

Companies, 498 U.S. 211, 230 (1991). See also Tennessee Valley Municipal Gas 

Association v. FERC, 140 F.3d. 1085, 1088 (D.C. Cir. 1998).

729 Sacramento Municipal Utility District at 11.
Docket No. RM10-23-001 -461-

entity that will recover the costs. It considers a cost allocation in this situation to be a 

cost allocation to a non-customer. We have addressed this issue at length above. 

Because we disagree with Sacramento Municipal Utility District’s premise, we disagree 

that our decision not to address cost recovery in Order No. 1000 makes the order 

deficient. This conclusion applies equally to Sacramento Municipal Utility District’s 

assertion that it is not a mere concern over form to expect an explanation of the 

mechanism for recovering a charge when the party being charged is not a customer. 

618. Edison Electric Institute seeks clarification on how costs can be recovered from a 

beneficiary in the absence of an applicable tariff or agreement. Edison Electric Institute’s 

request is based on its reading of paragraph 506 of Order No. 1000, which it notes states 

that the Commission “would permit recovery of costs from a beneficiary in the absence 

of a voluntary arrangement.” However, this statement is simply part of a summary of the 

Commission’s ruling in AEP. This summary does not imply that Order No. 1000 

contemplates the recovery of costs from a beneficiary in the absence of an applicable 

tariff or agreement. All tariffs will be required to contain an appropriate cost allocation 

method or methods. 

619. In response to Alabama PSC, the Commission was not being inconsistent on the 

issue of cost recovery when it found that participant funding, which it describes as a form 

of cost recovery, cannot be a regional cost allocation method. This argument assumes 

that cost allocation and cost recovery are not distinct issues. The Commission’s position 
Docket No. RM10-23-001 -462-

is that they are distinct – a point that Alabama PSC does not challenge – and thus when it 

concluded that participant funding cannot serve as a regional cost allocation method, the 

Commission was not making a conclusion regarding cost recovery mechanisms. As a 

result, the Commission was not taking an action that was inconsistent with its position 

that it would not address cost recovery in Order No. 1000. We address the prohibition 

against participant funding as a regional cost allocation method elsewhere in this order. 

Similarly, we disagree with Northern Tier Transmission Group that the Commission is 

impermissibly imposing recovery of transmission construction costs on non-jurisdictional 

entities, as Order No. 1000 did not address matters of cost recovery.

620. Moreover, we disagree with petitioners’ arguments that Order No. 1000’s cost 

allocation provisions infringe on state authority over the siting and permitting of 

transmission facilities, or that they infringe on integrated resource planning. Petitioners

have not demonstrated anything persuasive to support their comments. More generally, 

as we discuss in the cost allocation legal authority section above, we have ample 

authority under the FPA to require public utility transmission providers to file regional 

and interregional cost allocation methods, and we direct petitioners to that section for a 

fuller discussion of the Commission’s legal authority.

621. We disagree with those petitioners who claim the Commission is seeking to 

regulate bundled retail rates. North Carolina Agencies provide no clear explanation for 

their position. Indeed, they state only that there is a potential for the Commission to 
Docket No. RM10-23-001 -463-

regulate bundled retail rates. As for Ad Hoc Coalition of Southeastern Utilities’ 

arguments, we disagree that requiring the implementation of a method to allocate the 

costs of new transmission facilities selected in a regional transmission plan for purposes 

of cost allocation amounts to regulation of bundled retail rates.730 As discussed in Order 

No. 1000 and in this order, we have ample legal authority to adopt the Order No. 1000 

cost allocation reforms.731 We also affirm Order No. 1000’s discussion of this issue, 

namely, that:

[I]t is not clear why cost allocations consistent with this Final Rule would 

affect state jurisdiction differently from existing cost allocations. In any 

event, we find that such arguments are premature. It is inappropriate for the 

Commission to decide such issues generically in a rulemaking, as such 

issues should be decided based on specific facts and circumstances, none of 

which are presented here.732

Accordingly, we reiterate here that in this generic rulemaking proceeding, these issues are 

not presented for Commission determination.

622. To the extent a non-public utility transmission provider exercises its discretion to 

enroll as a transmission provider in a regional transmission planning process, it may be 

allocated costs roughly commensurate with the benefits that it is determined to receive 

 730 Ad Hoc Coalition of Southeastern Utilities at 74.

731 See, e.g., Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 530-49; see also

discussion supra at section II.C and discussion supra at section IV.A.3.

732 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 548.
Docket No. RM10-23-001 -464-

from new transmission facilities selected in the regional transmission plan for purposes of 

cost allocation.733 We disagree with Arizona Cooperative and Southwest Transmission 

that a non-public utility transmission provider will effectively forfeit its rights to avoid 

undue discrimination by participating in the regional transmission planning process for 

several reasons. First, the choice of whether to enroll in the regional transmission 

planning process, and thus be subject to being determined to be a beneficiary for which 

cost allocation is appropriate, remains with each non-public utility transmission provider. 

Second, it will have a voice in the process of determining the cost allocation method, and 

if it believes that the result is unduly discriminatory, it maintains the right to intervene in 

the compliance proceeding when that method is filed at the Commission. Third, for 

future applications of the method to actual new facilities, a non-public utility 

transmission provider could exercise any right it has in the regional transmission planning 

process to withdraw rather than accept the allocation of costs.734 And finally, non-public 

utility transmission providers choosing to remain in the transmission planning region 

 733 See discussion supra at PP 274- 279.

734 To accommodate the participation of non-public utility transmission providers, 

the relevant tariffs or agreements governing the regional transmission planning process 

could establish the terms and conditions of orderly withdrawal for non-public utility 

transmission providers that are unable to accept the allocation of costs pursuant to a 

regional or interregional cost allocation method. See Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 820.
Docket No. RM10-23-001 -465-

notwithstanding dissatisfaction with a particular application of the cost allocation method 

may file with the Commission for a FPA 206 determination that the approved method is 

no longer just and reasonable or is unduly discriminatory or preferential in practice.

623. We affirm the Commission’s finding in Order No. 1000 that this is not the proper 

proceeding to address rate pancaking issues. If rate pancaking is an issue in a particular 

transmission planning region, stakeholders may raise their concerns in the consultations 

leading to the compliance proceedings for Order No. 1000 or make a separate filing with 

the Commission under section 205 or 206 of the FPA, as appropriate.735 The 

Commission has the discretion to determine which issues to address in a particular 

proceeding.736

624. With regard to concerns related to access to new transmission facilities for which 

an entity has been allocated costs pursuant to a regional or interregional cost allocation 

method, the Commission believes that the appropriate forum to consider such issues in 

the first instance is in the regional transmission planning process for each transmission 

planning region. Each regional transmission planning process must provide entities who 

will receive regional or interregional cost allocation an understanding of the identified 

 735 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 764.

736 Mobil Oil Exploration & Producing Southeast, Inc. v. United Distribution 

Companies, 498 U.S. 211, 230 (1991). See also Tennessee Valley Municipal Gas 

Association v. FERC, 140 F.3d. 1085, 1088 (D.C. Cir. 1998).
Docket No. RM10-23-001 -466-

benefits on which the cost allocation is based. The Commission anticipates that regions 

may approach these issues in different ways and thus will allow public utility 

transmission providers, in consultation with stakeholders, to address these issues as they 

develop the regional and interregional cost allocation methods for their transmission 

planning region. We note that entities may utilize the existing OATT provisions 

regarding Order No. 890 dispute resolution, which will also apply to the new 

transmission planning and cost allocation processes adopted under Order No. 1000, if 

they disagree with the public utility transmission provider’s identification of benefits and 

beneficiaries for a regional or interregional transmission facility selected in the regional 

transmission plan for purposes of cost allocation.

625. We affirm the Commission’s decision in Order No. 1000 that cost containment 

issues relate to the level of costs and not how costs should be allocated among 

beneficiaries.737 As the Commission emphasized in Order No. 1000, this proceeding 

relates to transmission planning reforms, including the role of cost allocation in 

transmission planning, not the level of transmission costs,738 and therefore this 

proceeding is not the appropriate forum for addressing the transmission cost containment 

issues raised by petitioners. However, as with cost recovery, we note that cost 

 737 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 704.

738 Id.
Docket No. RM10-23-001 -467-

containment may be considered as part of a region’s stakeholder process in developing a 

cost allocation method or methods to comply with Order No. 1000. Therefore, to the 

extent that cost containment provisions are considered in connection with a cost 

allocation method or methods for a regional or interregional transmission facility, public 

utility transmission providers may include transmission cost containment provisions in 

their compliance filings.

C. Cost Allocation Method for Interregional Transmission Facilities

1. Final Rule

626. In Order No. 1000, the Commission required each public utility transmission 

provider in a transmission planning region to have, together with the public utility 

transmission providers in its own transmission planning region and a neighboring 

transmission planning region, a common method or methods for allocating the costs of a 

new interregional transmission facility among the beneficiaries of that transmission 

facility in the two neighboring transmission planning regions in which the transmission 

facility is located. The Commission explained that the cost allocation method or methods 

used by the pair of neighboring transmission regions can differ from the cost allocation 

method or methods used by each region to allocate the cost of a new interregional 

transmission facility within that region.739 The Commission stated that in an RTO or ISO 

 739 Id. P 578.
Docket No. RM10-23-001 -468-

region, the method must be filed in the OATT.740 Additionally, the Commission stated 

that in a non-RTO/ISO transmission planning region, the same common cost allocation 

method or methods must be filed in the OATT of each public utility transmission 

provider in the transmission planning region.741 In either instance, the Commission 

stated that such cost allocation method or methods must be consistent with the 

interregional cost allocation principles adopted in Order No. 1000.742

627. The Commission also clarified that it would not require each transmission 

planning region to have the same interregional cost allocation method or methods with 

each of its neighbors.743 Order No. 1000 provided that each pair of transmission planning 

regions may develop its own approach to interregional cost allocation that satisfies both 

transmission planning regions’ needs and concerns, as long as that approach satisfies the 

interregional cost allocation principles.744 

 740 Id.

741 Id.

742 Id.

743 Id. P 580.

744 Id.
Docket No. RM10-23-001 -469-

628. The Commission did not specify how the costs for an individual interregional 

transmission facility should be allocated.745 However, the Commission stated that while 

transmission planning regions can develop a different cost allocation method or methods 

for different types of transmission projects, such a cost allocation method or methods 

should apply to all transmission facilities of the type in question and each cost allocation 

method would have to be determined in advance for each type of transmission facility.746 

Also, the Commission adopted the requirement that an interregional transmission facility 

must be selected in a relevant regional transmission plan for purposes of cost allocation to 

be eligible for interregional cost allocation pursuant to the interregional cost allocation 

method or methods.747

629. The Commission also noted that as it made clear in its discussion of Cost 

Allocation Principle 4,748 costs may be assigned only on a voluntary basis to a 

transmission planning region in which an interregional transmission facility is not 

located.749 The Commission noted that, given this option, regions are free to negotiate 

 745 Id. P 581.

746 Id.

747 Id.

748 See Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at section IV.E.5.

749 Id. P 582.
Docket No. RM10-23-001 -470-

interregional transmission arrangements that allow for the allocation of costs to 

beneficiaries that are not located in the same transmission planning region as any given 

interregional transmission facility.750

630. In addition, the Commission clarified that the requirement to coordinate with 

neighboring regions applies to public utility transmission providers within a region as a 

group, not to each individual public utility transmission provider acting on its own. For 

example, within an RTO or ISO, the RTO or ISO would develop an interregional cost 

allocation method or methods with its neighboring regions on behalf of its public utility 

transmission owning members.751 

2. Requests for Rehearing or Clarification

631. Several petitioners seek clarification of the Commission’s interregional cost 

allocation requirements. California ISO seeks clarification that one planning region 

cannot allocate costs to a neighboring transmission planning region for a transmission 

line that interconnects to the system of the neighboring region but that the neighboring 

region has not determined is needed and has not included in its transmission plan. 

632. MISO Transmission Owners Group 1 requests clarification that Order No. 1000’s 

statement that a transmission owner in an RTO or ISO can comply with the proposed 

 750 Id.

751 Id. P 584.
Docket No. RM10-23-001 -471-

interregional cost allocation mandates through participation in the RTO and ISO is not 

intended to alter a transmission owner’s section 205 rights or the division of section 205 

filing rights between an RTO and its transmission owners. It states that if the 

Commission does not provide this clarification, the Commission must grant rehearing 

because limiting the section 205 filing rights of transmission owners would be contrary to 

judicial precedent.752 

633. Transmission Dependent Utility Systems request clarification that transmission 

customer load-serving entities should be able to review and comment on the development 

of interregional cost allocation methods and have their input considered and addressed 

before public utility transmission providers make their compliance filings. Transmission 

Dependent Utility Systems assert this is necessary to ensure consistency with the nondiscrimination requirements of FPA section 205.

3. Commission Determination

634. As stated in Order No, 1000, the Commission requires that each public utility 

transmission provider in a transmission planning region must have, together with the 

public utility transmission providers in its own transmission planning region and a 

neighboring transmission planning region, a common method or methods for allocating 

 752 MISO Transmission Owners Group 1 at 13-14 (citing Atlantic City Electric Co. 

v. FERC, 295 F.3d 1 (D.C. Cir. 2002)).
Docket No. RM10-23-001 -472-

the costs of a new interregional transmission facility among the beneficiaries of that 

transmission facility in the two neighboring transmission planning regions in which the 

transmission facility is located.753 We continue to believe that the absence of clear cost 

allocation rules for interregional transmission facilities can impede the development of 

such transmission facilities due to the uncertainty regarding the allocation of 

responsibility for associated costs, potentially adversely affecting rates for jurisdictional 

services causing them to become unjust and unreasonable or unduly discriminatory or 

preferential.754 

635. In response to California ISO’s request that we clarify that another region could 

not impose costs on it for an interregional transmission facility without approval, Order 

No. 1000 states that, for an interregional transmission facility to receive interregional cost 

allocation, each of the neighboring transmission planning regions in which the 

interregional transmission facility is proposed to be located must select the facility in its 

regional transmission plan for purposes of cost allocation.755 As such, we believe that it 

is clear that, if one of the regional transmission planning processes does not select the 

interregional transmission facility to receive interregional cost allocation, neither the 

 753 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 579.

754 Id.

755 Id. P 436.
Docket No. RM10-23-001 -473-

transmission developer nor the other transmission planning region may allocate the costs 

of that interregional transmission facility under the provisions of Order No. 1000 to the 

region that did not select the interregional transmission facility.

636. In response to MISO Transmission Owners Group 1, we clarify that the Order No. 

1000 interregional cost allocation requirements are not intended to alter the section 205 

rights of transmission owners and RTOs.

637. In response to Transmission Dependent Utility Systems, we clarify that all 

interested parties, including transmission customer load-serving entities, must have the 

opportunity to participate in the process of developing the interregional cost allocation 

method or methods. As the Commission stated in Order No. 1000, in developing 

appropriate cost allocation methods for their regional and interregional transmission 

facilities, public utility transmission providers must consult with stakeholders.756 The 

Commission also stated that stakeholder input in the development of a cost allocation 

method or methods should ensure that the method or methods ultimately agreed upon is 

balanced and does not favor any particular entity.757 Consistent with Order No. 890, the 

Commission defined “stakeholder” in Order No. 1000 as including any party interested in 

 756 Id. P 482.

757 Id. P 671.
Docket No. RM10-23-001 -474-

the regional transmission planning process.758 As such, we view stakeholder 

participation, including that by load-serving entities, as an important aspect of the 

development of compliance filings to meet the requirements of Order No. 1000. 

D. Principles for Regional and Interregional Cost Allocation

1. Use of a Principles-Based Approach

638. In Order No. 1000, the Commission required each public utility transmission 

provider to show on compliance that its cost allocation method or methods for regional 

cost allocation and its method or methods for interregional cost allocation are just and 

reasonable and not unduly discriminatory or preferential by demonstrating that each 

method satisfies the six cost allocation principles.759 The Commission took a principlesbased approach because it recognized that regional differences may warrant distinctions 

in cost allocation methods among transmission planning regions. The Commission 

explained that the six regional cost allocation principles apply to, and only to, a cost 

allocation method or methods for new regional transmission facilities selected in a 

regional transmission plan for purposes of cost allocation.760 Likewise, the Commission 

stated that the six analogous interregional cost allocation principles apply to, and only to, 

 758 Id. P 143.

759 Id. P 603.

760 Id.
Docket No. RM10-23-001 -475-

a cost allocation method or methods for a new transmission facility that is located in two 

neighboring transmission planning regions and accounted for in the interregional 

transmission coordination procedure in an OATT.761 Additionally, the Commission 

stated that the cost allocation principles do not apply to other new transmission facilities 

and therefore did not foreclose the opportunity for a developer or individual customer to 

voluntarily assume the costs of a new transmission facility.762

639. The Commission declined to adopt a default regional or interregional cost 

allocation method, but stated that in the event of a failure to reach an agreement on a cost 

allocation method or methods, it would use the record in the relevant compliance filing 

proceeding as a basis to develop a cost allocation method or methods that meets its 

proposed requirements.763 

a. Arguments That Principles-Based Cost Allocation 

Methods Are Unfair and Arguments Related to 

Commission Determination of Cost Allocation Method 

Pursuant to the Compliance Process

640. Illinois Commerce Commission argues that Order No. 1000 appears to require 

transmission providers to be responsible for estimating project benefits, which effectively 

delegates the Commission’s authority over rates and to define what constitutes benefits. 

 761 Id.

762 Id.

763 Id. PP 607, 610.
Docket No. RM10-23-001 -476-

It maintains that delegating this authority to the transmission provider and the stakeholder 

process does not ensure that planning criteria and cost allocation methods based on 

benefits will be just and reasonable. 

641. Illinois Commerce Commission asserts that the stakeholder process may neglect 

the interests of some load-serving entities that will bear the costs of transmission 

investment when the interests of those load-serving entities are not aligned or directly 

conflicts with the majority of load-serving entities and other stakeholders within the 

region. It cites Illinois Commerce Commission as an example of an outcome where the 

majority of stakeholders agreed to spread costs in eastern PJM to utilities in western PJM, 

and the Commission deferred to this “regional consensus” while acknowledging there 

was none. Illinois Commerce Commission states that the Seventh Circuit disagreed and 

found that one group of utilities’ desire to be subsidized by another is no reason in itself 

for giving them their way. 

642. Illinois Commerce Commission further argues that delegating the Commission’s 

obligation to ensure just and reasonable rates to a stakeholder process violates section 

205 due process rights of interested parties because it imposes an undue burden on parties 

to participate in a new and costly process without providing the funding to participate. It 

contends that the process will lack a public administrative record, making it difficult for 

interested parties who would have otherwise intervened in a normal administrative 
Docket No. RM10-23-001 -477-

process to follow the proceeding. Illinois Commerce Commission states that the right of 

parties to bring a section 206 complaint is an inadequate remedy in light of these issues.

643. Several petitioners seek rehearing of the Commission’s statement that if an 

agreement on a cost allocation method is not reached, it will use the record to develop a 

method or methods for the region, arguing that the Commission does not have the 

authority to do so.764 Florida PSC argues that this provision encroaches on Florida’s 

jurisdiction because the Commission does not have authority to assign cost recovery to 

retail customers.765 Kentucky PSC also argues that the due process requirements of the 

state integrated resource planning and certificate of public convenience and necessity 

processes is being replaced by majoritarian processes backed by the threat that the 

Commission will determine cost allocation processes if the regional group cannot. 

644. Illinois Commerce Commission argues that Order No. 1000 implies that if there is 

consensus, the Commission will accept that compliance filing. Illinois Commerce 

Commission seeks rehearing of the meaning of “consensus” if it means here something 

different from “agreement.”766 It argues that the term is insufficient to protect those who 

may be harmed by a majority. Additionally, Illinois Commerce Commission argues that 

 764 See, e.g., Georgia PSC; Illinois Commerce Commission; and Florida PSC.

765 Florida PSC at 7 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 

607).

766 Illinois Commerce Commission at 35.
Docket No. RM10-23-001 -478-

requiring a consensus means that minority interests will always lose, which is unduly 

discriminatory on its face, and forcing minority interests to bring a section 206 complaint 

is insufficient to protect their interests and overly burdensome. 

645. New York Transmission Owners seek clarification that the Commission will 

impose a cost allocation method on transmission planning regions only as a last resort 

after consensus has been encouraged through mediation and other alternative dispute 

resolution procedures.

646. Transmission Dependent Utility Systems seek clarification, or in the alternative

rehearing, that compliance filings must document the opportunities for customer input in 

the development of regional and interregional cost allocation methods as well as the basis 

relied upon for disregarding any such input. They argue that this information is 

necessary to gauge the inclusiveness and transparency of the processes for developing 

cost allocation methods.

i. Commission Determination

647. We affirm the Commission’s decision that the appropriate approach is for public 

utility transmission providers to develop regional and interregional cost allocation 

methods based on the six cost allocation principles described in Order No. 1000, thereby 

allowing public utility transmission providers the flexibility to develop cost allocation 

methods that best suit regional needs. The Commission disagrees that Order No. 1000 is 

delegating the Commission’s authority over rates to define what constitutes benefits. 
Docket No. RM10-23-001 -479-

The proper context for further consideration of “benefits” and “beneficiaries” is in the 

Commission’s review of compliance proposals and a record before the Commission.767 

As the Commission explained in Order No. 1000, the cost allocation principles do not 

prescribe a uniform approach, but provide the public utility transmission providers in 

consultation with the stakeholders in each region the opportunity to first develop their 

own method or methods, and recognized that regional differences may warrant 

distinctions in cost allocation methods.768 It would be inconsistent with the regional 

flexibility provided in Order No. 1000 for the Commission to prescribe a uniform 

approach to determining benefits or beneficiaries when a multitude of factors vary across 

transmission planning regions and the entire country.

648. In response to concerns that a stakeholder process is an inappropriate way to 

allocate costs, we note that the Commission has previously found, and the D.C. Circuit 

has affirmed, that a stakeholder process is appropriate when unresolved issues may be 

better addressed in a forum featuring broad stakeholder input, and where a transmission 

solution can be better tailored to meet regional transmission needs through broad input 

from interested participants that may not otherwise participate in a Commission 

 767 Id. P 624.

768 Id.
Docket No. RM10-23-001 -480-

proceeding.769 The public utility transmission providers and stakeholders that make up 

the region are intimately familiar with the transmission needs of their region. Therefore, 

they are in the best position to develop, and submit to the Commission for review, a cost 

allocation method or methods that complies with the six cost allocation principles and 

best meets the transmission planning region’s needs. This does not amount to a 

delegation of Commission authority because the Commission ultimately will determine 

whether the method or methods are just and reasonable and interested parties will 

continue to have an opportunity to support or oppose the cost allocation methods 

proposed in the compliance filings at the Commission.770 

649. It also does not interfere with section 205 rights or otherwise impose an undue 

burden on parties to participate in new and costly processes. The transmission planning 

and cost allocation processes in Order No. 1000 are not entirely new, but rather build on 

the reforms to the processes already required by Order No. 890, in which all interested 

parties should already be participating. In any event, with regard to state regulators, such 

as Illinois Commerce Commission, we have already explained above that, consistent with 

 769 Braintree Elec. Light Dept. v. ISO New England, Inc., 128 FERC ¶ 61,008 

(2009) (citing MISO, 125 FERC ¶ 61,038, at P 19 (2008); Pepco Energy Servs. v. PJM 

Interconnection, L.L.C., 124 FERC ¶ 61,008, at P 24 (2008); PSC of Wis. v. FERC, 545 

F.3d 1058, 1063 (D.C. Cir. 2008)).

770 PSC of Wis. v. FERC, 545 F.3d at 1064.
Docket No. RM10-23-001 -481-

Order Nos. 1000 and 890, they may request that the public utility transmission providers 

in their region propose a mechanism in their compliance filings providing for state 

regulators to recoup the costs of their participation in the regional transmission planning 

process.

771 In addition, interested parties retained their section 206 rights to file a 

complaint if they have concerns about the process or the method or methods proposed. 

Illinois Commerce Commission has not provided a reason that section 206 would not be 

an appropriate remedy and not identified specific facts to illustrate a scenario where it 

would not be able to obtain an adequate remedy under section 206.

650. We also affirm the Commission’s decision in Order No. 1000 that, in the event of 

a failure to reach an agreement on a cost allocation method or methods, the Commission 

will use the record in the relevant compliance filing proceeding as a basis to develop a 

cost allocation method or methods that meets Order No. 1000’s cost allocation 

principles.772 This provision does not infringe upon state jurisdiction, as suggested by the 

Florida and Kentucky PSCs, because, as discussed above, states retain whatever 

jurisdiction they have over retail rates.

 771 See discussion supra at section III.A. (citing Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 162 and quoting Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 

574 n.339 and P 586)).

772 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 607.
Docket No. RM10-23-001 -482-

651. In response to Illinois Commerce Commission’s argument regarding whether a 

“consensus” of stakeholders is synonymous with “agreement,” and if so, that such an 

approach would allow the majority to override minority interests when making 

compliance filings, we reiterate our finding in Order No. 1000 that “the Commission will 

consider in response to compliance filings all issues raised by commenters, such as what 

constitutes an impasse, [and] whether there should be deference to the majority....”773 

Accordingly, we decline to speculate in advance of these compliance filings the extent to 

which the Commission would give weight to the majority of public utility transmission 

providers and stakeholders in a region. 

652. In response to New York Transmission Owners, we reiterate that the Commission 

will use the record in the relevant compliance filings as a basis to develop a cost 

allocation method or methods for a transmission planning region when the transmission 

planning region fails to reach an agreement. To this end, we note that in response to a 

directive to do so in Order No. 1000,774 the Commission’s staff has been made available 

to assist public utility transmission providers and stakeholders in the various regions 

around the country in reaching an agreement on a compliance filing. The Commission 

also noted in Order No. 1000 that the procedural mechanisms used by it in response to 

 773 Id. P 609.

774 Id. P 14.
Docket No. RM10-23-001 -483-

compliance filings will depend on the nature of remaining disputes and what issues are 

still at stake that are preventing the public utility transmission providers in each 

transmission planning region or pair of transmission planning regions from reaching a 

consensus.775 Accordingly, in advance of such compliance filings, we decline to 

specifically endorse any particular procedural method for resolving cost allocation 

disputes brought forward in compliance filings; mediation or other alternative dispute 

resolution procedures, as suggested by New York Transmission Owners are certainly 

viable methods to encourage consensus and will be considered if necessary at the 

appropriate time. 

653. In response to Transmission Dependent Utility Systems’ request that compliance 

filings must document the opportunities for customer input provided, as well as the basis 

relied upon for disregarding any such customer input, we do not believe any clarification 

of Order No. 1000 is necessary. Order No. 1000 already provides that “[p]ublic utility 

transmission providers must document in their compliance filings the steps they have 

taken to reach consensus on a cost allocation method or set of methods to comply with 

this Final Rule, as thoroughly as practicable, and provide whatever information they view 

 775 Id. P 609.
Docket No. RM10-23-001 -484-

as necessary for the Commission to make a determination of the appropriate cost 

allocation method or methods.”776

2. Cost Allocation Principle 1—costs allocated in a way that is 

roughly commensurate with benefits

654. In Order No. 1000, the Commission adopted the following Cost Allocation 

Principle 1 for both regional and interregional cost allocation:

Regional Cost Allocation Principle 1: The cost of transmission 

facilities must be allocated to those within the transmission planning 

region that benefit from those facilities in a manner that is at least 

roughly commensurate with estimated benefits. In determining the 

beneficiaries of transmission facilities, a regional transmission 

planning process may consider benefits including, but not limited to, 

the extent to which transmission facilities, individually or in the 

aggregate, provide for maintaining reliability and sharing reserves, 

production cost savings and congestion relief, and/or meeting Public 

Policy Requirements.

and

Interregional Cost Allocation Principle 1: The costs of a new 

 776 Id. P 607. 
Docket No. RM10-23-001 -485-

interregional transmission facility must be allocated to each 

transmission planning region in which that transmission facility is 

located in a manner that is at least roughly commensurate with the 

estimated benefits of that transmission facility in each of the 

transmission planning regions. In determining the beneficiaries of 

interregional transmission facilities, transmission planning regions 

may consider benefits including, but not limited to, those associated 

with maintaining reliability and sharing reserves, production cost 

savings and congestion relief, and meeting Public Policy 

Requirements.777

655. However, the Commission stated that it was not prescribing a particular definition 

of “benefits” or “beneficiaries” in Order No. 1000.778 In the Commission’s view, the 

proper context for consideration of these matters is in the regional stakeholder meetings 

in the first instance, followed by Commission consideration of these matters on review of 

compliance proposals and the record before the Commission.779 

 777 Id. P 622.

778 Id. P 624.

779 Id.
Docket No. RM10-23-001 -486-

656. The Commission also stated that if a non-public utility transmission provider 

makes the choice to become part of the transmission planning region and it is determined 

by the transmission planning process to be a beneficiary of certain transmission facilities 

selected in the regional transmission plan for purposes of cost allocation, that non-public 

utility transmission provider is responsible for the costs associated with such benefits.780

657. Additionally, in Order No. 1000, the Commission found that issues related to the 

generator interconnection process and to interconnection cost recovery were outside the 

scope of the rulemaking proceeding.781 The Commission stated that Order No. 2003782

sets forth the procedures for the interconnection of a large generating transmission 

facility to the bulk power system.783 Additionally, the Commission emphasized that 

Order No. 1000 did not set forth any new requirements with respect to such procedures 

for interconnecting large, small, or wind or other generation facilities.784 Therefore, the 

 780 Id. P 629.

781 Id. P 760.

782 Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ¶ 31,146, order on reh’g, 

Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order 

No. 2003-B, 70 FR 265, FERC Stats. & Regs. ¶ 31,171, order on reh’g, Order No. 2003-

C, 70 FR 37661, FERC Stats. & Regs. ¶ 31,190 , aff'd sub nom. Nat’l Ass’n of Regulatory 

Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 

(2008).

783 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 760.

784 Id.
Docket No. RM10-23-001 -487-

Commission determined that Order No. 1000 was not the proper proceeding for 

commenters to raise issues about the interconnection agreements and procedures under 

Order Nos. 2003, 2006785 or 661.786

a. Requests for Rehearing or Clarification

658. Several petitioners seek rehearing or clarification regarding the lack of a definition 

of “benefits” in Order No. 1000. Illinois Commerce Commission argues that by failing to 

establish definitions and standards for transmission providers to implement in identifying 

project benefits, the Commission has placed transmission providers in conflict with 

majority desires in the stakeholder process because an RTO is obligated to act in the 

interests of its transmission owning members. It argues that RTO behavior has been 

more accommodating to transmission owning utilities than captive ratepayers, and this 

issue will be exacerbated with less Commission oversight. 

659. Arizona Cooperative and Southwest Transmission also argue that there is 

insufficient Commission oversight of the definition and measurement of benefits. It 

argues that “benefits” can, within the context of a network, become so pliable as to 

become meaningless, especially as applied to individual situations. Arizona Cooperative 

 785 Order No. 2006, 70 FR 34189, FERC Stats. & Regs. ¶ 31,180, order on reh’g, 

Order No. 2006-A, 70 FR 71760, FERC Stats. & Regs. ¶ 31,196, order granting 

clarification, Order No. 2006-B, 71 FR 42587, FERC Stats. & Regs. ¶ 31,221.

786 Order No. 661, 70 FR 34993 (Jun. 16, 2005), FERC Stats. & Regs. ¶ 31,186, 

order on reh’g, Order No. 661-A, FERC Stats. & Regs. ¶ 31,198.
Docket No. RM10-23-001 -488-

and Southwest Transmission add that different outcomes are apt to flow from how 

benefits are defined. Public utilities may value needs and interests differently from other 

stakeholders, and customers and entities will not all have the same needs and interests. 

Arizona Cooperative and Southwest Transmission are concerned that it may be deemed 

to receive benefits that have little or nothing to do with its needs. 

660. Georgia PSC and Florida PSC seek clarification of the definition of benefits and 

what constitutes too narrow or too broad a definition. Florida PSC asserts that leaving 

this question to the stakeholder and subsequent compliance process creates the possibility 

that regions will adopt a definition of benefits that does not meet whatever undefined 

standard the Commission may have in mind. It argues that this approach limits regional 

autonomy in an undefined way, even though the Commission states that regions are free 

to determine their own definitions of benefits.

661. Georgia PSC and Florida PSC also seek clarification of what benefits must be 

quantifiable and based on existing policies in state and federal law. Florida PSC argues 

that ambiguities on this issue and what constitutes too broad or narrow a definition of 

benefits violate the Due Process Clause “fair notice” requirement.787 

 787 Florida PSC at 8 (citing Trinity Broadcasting of Fla., Inc. v. FCC, 211 F.3d 

618, 628 (D.C. Cir. 2000)).
Docket No. RM10-23-001 -489-

662. Other petitioners argue that the definitions of “benefits” and “beneficiary” were 

left too broad.788 Kentucky PSC argues that the Commission erred in failing to define 

“cost causer” and “beneficiary.”789 It asserts that recently there has been considerable 

dispute over the meaning of cost causer and when an entity becomes a beneficiary of a 

new or expanded facility developed by others. Kentucky PSC is concerned that there is 

no requirement that cost allocation processes account for proximity to a project, which it 

asserts is directly related a project’s actual benefits in terms of improving reliability, 

reducing congestion, and opening markets. It contends that it appears that a project may 

be eligible for cost allocation solely due to its ability to meet the public policy 

requirements of state or federal governments.790 Kentucky PSC explains that there is no 

requirement that a state have a need for a project, which will result in ratepayers paying 

for projects that may not be located within their state and that are designed to meet other 

states’ public policy requirements. It maintains that to exempt a state’s ratepayers from 

cost allocation only if they will not benefit at present or in a “future scenario” appears to 

enable the majority in a regional planning entity to decide that a particular state’s 

 788 See, e.g., Coalition for Fair Transmission Policy; and PSEG Companies.

789 Kentucky PSC at 5.

790 Kentucky PSC at 6 (quoting Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at 

P 585).
Docket No. RM10-23-001 -490-

legislature will, or should, ultimately enact certain public policies or that the federal 

government will do so.

663. Likewise, Coalition for Fair Transmission Policy argues that not limiting the 

definition of “benefits” and “beneficiary” will lead to uncertainty and dispute.791 It states 

that a beneficiary-pays approach is appropriate for certain types of projects, such as 

projects driven by reliability compliance obligations, because the relationship between 

specific transmission projects, reliability impacts, and the benefits of reliability are well 

established and capable of examination within a framework of existing transmission 

planning horizons and study methodologies. However, Coalition for Fair Transmission 

Policy asserts that it is difficult to define benefits and beneficiaries in a way that is just 

and reasonable and objectively verifiable for projects such as upgrades driven by 

economics and/or public policy requirements.

664. According to Coalition for Fair Transmission Policy, failure to define potential 

benefits correctly on compliance will have adverse economic and policy impacts. For 

instance, it maintains that if benefits are defined to include broad societal benefits of 

building renewables in a certain area, and that definition is used to justify cost 

socialization of transmission projects to that area, the generator or customer will not face 

the true costs of their resource decisions. Buyers may decide to buy from remote 

 791 Coalition for Fair Transmission Policy at 8.
Docket No. RM10-23-001 -491-

renewable resources that require long-distance transmission, rather than potentially lower 

cost local renewable resources, because they do not have to pay the full transmission 

costs. According to Coalition for Fair Transmission Policy, competitive wholesale 

markets using locational-marginal pricing would at that point begin to see price signals 

break down and become inefficient. It also argues that siting may become more difficult 

because those required to pay for lines they do not see benefit from will litigate both the 

cost and siting-approval processes.

665. Coalition for Fair Transmission Policy urges the Commission to limit regions to 

considering only benefits that: (1) occur within the typical transmission planning horizon 

of the public utilities within the region that can be measured or projected through the 

kinds of transmission planning studies that are normally conducted; (2) are not 

speculative; and (3) are not based on “societal” benefits that are not embodied in existing 

federal and state public policy requirements.792 It also argues that the Commission 

should clarify that regional transmission planning may not adopt presumptions that broad 

categorizations of types or classes of transmission lines driven by economic or public 

policy requirements have broad benefits and should be allocated widely. Also, Coalition 

for Fair Transmission Policy and North Carolina Agencies argue that the Commission 

should require that those seeking cost allocations for individual transmission projects be 

 792 Coalition for Fair Transmission Policy at 13.
Docket No. RM10-23-001 -492-

able to demonstrate quantifiable, observable and tangible reliability and economic 

benefits with reasonable particularity that is tied directly to those who will be required to 

pay under a cost allocation methodology. North Carolina Agencies argue that both the 

FPA and Commission precedent require the allocation of costs in proportion to the real 

reliability and economic benefits resulting from a transmission investment that can be 

measured or projected within the planning horizon.

666. In addition, Coalition for Fair Transmission Policy argues that the Commission 

should revise its cost allocation principles to assure that benefits are defined in way that 

conforms with what it asserts are established cost-causation standards, which include, 

among other things, tying cost allocation to the taking of transmission service.793

667. Coalition for Fair Transmission Policy maintains that while Order No. 1000 states 

that the Commission will fill in the gaps that it left in Order No. 1000 through the process 

of accepting or rejecting or requiring modification of proposed definitions, the courts 

have rejected this approach as contrary to law, arbitrary and capricious.794 Coalition for 

 793 Coalition for Fair Transmission Policy at 15-16 (citing Midwest ISO 

Transmission Owners v. FERC, 373 F.3d 1361, 1369 (D.C. Cir. 2004); citing Illinois 

Commerce Commission v. FERC, 576 F.3d at 474-77; citing Pacific Gas & Electric Co. 

v. FERC, 373 F.3d 1315, 1321 (D.C. Cir. 2004); quoting Algonquin Gas Transmission 

Co. v. FERC, 948 F.2d 1305, 1312-14 (D.C. Cir. 1991)).

794 Coalition for Fair Transmission Policy at 14 (citing Appalachian Power Co. v. 

EPA, 208 F.3d 1015, 1020 (D.C. Cir. 2000)).
Docket No. RM10-23-001 -493-

Fair Transmission Policy asserts that the Commission must supply sufficient explanation 

to provide a reasonable benchmark and guidance in the development of compliance 

filings. Coalition for Fair Transmission Policy asserts that the lack of additional guidance 

creates a risk of stalemate at the regional level and a likelihood that the Commission 

ultimately would have to define the terms for a region. It argues that this would 

essentially penalize public utility transmission providers because the process is designed 

to fail and then be saved by the Commission.

668. Illinois Commerce Commission argues that there is no way to identify “more 

efficient or cost effective” transmission projects in the planning process without a 

meaningful estimation of benefits, and there is no way to assess whether a transmission 

provider has complied with the Commission’s directive that costs be allocated at least 

roughly commensurate with benefits unless the level of benefits expected to be provided 

by a project to each load-serving entity have been determined.795 It adds that if the 

Commission’s requirements are not clear, there will be no basis to make compliance 

findings or to detect planning and cost allocation abuses.

669. Illinois Commerce Commission and MISO Northeast seek clarification that 

generators are subject to regional cost allocation. Illinois Commerce Commission 

requests clarification that costs can be recovered when the planning itself is undertaken to 

 795 Illinois Commerce Commission at 10.
Docket No. RM10-23-001 -494-

accommodate the interconnection of particular generators. It notes that Order No. 1000 

ruled out participant funding as an acceptable regional or interregional cost allocation 

method, but Illinois Commerce Commission states that participant funding has applied to 

generation developers that agree to fund transmission network upgrades to enable their 

generator to be interconnected to the network. Illinois Commerce Commission requests 

clarification that Order No. 1000 does not prohibit transmission providers from finding 

generators to be cost causers or beneficiaries of new transmission facilities developed 

pursuant to the regional or interregional planning process and allocating costs to those 

generators accordingly. MISO Northeast likewise requests that the Commission clarify 

that any regionwide cost allocation method adopted pursuant to Order No. 1000 must 

allocate costs to generators and end-users commensurate with the share of public policy 

benefits that they receive.

670. In contrast, NextEra argues that generators should not be responsible for costs not 

specified in interconnection agreements. It explains that Order No. 2003 recognized that 

generators must be able to identify all risks prior to entering into an interconnection 

agreement and commencing construction when it concluded that interconnection 

customers should only be responsible for costs specifically identified in their 

interconnection agreements.796 It argues that it follows that generators should not be 

 796 NextEra at 18 (citing Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 421).
Docket No. RM10-23-001 -495-

responsible for costs not identified in their interconnection agreements, and asserts that if 

costs could be so allocated, it would make the cost of project financing prohibitive 

because lenders would likely seek protection for such contingencies. NextEra thus urges 

the Commission to clarify that generators and other tie line owners will not be 

responsible for costs not specified in their interconnection agreements, which it argues is 

consistent with Order No. 1000’s conclusion that costs cannot be involuntarily allocated 

to non-beneficiaries. Otherwise, NextEra argues, such unknowable and unworkable cost 

allocation creates unjust and unreasonable risks and would be inconsistent with Order 

No. 2003.

671. Illinois Commerce Commission also takes issue with the requirement in Order No. 

1000 that cost allocation methods consider the benefits and costs of groups of new 

transmission facilities rather than requiring that each project satisfy the Commission’s 

principles and requirements on its own merits. It argues that a portfolio approach to 

transmission planning allows the approval of projects that, when considered individually, 

are not cost beneficial. 

672. Illinois Commerce Commission states that if individual projects are cost 

beneficial, and in the aggregate their estimated benefits are roughly commensurate with a 

postage stamp allocation, then an allocation according to the benefits of each project 

individually would result in an allocation roughly equivalent with a postage stamp 

allocation. It argues that this scenario would render the postage stamp allocation 
Docket No. RM10-23-001 -496-

unnecessary. Therefore, Illinois Commerce Commission argues that the Commission 

erred by including the word “aggregate” in Principle 1 because it allows transmission 

providers to avoid demonstrating that each individual project is cost beneficial. It also 

argues that the Commission violated the FPA and case precedent in failing to remove 

postage stamp rates as a possible cost allocation method. Specifically, it maintains that it 

is incorrect to conclude that even when “all customers within a transmission planning 

region are found to benefit from the use or availability of a transmission facility or class 

or group of transmission facilities,” they all benefit roughly equally.797 Illinois 

Commerce Commission also points to the Seventh Circuit’s statement that an assertion of 

generalized system benefits is not sufficient to justify a cost allocation and that alleged 

benefits, without specific evidentiary support, are too speculative to be considered.

673. Finally, ELCON, AF&PA, and the Associated Industrial Groups argue that use of 

a postage stamp rate for cost allocation at the regional or interregional level is a form of 

cost socialization, and it is therefore inconsistent with the cost causation principle. They 

also maintain that the statement by the court in Illinois Commerce Commission that 

benefits be at least roughly commensurate with costs requires one to conclude that a 

postage stamp rate is an impermissible form of cost causation. 

 797 Illinois Commerce Commission at 16.
Docket No. RM10-23-001 -497-

i. Commission Determination

674. We affirm Order No. 1000 and therefore deny those arguments requesting us to 

prescribe a particular definition of “benefits” or “beneficiaries.” As the Commission 

found in Order No. 1000, the proper context for further consideration of these matters is 

on review of compliance proposals and a record before us. Many of the petitioners here 

essentially expound on concerns they raised in the rulemaking proceeding that more 

specificity in Order No. 1000 itself is required because an overly broad or overly narrow 

definition of beneficiary or beneficiaries could lead to cost allocations that do not 

correspond to cost causation. However, as stated in Order No. 1000, we believe that 

concerns regarding overly narrow or broad interpretations of benefits will be addressed in 

the first instance during the process of public utility transmission providers consulting 

with their stakeholders as part of the development of a compliance filing. If such 

interpretations should emerge, we can more effectively ensure that the term is not given 

too narrow or broad a meaning by considering a specific proposal and a record than by 

attempting to anticipate and rule on all possibilities before the fact. This point applies 

equally to those petitioners that note the potential difficulties in quantifying benefits.798 

For this reason, we decline to adopt any of the many suggestions offered by petitioners in 

their requests for rehearing and clarification, including those who argue that only certain 

 798 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 624-25.
Docket No. RM10-23-001 -498-

benefits, such as reliability benefits, should be considered, because determining other 

types of benefits is difficult or speculative.

675. In response to Illinois Commerce Commission’s concern that by not providing a 

definition of “benefits” in Order No. 1000 the Commission would exacerbate an RTO’s 

ability to favor its transmission owning members to the detriment of other stakeholders, 

we first note that we do not accept the premise that RTOs as a rule engage in such 

behavior. In any event, when each public utility transmission provider, including an 

RTO, proposes its cost allocation method or methods, the Commission will review the 

method or methods, including how benefits and beneficiaries are defined, to determine 

whether it complies with the requirements of Order No. 1000. This review will include 

an analysis of whether the cost allocation method or methods comply with Principle 1, 

which requires that the cost allocation method or method result in an allocation of costs 

roughly commensurate with benefits. If the compliance filing is unclear on these matters 

or if parties take issue with aspects of the compliance filing, such as the definition of 

benefits, the Commission will address those issues at that time. 

676. We also disagree with petitioners, such as Georgia PSC and Florida PSC, who 

assert that by not defining benefits the Commission is limiting regional autonomy. By 

permitting public utility transmission providers in a region to define benefits collectively 

together with regional stakeholders, the Commission is enabling them to account for 

regional differences rather than prescribing a one-size-fits-all method that might not do so 
Docket No. RM10-23-001 -499-

as effectively. We also decline to grant the requests of Georgia PSC and Florida PSC for 

clarification of what benefits must be quantifiable based on existing policies in state and 

federal law. Consistent with the discussion above, we believe that this is a matter that is 

best addressed in the first instance by the public utility transmission providers and their 

stakeholders in the development of the cost allocation methods for their regions. 

Furthermore, Florida PSC’s argument that the fair notice requirement of the Due Process 

Clause requires a definition of benefits is without merit, as Florida PSC and all other 

stakeholders will have ample opportunity to participate in both in the development of the 

cost allocation methods for their regions, as well as in the Commission proceeding to 

review the compliance filings that incorporate those cost allocation methods. 

677. Moreover, we note that, as applied by the courts, the Due Process standard has 

been held to allow for flexibility in the wording of an agency’s rules and for a reasonable 

breadth in their construction.799 In fact, the courts have recognized that “by requiring 

regulations to be too specific, [courts] would be opening up large loopholes allowing 

conduct which should be regulated to escape regulation.”800 As the Supreme Court has 

noted, the degree of vagueness tolerated by the Constitution depends in part on the nature 

 799 See Grayned v. City of Rockford, 408 U.S. 110 (1971) (holding that an antinoise ordinance was not vague where the words of the ordinance “are marked by 

flexibility and reasonable breadth, rather than meticulous specificity.”).

800 See Ray Evers Welding Co. v. OSHRC, 625 F.2d 726, 730 (6th Cir. 1980).
Docket No. RM10-23-001 -500-

of the rules at issue.801 In the case of economic regulation, the Supreme Court has found 

that the vagueness test must be applied in a less strict manner because, among other 

things, “the regulated enterprise may have the ability to clarify the meaning of the 

regulation by its own inquiry, or by resort to an administrative process.”802

678. We also note several petitioners’ concerns that the definitions of “benefits,” 

“beneficiary,” and “cost causer,” are too broad, which they argue will lead to further 

disputes. As the Commission stated in Order No. 1000, the Commission is allowing 

flexibility to accommodate a variety of approaches which can better advance the goals of 

Order No. 1000, recognizing that regional differences may warrant distinctions in cost 

allocation method or methods.803 This flexibility is provided so that public utility 

transmission providers and their stakeholders can develop cost allocation methods that 

best meet their region’s needs. The Commission established the Cost Allocation 

Principles to provide general guidance to public utility transmission providers to limit 

uncertainty as they develop their compliance filings. However, for those cost allocation 

methods to be accepted by the Commission as Order No. 1000-compliant, they will have 

to clearly and definitively specify the benefits and the class of beneficiaries. 

 801 See Village of Hoffman Estates v. The Flipside, Hoffman Estates, Inc., 455 U.S. 

489 (1981).

802 See id. at 498.

803 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 624.
Docket No. RM10-23-001 -501-

Accordingly, we disagree with the premise of some petitioners’ arguments that there will 

be uncertainty once the Commission accepts the cost allocation method or methods in 

exactly who is a beneficiary and how such determinations are made. That is the very 

purpose of requiring an ex ante cost allocation method: to be clear upfront about who is 

benefitting so that disputes are minimized and so that the transmission facilities selected 

in the regional transmission plan for purposes of cost allocation are more likely to be 

constructed. 

679. Additionally, we agree with Illinois Commerce Commission’s argument that there 

is no way to identify “more efficient or cost effective” transmission solutions, or to assess 

whether costs are being allocated at least roughly commensurate with benefits, without a 

meaningful estimation of benefits. However, we do not believe that this requires any 

change or clarification to Order No. 1000. As we explain above, while Order No. 1000 

does not define benefits and beneficiaries, it does require the public utility transmission 

providers in each region to be definite about benefits and beneficiaries for purposes of 

their cost allocation methods. Once beneficiaries are identified, public utility 

transmission providers would then be able to identify what is the more efficient or cost 

effective transmission solution or assess whether costs are being allocated at least roughly 

commensurate with benefits.

680. With respect to generators being identified as beneficiaries and ultimately 

responsible for costs, we find that just as each transmission planning region retains the 
Docket No. RM10-23-001 -502-

flexibility to define benefit and beneficiary, the public utility transmission providers in 

each transmission planning region, in consultation with their stakeholders, may consider 

proposals to allocate costs directly to generators as beneficiaries that could be subject to 

regional or interregional cost allocation. However, we emphasize that any effort to do so 

must not be inconsistent with the generator interconnection process under Order No. 

2003804 because, as we stated in Order No. 1000, the generator interconnection process 

and interconnection cost recovery are outside the scope of this rulemaking. With this 

said, however, we are not minimizing the importance of evaluating the impact of 

generation interconnection requests during transmission planning, nor limiting the ability 

of public utility transmission providers to take requests for generator interconnections 

into account in developing assumptions to be used in the transmission planning 

process.805 While we agree with NextEra that interconnection costs would be specified in 

interconnection agreements, we deny NextEra’s request that the Commission clarify 

those are the only transmission costs for which generators could be responsible. The 

 804 Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ¶ 31,146, order on reh’g, 

Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order 

No. 2003-B, 70 FR 265, FERC Stats. & Regs. ¶ 31,171, order on reh’g, Order No. 2003-

C, 70 FR 37661, FERC Stats. & Regs. ¶ 31,190 , aff'd sub nom. Nat’l Ass’n of Regulatory 

Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 

(2008).

805 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 760.
Docket No. RM10-23-001 -503-

Commission determined in Order No. 2003 that interconnection service does not convey 

the right to flow output of the interconnection customer’s generating facility onto the 

transmission provider’s transmission system and does not constitute a reservation of 

transmission capacity.806 Order No. 2003 states that the interconnection customer, load 

or other market participant would have to request either point-to-point or Network 

Integration Transmission Service under the Transmission Provider’s OATT in order to 

receive the delivery service that is a prerequisite to flowing power onto the system.807 As 

such, the interconnection customer could be subject to charges associated with 

transmission service that are not addressed in its interconnection agreement.

681. We affirm the Commission’s finding in Order No. 1000 that in determining the 

beneficiaries of transmission facilities, Regional Cost Allocation Principle 1 should 

permit a regional transmission planning process to “consider benefits including, but not 

limited to, the extent to which transmission facilities, individually or in the aggregate, 

provide for maintaining reliability and sharing reserves, production cost savings and 

congestion relief, and/or meeting Public Policy Requirements.”808 Order No. 1000 was 

 806 Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ¶ 31,146 at P 767.

807 Id.

808 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 622.
Docket No. RM10-23-001 -504-

not intended to restrict regional choice in the transmission planning and cost allocation 

process as petitioners request. 

682. Accordingly, we continue to believe that it is appropriate to allow public utility 

transmission providers in a transmission planning region to propose a cost allocation 

method that considers the benefits and costs of a group of new transmission facilities, 

although they are not required to do so.809 As such, we deny Illinois Commerce 

Commission’s arguments that ask us to decide in advance that such an approach is 

inappropriate and at odds with cost causation. We reiterate that if public utility 

transmission providers in a region in consultation with their regional stakeholders choose 

to propose and adequately support a cost allocation method or methods that considers the 

benefits and costs of a group of new transmission facilities, Order No. 1000 would not 

require a facility-by-facility showing, so long as the aggregate cost of the transmission 

facilities in the group is allocated roughly commensurate with aggregate benefits.810 

Such an approach could be reasonable if it, for instance, enables a transmission planning 

region to prioritize its new transmission facilities in such a way as to ensure benefits from 

the facilities and maximize the number of system users who will share in those benefits.

 809 Id. P 627.

810 Id. P 641.
Docket No. RM10-23-001 -505-

683. We also decline to forbid in advance the potential use of a postage stamp cost 

allocation method. We continue to believe that a postage stamp cost allocation method 

may be appropriate where all customers within a specified transmission planning region 

are found to benefit from the use or availability of a transmission facility or class or 

group of transmission facilities, especially if the distribution of benefits associated with a 

class or group of transmission facilities is likely to vary considerably over the long 

depreciation life of the transmission facilities amid changing power flows, fuel prices, 

population patterns, and local economic considerations.811 As such, we believe that 

public utility transmission providers, if they choose to do so in consultation with 

stakeholders, should be permitted to make the case in their compliance filings that a 

postage stamp cost allocation is consistent with Principle 1’s requirement that all costs be 

allocated roughly commensurate with benefits. To this end, we agree with Illinois 

Commerce Commission that any such case would have to do more than make a mere 

assertion of generalized system benefits. Last, we decline to address Illinois Commerce 

Commission’s arguments related to the MISO MVP proceeding in Docket No. ER10-

1791-000 as outside the scope of this proceeding.

 811 Id. P 605. 
Docket No. RM10-23-001 -506-

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

non-beneficiaries

a. Final Rule

684. The Commission adopted the following Cost Allocation Principle 2 for both 

regional and interregional cost allocation:

Regional Cost Allocation Principle 2: Those that receive no benefit 

from transmission facilities, either at present or in a likely future 

scenario, must not be involuntarily allocated any of the costs of 

those transmission facilities.

and

Interregional Cost Allocation Principle 2: A transmission planning 

region that receives no benefit from an interregional transmission 

facility that is located in that region, either at present or in a likely 

future scenario, must not be involuntarily allocated any of the costs 

of that transmission facility.812

685. The Commission also required that every cost allocation method or methods 

provide for allocation of the entire prudently incurred cost of a transmission project to 

prevent stranded costs.813

 812 Id. P 637.

813 Id. P 640.
Docket No. RM10-23-001 -507-

b. Requests for Rehearing or Clarification

686. PSEG Companies argue that Principle 2’s “likely future scenarios” language is 

problematic because it could easily result in the expansion of the class of customers that 

are labeled beneficiaries as more scenarios are introduced, thus making cost allocation 

determinations more likely to be inexact and speculative.814 They further state that Order 

No. 1000’s statement that benefits must be “identifiable” does not cure the defect, 

particularly because Order No. 1000 allows not only transmission providers to identify 

the beneficiaries of proposed projects based on “likely future scenarios,” but also allows 

them to develop such scenarios based on potential public policy requirements.815 PSEG 

Companies argue that allowing transmission providers to exercise unfettered discretion in 

identifying beneficiaries under future scenarios will allow them to act arbitrarily and 

capriciously, and that the expansive interpretations of “benefits” and “beneficiaries” 

would permit the allocation of costs based on tenuous associations with benefits, contrary 

to Illinois Commerce Commission.

816

 814 PSEG Companies at 41-42.

815 PSEG Companies at 42-43.

816 PSEG Companies at 43-44. PSEG Companies also cite to Transcontinental 

Gas Pipe Line Corp., 112 FERC ¶ 61,170 (2005), where the Commission rejected 

reliance on a claim of generalized system benefits as a basis for allocating gas pipeline 

upgrade costs to existing shippers.
Docket No. RM10-23-001 -508-

687. ITC Companies seek clarification that a “likely future scenario” that would justify 

an allocation of costs for new transmission facilities includes the transmission planning 

scenarios being used by a transmission provider to prepare a regional transmission 

plan.817 ITC Companies state that one helpful clarification would be to confirm that, if a 

project is shown to have benefits for a zone or customer in one or more of the planning 

scenarios generally used by the transmission provider to prepare a regional transmission 

plan, those benefits satisfy Principle 2 and support the allocation of costs to the 

beneficiaries.

688. Long Island Power Authority seeks clarification that entities not subject to a 

Public Policy Requirement will have an opportunity to demonstrate this fact for purposes 

of cost allocation. Long Island Power Authority acknowledges, however, that where an 

approved project provides multiple benefits, it could be appropriate for an entity to be 

allocated that portion of a project’s costs that are unrelated to fulfilling certain public 

policy goals, provided that the economic and reliability related costs were allocated 

according to the economic and reliability procedures of the region, or as agreed upon by 

neighboring regions.

 817 ITC Companies at 14.
Docket No. RM10-23-001 -509-

c. Commission Determination

689. We affirm Order No. 1000’s adoption of Regional and Interregional Cost 

Allocation Principle 2. Accordingly, we deny PSEG Companies’ request for rehearing, 

which largely repeats arguments it made in the rulemaking proceeding. The Commission 

disagreed with PSEG Companies in Order No. 1000 that basing a determination of who 

constitutes a “beneficiary” on “likely future scenarios” necessarily would result in inexact 

and speculative proposed transmission plans and cost allocation methods.818 The 

Commission explained that scenario analysis is a common feature of electric power 

system planning, and that it believed that public utility transmission providers are in the 

best position to apply it in a way that achieves appropriate results in their respective 

transmission planning regions.819 We disagree that the use of “likely future scenarios” 

and Public Policy Requirements will expand the class of customers who will be identified 

as beneficiaries. The Commission stated in the discussion on Cost Allocation Principle 1 

above that the identification of beneficiaries is based on the principle of cost causation. 

Accordingly, the scenario analysis is not unfettered. It is limited to scenarios in which a 

beneficiary is identified as such on the basis of the cost causation principle.

 818 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 626.

819 Id.
Docket No. RM10-23-001 -510-

690. In response to ITC Companies, we therefore clarify that public utility transmission 

providers may rely on scenario analyses in the preparation of a regional transmission plan 

and the selection of new transmission facilities for cost allocation. If a project or group 

of projects is shown to have benefits in one or more of the transmission planning 

scenarios identified by public utility transmission providers in their Commissionapproved Order No. 1000-compliant cost allocation methods, Principle 2 would be 

satisfied. 

691. In response to Long Island Power Authority’s request that the Commission clarify 

that entities have the opportunity to demonstrate that a transmission project proposed to 

meet a given Public Policy Requirement is not applicable to them and provides no benefit 

to them, we affirm the Commission’s statement in Order No. 1000 that consideration of 

regional transmission needs driven by Public Policy Requirements must follow the cost 

allocation principles. For instance, Cost Allocation Principle 1 makes clear that Long 

Island Power Authority will be allocated only costs that are roughly commensurate with 

the benefits it receives from a transmission facility or facilities. Additionally, Cost 

Allocation Principle 2 states that those that receive no benefit from new transmission 

facilities, either at present or in a likely future scenario, must not be involuntarily 

allocated any of the costs of those transmission facilities.820 Given this, if it is true that 

 820 Id. P 219.
Docket No. RM10-23-001 -511-

Long Island Power Authority would not benefit from a transmission project or group of 

projects designed to meet a regional transmission need driven by a Public Policy 

Requirement, the transmission planning region’s cost allocation method or methods 

would not be permitted to allocate any costs to it. As Long Island Power Authority 

acknowledges, even if it does not need the transmission facility to meet a Public Policy 

Requirement of its own, it nevertheless may receive other economic or reliability benefits 

from a proposed transmission facility and then the cost allocation method may allocate 

the costs for the economic or reliability benefits received.

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

a. Final Rule

692. The Commission adopted the following Cost Allocation Principle 3 for both 

regional and interregional cost allocation:

Regional Cost Allocation Principle 3: If a benefit to cost threshold 

is used to determine which transmission facilities have sufficient net 

benefits to be selected in a regional transmission plan for the purpose 

of cost allocation, it must not be so high that transmission facilities 

with significant positive net benefits are excluded from cost 

allocation. A public utility transmission provider in a transmission 

planning region may choose to use such a threshold to account for 

uncertainty in the calculation of benefits and costs. If adopted, such 
Docket No. RM10-23-001 -512-

a threshold may not include a ratio of benefits to costs that exceeds 

1.25 unless the transmission planning region or public utility 

transmission provider justifies and the Commission approves a 

higher ratio.

and

Interregional Cost Allocation Principle 3: If a benefit-cost threshold 

ratio is used to determine whether an interregional transmission 

facility has sufficient net benefits to qualify for interregional cost 

allocation, this ratio must not be so large as to exclude a 

transmission facility with significant positive net benefits from cost 

allocation. The public utility transmission providers located in the 

neighboring transmission planning regions may choose to use such a 

threshold to account for uncertainty in the calculation of benefits and 

costs. If adopted, such a threshold may not include a ratio of 

benefits to costs that exceeds 1.25 unless the pair of regions justifies 

and the Commission approves a higher ratio.821 

 821 Id. P 646.
Docket No. RM10-23-001 -513-

693. The Commission stated that Cost Allocation Principle 3 did not require the use of 

a benefit to cost ratio threshold.822 However, if a transmission planning region chooses to 

have such a threshold, the principle limited the threshold to one that is not so high as to 

block inclusion of many worthwhile transmission projects in the regional transmission 

plan.823 Further, it allowed public utility providers in a transmission planning region to 

use a lower ratio without a separate showing and to use a higher threshold if they justify 

it and the Commission approves a greater ratio.824 

b. Request for Rehearing or Clarification

694. Transmission Dependent Utility Systems seek clarification, or in the alternative 

rehearing, that stakeholders will have access to the data necessary to replicate any 

benefit-to-cost analysis that public utility transmission providers conduct pursuant to Cost 

Allocation Principle 3. They state that the Commission did not respond in Order No. 

1000 to their argument that Cost Allocation Principle 3 be modified to ensure that 

implementation of any cost benefit analysis is transparent to load serving entity 

transmission customers.

 822 Id. P 647.

823 Id.

824 Id.
Docket No. RM10-23-001 -514-

c. Commission Determination

695. We find that it is not necessary to modify Cost Allocation Principle 3 to require 

transparency in the implementation of the benefit to cost analysis because this 

requirement already exists in Cost Allocation Principle 5. The language in Regional Cost 

Allocation Principle 5 and Interregional Cost Allocation Principle 5 states that “[t]he cost 

allocation method and data requirements for determining benefits and identifying 

beneficiaries...must be transparent with adequate documentation to allow a stakeholder 

to determine how they were applied.”825 Accordingly, we believe that it is clear that the 

transparency requirement in Cost Allocation Principle 5 applies to any benefit to cost 

analysis subject to Cost Allocation Principle 3, such that all data relating to the benefit to 

cost ratio must be transparent. Additionally, the Order No. 890 transparency principle 

requires “transmission providers to disclose to all customers and other stakeholders the 

basic criteria, assumptions, and data that underlie their transmission system plans.”826

 825 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 668.

826 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 471.
Docket No. RM10-23-001 -515-

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

transmission planning region(s) unless those outside voluntarily 

assume costs

a. Final Rule

696. The Commission adopted the following Cost Allocation Principle 4 for both 

regional and interregional cost allocation:

Regional Cost Allocation Principle 4: The allocation method for the 

cost of a transmission facility selected in a regional transmission 

plan must allocate costs solely within that transmission planning 

region unless another entity outside the region or another 

transmission planning region voluntarily agrees to assume a portion 

of those costs. However, the transmission planning process in the 

original region must identify consequences for other transmission 

planning regions, such as upgrades that may be required in another 

region and, if the original region agrees to bear costs associated with 

such upgrades, then the original region’s cost allocation method or 

methods must include provisions for allocating the costs of the 

upgrades among the beneficiaries in the original region.

and

Interregional Cost Allocation Principle 4: Costs allocated for an 

interregional transmission facility must be assigned only to 
Docket No. RM10-23-001 -516-

transmission planning regions in which the transmission facility is 

located. Costs cannot be assigned involuntarily under this rule to a 

transmission planning region in which that transmission facility is 

not located. However, interregional coordination must identify 

consequences for other transmission planning regions, such as 

upgrades that may be required in a third transmission planning 

region and, if the transmission providers in the regions in which the 

transmission facility is located agree to bear costs associated with 

such upgrades, then the interregional cost allocation method must 

include provisions for allocating the costs of such upgrades among 

the beneficiaries in the transmission planning regions in which the 

transmission facility is located.827

b. Requests for Rehearing or Clarification

697. Several petitioners argue that Principle 4 is inconsistent with cost causation.828 

Energy Future Coalition Group and AEP assert that the Commission should require

beneficiaries in adjoining regions to contribute to the costs of new transmission facilities. 

 827 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 657.

828 See, e.g., Joint Petitioners; Energy Future Coalition Group; and AEP.
Docket No. RM10-23-001 -517-

They assert that otherwise it is likely that intraregional transmission projects that are in 

the public interest, and would benefit customers in multiple regions, will fail. 

698. Energy Future Coalition Group argues that the Commission disregarded the 

beneficiary pays principle by providing that costs for a transmission facility located in 

one region may be allocated to beneficiaries in another region only if those beneficiaries 

volunteer to pay those costs.829 Energy Future Coalition Group, Joint Petitioners, and 

AEP add that the Commission’s decision fails to address the concern about free-riders. 

AEP argues that the Commission’s decision is contrary to its findings that the FPA and 

court precedent830 require all rates to “reflect to some degree the costs actually caused by 

the customer who must pay them,” and “[t]o the extent that a utility benefits from the 

costs of new facilities, it may be said to have ‘caused’ a part of those costs to be 

incurred.”831 AEP argues that this cost causation principle applies to all identifiable 

beneficiaries, not only those who voluntarily agree to pay the costs associated with the 

 829 Energy Future Coalition Group at 9 (citing Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 582).

830 AEP at 7 (citing Illinois Commerce Commission v. FERC, 576 F.3d 470 (7th

Cir. 2009); K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); Midwest 

ISO Transmission Owners v. FERC, 373 F.3d 1361, 1369 (D.C. Cir. 2004); 

Sithe/Independent Power Partners, L.P. v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002)).

831 AEP at 8 (quoting Illinois Commerce Commission v. FERC, 576 F.3d at 476).
Docket No. RM10-23-001 -518-

facilities. AEP further argues that the Commission’s policy results in unjust and 

unreasonable rates that discriminate against a set of customers.

699. Joint Petitioners further argue that it is arbitrary to follow the beneficiary pays 

principle within a region, but not across regions, when the Commission has declined to 

define what these regions should be and when they may have little or no electrical 

significance. AEP makes a similar argument. Energy Future Coalition Group and AEP 

also argue that there will be a perverse incentive to create regional boundaries for the 

purpose of evading cost responsibility for nearby transmission facilities. 

AEP adds that the choice between a regional and an interregional project configuration 

would make an enormous difference with respect to cost allocation, but that there may be 

very little difference in the distribution of benefits or the physical design of the project. 

700. Energy Future Coalition Group notes that the Commission held that within a given 

region, costs of a new project built wholly within the service territory of one transmission 

provider can be allocated to beneficiaries throughout the region if there is a clear regional 

benefit. It argues that this is directly analogous to the potential for extraregional benefits 

from a regional transmission project and asserts that the Commission unaccountably 

reaches the opposite conclusion as to the possibility of broader interregional cost 

allocation for a regional project with broader benefits.

701. Energy Future Coalition Group argues that the Commission can ensure that the 

attenuated assessments of benefits are avoided by providing that interregional planning 
Docket No. RM10-23-001 -519-

and cost allocation are required for a project located wholly within one region only when: 

(1) the extraregional benefits are directly related to the proposed transmission project, not 

to assumed electricity market reactions or influences; (2) the identified extraregional 

benefits are enjoyed in an adjacent planning region; and (3) the extraregional benefits are 

similar in nature to the benefits for which costs are proposed to be allocated within the 

region where the facility is proposed.832 

702. Joint Petitioners suggest that to limit the stakeholder burden of monitoring 

transmission planning in other regions, and in keeping with the evidence of the broad 

benefits of extra high voltage transmission, Regional Cost Allocation Principle 4 and 

Interregional Cost Allocation Principle 4 should be limited to transmission projects less 

than 345 kV. Joint Petitioners recommend that for projects at 345 kV and above, the 

Commission should expand its interregional coordination requirements to require that a 

regional planning entity notify its neighbors when it is considering such an extra high 

voltage project. Joint Petitioners state that the neighboring transmission planning region 

then could have an opportunity to participate in the planning process through which the 

project’s beneficiaries will be determined or may conduct its own planning process to 

consider the project. They suggest similar opportunities should be provided in the 

regional planning process. 

 832 Energy Future Coalition Group at 11.
Docket No. RM10-23-001 -520-

703. Similarly, AEP proposes that the Commission expand the scope of “interregional 

transmission facilities” to include new facilities located solely within a single region in 

certain circumstances, such as where the facilities are extra high voltage facilities that 

provide demonstrable benefits to the neighboring region.833 AEP adds that identification 

of potential beneficiaries will be strictly limited to a region that adjoins the region in 

which the facility will be located, and would specifically exclude any region that does not 

have a direct interconnection with the region in which the new facility is located. AEP 

asserts that this approach addresses several of the Commission’s concerns and does not 

place any undue burden on stakeholders.834 

704. MISO argues that Cost Allocation Principle 4 should not preclude an RTO from 

allocating to a withdrawing RTO member the cost of eligible transmission upgrades 

located solely in the RTO and approved before the withdrawal. It states that in recently 

accepting MISO’s tariff provisions regarding multi-value projects, the Commission 

specifically found just and reasonable tariff provisions that authorize allocating to a 

 833 AEP at 14.

834AEP adds that the Commission should find that the transmission planning 

provisions of the joint operating agreement between PJM and MISO meet the 

requirements of the Final Rule for interregional transmission coordination without the 

need to justify the process in a compliance filing. 
Docket No. RM10-23-001 -521-

withdrawing transmission owner the cost of a multi-value project approved before the 

withdrawal, although the associated facility will be located only in a MISO state. 

705. Vermont Agencies note that while Order No. 1000 states that it will not authorize 

the allocation of costs of facilities located in one region to entities located in another 

region, because Order No. 1000 does not define “region” it could be read to claim 

authority to force market participants into a region where they will be subject to cost 

allocation plans agreed upon by the participants in that region.835

706. Finally, North Carolina Agencies state that while the Commission approves 

Principle 4, the Commission also states that if there are benefits of a new transmission 

project to a public or non-public utility within a region that has no transmission 

arrangement with the entity building the project, costs can still be allocated to that utility 

if it is found to benefit from the project. According to North Carolina Agencies, the 

Commission has committed error by not recognizing this apparent contradiction in the 

foregoing statements, as well as by stating that the costs of new transmission projects 

may be allocated involuntarily to those that lack any sort of connection to the 

transmission project in question.

 835 Vermont Agencies at 9. 
Docket No. RM10-23-001 -522-

c. Commission Determination

707. We affirm Regional and Interregional Cost Allocation Principle 4. Accordingly, 

we deny the arguments of those petitioners that ask us to expand the scope of Cost 

Allocation Principle 4 to permit a transmission planning region where a new transmission 

facility is located to allocate costs of the facility unilaterally to a neighboring region that 

benefits from it. Such arguments fail to take into account the relationship between the 

Commission’s cost allocation reforms and the other reforms contained in Order No. 1000 

and the need to balance a number of factors to ensure that the reforms achieve the goal of 

improved planning and cost allocation for transmission in interstate commerce.

708. In Order No. 1000, the Commission acknowledged that its approach may lead to 

some beneficiaries of transmission facilities escaping cost responsibility because they are 

not located in the same transmission planning region as the transmission facility. 

Nonetheless, the Commission found this approach to be appropriate since Order No. 1000 

establishes a closer link between regional transmission planning and regional cost 

allocation, both of which involve the identification of beneficiaries. In light of that closer 

link, the Commission found that allowing one region to allocate costs unilaterally to 

entities in another region would impose too heavy a burden on stakeholders to actively 

monitor transmission planning processes in numerous other regions, from which they 

could be identified as beneficiaries and be subject to cost allocation. The Commission 

noted that if it expected such participation, the resulting regional transmission planning 
Docket No. RM10-23-001 -523-

processes could amount to interconnectionwide transmission planning with 

corresponding cost allocation, albeit conducted in a highly inefficient manner. The 

Commission further explained that it is not requiring either interconnectionwide 

transmission planning or interconnectionwide cost allocation.836

709. Moreover, the discussion above highlights the importance that the ability to 

participate in the transmission planning and cost allocation process has for the 

Commission’s transmission planning reforms. While the Commission concluded in 

Order No. 1000 that cost allocation is not dependent on a preexisting contractual 

relationship, we also think it is important that any entities that will be responsible for 

costs have an opportunity to participate in the process through which they will be 

allocated costs. This follows directly from the requirement of Order No. 890 that 

transmission planning be open and transparent. It also promotes a close link between 

transmission planning and cost allocation and helps to ensure fairness, which ultimately 

promotes successful transmission planning. Entities outside of a region may not be 

capable of being full participants in each and every region’s transmission planning 

process in which they could potentially be allocated transmission costs. Unilateral 

allocation of costs to them thus could undermine rather than promote the linking of cost 

allocation and transmission planning. 

 836 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 660.
Docket No. RM10-23-001 -524-

710. Energy Future Coalition Group, Joint Petitioners, and AEP state that failing to 

revisit Cost Allocation Principle 4 does not address the Commission’s concerns about 

free riders. North Carolina Agencies argue that the Commission’s adoption of Cost 

Allocation Principle 4 contradicts the Commission’s finding that costs can still be 

allocated to any entity that benefits from a new transmission facility without a 

transmission arrangement. As noted above, the Commission acknowledged in Order No. 

1000 that its decision this “may lead to some beneficiaries of transmission facilities 

escaping cost responsibility because they are not located in the same transmission 

planning region as the transmission facility.”837 However, the Commission’s cost 

allocation reforms represent a significant advance over current practices, and it is 

important to balance the possibility that some beneficiaries could escape cost 

responsibility against the larger goal of linking cost allocation with the transmission 

planning process for the purpose of improving that process. Additionally, as noted in our 

discussion of the need for the Commission’s reforms, transmission planning is more 

likely to succeed if it is understood in advance how the costs of planned facilities will be 

allocated. While a preexisting contract is not necessary to establish a cost allocation, we 

believe that an ability to participate in the process in which costs are allocated is 

important as it promotes the improved transmission planning that Order No. 1000 seeks 

 837 Id.
Docket No. RM10-23-001 -525-

to achieve. The Commission acknowledged in Order No. 1000 that some beneficiaries 

could escape cost responsibility as a result of the decision not to allow costs to be 

allocated outside the region in which a transmission facility is located, but the 

implementation of any policy often requires one to balance a number of considerations, 

which we believe Cost Allocation Principle 4 does appropriately. 

711. For these same reasons, we decline to adopt the suggestions made by those 

petitioners that attempt to address the burden on stakeholders to participate in several 

transmission planning regions, by for example, limiting extraregional cost allocation to 

higher voltage facilities or by requiring that costs be allocated only to regions adjacent to 

the one in which a transmission facility is located. While we agree that these suggestions 

might mitigate the burden on some stakeholders, we nevertheless are not convinced that 

they are sufficient to ensure that the Commission is not through this rulemaking 

proceeding effectively requiring interconnectionwide transmission planning. In any 

event, nothing in Order No. 1000 would prohibit regions from voluntarily agreeing to 

bear the costs for transmission facilities located in neighboring regions and from which 

they receive a benefit. Doing so is not inconsistent with Cost Allocation Principle 4.838 

712. We further disagree with petitioners that this determination will result in arbitrary 

drawing of regional boundaries to avoid cost allocation. In Order No. 890, the 

 838 Id. PP 658-59.
Docket No. RM10-23-001 -526-

Commission determined that “the scope of a transmission planning region should be 

governed by the integrated nature of the regional power grid and the particular reliability 

and resource issues affecting individual regions.”839 Consistent with that guidance, 

regions already have defined themselves for purposes of transmission planning. The 

Commission appreciates that these regional boundaries may change in response to Order 

No. 1000, but any such changes will be subject to Commission review on compliance to 

ensure that they continue to be appropriate. In response to Vermont Agencies’ concerns 

about entities being forced into regions against their will, we note that in Order No. 1000, 

the Commission found that a transmission planning region “is one in which public utility 

transmission providers, in consultation with stakeholders and affected states, have agreed 

to participate in for purposes of regional transmission planning and development of a 

single regional transmission plan.”840 

713. We agree with AEP that there can be cases where a project can have similar 

transmission flow impacts whether it is configured regionally or interregionally. 

However, we conclude that the regional and interregional transmission planning and 

coordination requirements of Order No. 1000 provide sufficient opportunities for

 839 Id. P 160 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 527).

840 Id. P 160 (emphasis added).
Docket No. RM10-23-001 -527-

analyzing the potential benefits of new transmission facilities, whether regional or 

interregional in configuration. 

714. In response to MISO, we clarify that Cost Allocation Principle 4 does not preclude 

an RTO from allocating to a withdrawing RTO member the cost of eligible transmission 

upgrades located solely in the RTO and approved before the withdrawal pursuant to a 

Commission-approved RTO agreement. 

6. Whether To Establish Other Cost Allocation Principles

a. Final Rule

715. In Order No. 1000, the Commission stated that it did not believe that any 

additional cost allocation principles were necessary at that time.841

b. Requests for Rehearing

716. ELCON, AF&PA, and the Associated Industrial Groups argue that Order No. 

1000 should address whether the costs of new transmission occasioned by low capacity 

factor resources should be allocated on a capacity basis. They assert that the Commission 

devoted no substantive consideration to this issue, and deferred it to the regional 

transmission planning processes. ELCON, AF&PA, and the Associated Industrial 

Groups assert that FERC provided no explanation for why this issue is better addressed 

by regional planning agencies. For example, they argue that allocating the fixed costs of 

 841 Id. P 705.
Docket No. RM10-23-001 -528-

transmission facilities intended to transmit wind energy to load centers on a volumetric 

basis inappropriately subsidies wind energy, which is inconsistent with resource 

neutrality and economically efficient resource allocation. Moreover, ELCON, AF&PA, 

and the Associated Industrial Groups argue that allocating these costs on any basis other 

than a capacity basis would unfairly penalize and significantly increase costs for those 

customers that have invested in operational changes to minimize consumption during 

system peak periods.

c. Commission Determination

717. We disagree with ELCON, AF&PA, and the Associated Industrial Groups’ 

assertion that the Commission dismissed their proposal for new principles that would 

address cost allocation on a capacity basis without explanation. In Order No. 1000, the 

Commission declined to adopt additional principles proposed by commenters because the 

Commission believed that to do so would limit the flexibility provided to public utility 

transmission providers in proposing the appropriate cost allocation method or methods 

for their transmission planning region or pair of transmission planning regions.842 We 

continue to believe this to be the case, and we therefore affirm the Commission’s 

decision on this issue.

 842 Id.
Docket No. RM10-23-001 -529-

E. Application of Cost Allocation Principles

1. Participant Funding

a. Final Rule

718. In Order No. 1000, the Commission found that participant funding is permitted, 

but not as a regional or interregional cost allocation method.843 The Commission 

explained that if proposed as a regional or interregional cost allocation method, 

participant funding would not comply with the regional or interregional cost allocation 

principles adopted in Order No. 1000.844 The Commission explained, however, that these 

principles do not in any way foreclose the opportunity for a transmission developer, a 

group of transmission developers, or one or more individual transmission customers to 

voluntarily assume the costs of a new transmission facility.845

b. Requests for Rehearing or Clarification

719. Several petitioners request rehearing or clarification of the Commission’s finding 

that participant funding cannot be the regional or interregional cost allocation method.846 

 843 Id. P 723.

844 Id.

845 Id. P 724.

846 See, e.g., Illinois Commerce Commission; ELCON, AF&PA, and the 

Associated Industrial Groups; Arizona Cooperative; Ad Hoc Coalition of Southeastern 

Utilities; and Southern Companies.
Docket No. RM10-23-001 -530-

Ad Hoc Coalition of Southeastern Utilities states that, as a matter of policy, new long-line 

transmission facilities that span utility service areas must be supported by ascertainable 

demand, and that the most economically sound way to determine what facilities should be 

built, and at what price, is for those entities that will use the facilities to pay for them. 

ELCON, AF&PA, and the Associated Industrial Groups argue that prohibiting participant 

funding as a regional or interregional cost allocation method creates a new free rider 

problem. According to them, participants who, from an economic perspective, should be 

funding transmission, and could do so most expeditiously, will now have an incentive not 

to do so, because the cost will be allocated to other more peripheral beneficiaries as part 

of the regional transmission planning process.

720. ELCON, AF&PA, and the Associated Industrial Groups argue that the 

Commission’s explanation of why participant funding should be prohibited is both 

arbitrary and inconsistent when compared to determinations made by the Commission in 

Order No. 1000 concerning other cost allocation approaches. For instance, they state that 

the Commission was willing to leave the decision of whether postage stamp rate 

allocation is an appropriate cost allocation method to regional planning entities. ELCON, 

AF&PA, and the Associated Industrial Groups argue that Order No. 1000 subjects the 

two different cost allocation methods to widely divergent standards of scrutiny with no 

explanation as to why such differential treatment would be appropriate. They also seek 

clarification that Order No. 1000 allows participant funding to be used as the default for
Docket No. RM10-23-001 -531-

certain types of projects on a category basis where participant funding best matches cost 

causation principles.

721. Arizona Cooperatives and Southwest Transmission are concerned that Order No. 

1000 does not recognize the benefits of participant funding. For instance, Arizona 

Cooperatives and Southwest Transmission state that under participant funding, the cost of 

associated transmission is bundled with generation. If the bundled price is excessive, 

then the project does not attract customers and an unworthy investment is avoided.

722. Southern Companies argue that the Commission’s treatment of participant funding 

in Order No. 1000 is overly vague and unexplained. They state that the Commission 

should refine its guidance on rehearing to define “participant funding” more narrowly and 

in terms of the issue that Order No. 1000 seeks to address, rather than categorically 

excluding it. Southern Companies state the Commission should clarify that participant 

funding is only impermissible as a cost allocation method if there are identified 

beneficiaries and those beneficiaries would receive non-trivial, direct benefits and would 

be expected to participate in the facilities as a transmission customer or co-owner but for 

others valuing the new transmission facility more and agreeing to go ahead and support 

the project financially.

723. Southern Companies repeats arguments made above that the Supreme Court held 

the FPA is premised on the concept of voluntary sale and purchase of jurisdictional 

services and the courts have uniformly applied cost causation principles only in the 
Docket No. RM10-23-001 -532-

setting of relationships where privity exists. Therefore, it asserts that participant funding 

may well be the only cost allocation method or rate structure that is lawful for new 

regional and/or interregional transmission projects as envisioned by Order No. 1000. 

Southern Companies assert that without a privity relationship between the developer of a 

project and those expected to fund the project, there is no lawful basis upon which to 

impose a rate, and no assurance that any rate would be in connection with the provision 

of a jurisdictional service. Large Public Power Council and Ad Hoc Coalition of 

Southeastern Utilities also state that the Commission’s rejection of participant funding 

confounds a basic precept of the FPA that a utility’s ability to recover its costs rests on a 

contractual relationship with its customers. 

724. Southern Companies assert participant funding is consistent with cost causation 

and represents a proven-way of getting the costs of such regional and/or interregional 

transmission facilities allocated, paid and constructed on a timely basis.847 Southern 

Companies add that given the Commission’s objective to foster more development, 

categorical ex ante exclusion of a cost allocation method that has a proven track record of 

success does not reflect reasoned decision making. Large Public Power Council also 

 847 Southern Companies at 109 (citing Bryan K. Hill September 28, 2010 Affidavit 

at 31-32). 
Docket No. RM10-23-001 -533-

believes that the only economically sound way to determine what facilities should be 

built, and at what price, is to have those entities that will use the facilities pay for them.

725. On the other hand, Transmission Dependent Utility Systems commend the 

Commission’s ruling that participant funding cannot be used as a regional or interregional 

cost allocation method. Transmission Dependent Utility Systems also request that the 

Commission reaffirm its long-held policy prohibiting “and” pricing.848 Transmission 

Dependent Utility Systems assert the Commission should confirm that any limited use of 

participant funding in the future will be bound by the Commission’s same long-standing 

precedent.849

 848 Transmission Dependent Utility Systems at 31 (citing Standardization of 

Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & 

Regs. ¶ 31,146, at P 694 n.111 (2003), order on reh’g, Order No. 2003-A, FERC Stats. & 

Regs. ¶ 31,160 (2004), order on reh’g, Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171 

(2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005), aff’d 

sub. nom. Nat’l Ass’n of Regulatory Utils. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 

2007)). 

849 Transmission Dependent Utility Systems at 31 (citing Inquiry Concerning the 

Comm’n’s Transmission Pricing Policy for Transmission Services Provided by Pub.

Utils. Under the Fed. Power Act, 55 Fed. Reg. 55,031, FERC Stats. & Regs. ¶ 31,005, at 

31,142-43 (1994), clarified, 71 FERC ¶ 61,195 (1995); Am. Elec. Power Co., 67 FERC ¶ 

61,168 (1994)); see also Pennsylvania Elec. Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993).
Docket No. RM10-23-001 -534-

c. Commission Determination

726. We affirm Order No. 1000’s determination that participant funding is permitted, 

but not as a regional or interregional cost allocation method.850 We therefore continue to 

believe that if proposed as a regional or interregional cost allocation method, participant 

funding will not comply with the regional or interregional cost allocation principles 

adopted above. We remain concerned that reliance on participant funding as a regional 

or interregional cost allocation method increases the incentive of any individual 

beneficiary to defer investment in the hopes that other beneficiaries will value a 

transmission project enough to fund its development. Because of this, it is likely that 

some transmission facilities identified in the regional transmission planning process as 

more efficient or cost-effective solutions would not be constructed in a timely manner or 

would not be constructed at all, adversely affecting ratepayers. Moreover, reliance on 

participant funding as a regional or interregional cost allocation method leaves a 

transmission developer with no opportunity to allocate costs to beneficiaries identified in 

the regional transmission planning process, even if the developer’s transmission facility is 

identified as a more efficient or cost-effective solution and is selected in the regional 

transmission plan for purposes of cost allocation. In light of this prospect, a transmission 

 850 See Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 723-29.
Docket No. RM10-23-001 -535-

developer may decline to propose such a transmission facility in the regional transmission 

planning process. 

727. The Commission rejected participant funding as a regional or interregional cost 

allocation method because it does not comply with the regional or interregional cost 

allocation principles set forth in Order No. 1000. This is because participant funding by 

its nature does not assess transmission project benefits in regional or interregional terms. 

For this reason, it does not ensure that the allocation of costs will be roughly 

commensurate with benefits, since its focus is limited to transmission project participants 

rather than the regional or interregional impact of a transmission project. Many 

petitioners describe what they consider to be advantages of participant funding, but these 

descriptions and the arguments based on them do not show how participant funding 

satisfies the specific requirements or policy goals of Order No. 1000.

728. However, as Order No. 1000 made clear, we are not finding that participant 

funding leads to improper results in all cases. For example, a transmission developer 

may propose a project to be selected in the regional transmission plan for purposes of 

regional cost allocation but fail to satisfy the transmission planning region’s criteria for a 

transmission project selected in the regional transmission plan for purposes of cost 

allocation. Under such circumstances, the developer could either withdraw its 

transmission project or proceed to “participant fund” the transmission project on its own 

or jointly with others. In addition, it is possible that the developer of a facility selected in 
Docket No. RM10-23-001 -536-

the regional transmission plan for purposes of cost allocation might decline to pursue 

regional cost allocation and, instead, rely on participant funding. Moreover, nothing in 

Order No. 1000 forecloses the opportunity for a transmission developer, a group of 

transmission developers, or one or more individual transmission customers to voluntarily 

assume the costs of a new transmission facility. Accordingly, Order No. 1000 does not 

prohibit or, as Southern Companies assert, “categorically” exclude the use of participant 

funding. 

729. The Commission nowhere intended to suggest that participant funding has no 

place in the development of transmission infrastructure. As noted by Southern 

Companies, participant funding can result in timely construction of transmission facilities 

in many circumstances. Transmission developers who see particular advantages in 

participant funding remain free to use it on their own or jointly with others. This simply 

means that they would not be pursuing regional or interregional cost allocation. ELCON, 

AF&PA, and the Associated Industrial Groups do not explain what they mean by the use 

of participant funding “as the default for certain types of projects,”851 and we are not 

persuaded that the type of transmission project involved affects the ability of participant 

funding to satisfy the cost allocation principles of Order No. 1000.

 851 ELCON, AF&PA, and the Associated Industrial Groups at 16.
Docket No. RM10-23-001 -537-

730. The Commission did not state in Order No. 1000 that entities who support 

participant funding must show that it is uniquely the cost allocation method that follows 

“but for” cost causation principles, as ELCON, AF&PA, and the Associated Industrial 

Groups contend. The Commission simply stated that entities who had argued that it was 

such a method had not demonstrated that this was the case and that, moreover, the 

contention was at odds with existing precedent on cost causation.852 

731. Southern Companies maintain that participant funding means different things to 

different people and that the Commission should define it more narrowly for purposes of 

Order No. 1000. However, Southern Companies do not describe the different meanings 

of participant funding that they have in mind, and we therefore do not know what further 

refinements it believes would be in order.853 The Commission stated in Order No. 1000 

 852 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 726.

853 Southern Companies only state that the Commission’s “categorical exclusion” 

of participant funding had created a need to state specifically in Order No. 1000 (in 

response to Entergy) that prohibition of participant funding as a regional cost allocation 

mechanism “is not intended to modify existing pro forma OATT transmission service 

mechanisms for individual transmission service requests or requests for interconnection 

service.” Southern Companies at 106 (quoting Order No. 1000, FERC Stats. & Regs. ¶ 

31,323 at P 729). Southern Companies state that specifying this was important because 

long-term firm transmission service is a form of participant funding that addresses free 

rider issues, and this demonstrates the need for greater clarity on what the Commission is 

prohibiting. Id. However, Order No. 1000 does not create a “categorical exclusion” of 

participant funding, only an exclusion of the use of participant funding as a regional cost 

allocation method. We therefore do not see how the continued use of existing 

mechanisms for individual transmission service requests affects our conclusions on the 

(continued...)
Docket No. RM10-23-001 -538-

that “[u]nder a participant funding approach to cost allocation, the costs of a transmission 

facility are allocated only to those entities that volunteer to bear those costs.”854 In 

addition, the Commission noted in Order No. 1000 that the Proposed Rule cited to a 

number of concrete examples of the participant funding approach.855 We think that this 

provides sufficient guidance on the meaning of participant funding for purposes of Order 

No. 1000.

732. We disagree that precluding participant funding as a regional and interregional 

cost allocation method creates a new free rider problem by creating an incentive for what 

ELCON, AF&PA, and the Associated Industrial Groups describe as entities who should 

be funding a transmission project not to fund it in the hope of an allocation to additional 

beneficiaries. The primary goal of Order No. 1000’s cost allocation principles is to 

ensure that costs of regional transmission facilities selected in a regional transmission 

plan for purposes of cost allocation are allocated to beneficiaries in the region roughly 

 

use of participant funding for new transmission facilities selected in a regional 

transmission plan for purposes of cost allocation. As a result, we do not see the need for 

further refinements in the meaning of participant funding for purposes of Order No. 1000. 

We think that the two very different contexts at issue in Southern Companies’ argument –

firm transmission service requests and regional transmission planning – make such

analogies inappropriate.

854 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 486 n.375 (citing Proposed 

Rule, FERC Stats. & Regs. ¶ 32,660 at P 128).

855 Id. See Proposed Rule, FERC Stats. & Regs. ¶ 32,660 at P 128.
Docket No. RM10-23-001 -539-

commensurate with the benefits that they receive. It is unlikely that entities which 

benefit from such transmission facilities would decline to fund them. Moreover, we 

disagree with the argument that preclusion of participant funding as a regional or 

interregional cost allocation method creates an incentive not to develop a transmission 

project. On the contrary, a transmission developer will have the option of using 

participant funding or submitting its transmission project for evaluation in the regional 

transmission planning process to be selected for regional or interregional cost allocation. 

If its transmission project is selected in the regional transmission plan for purposes of 

cost allocation, the transmission developer would be able to allocate costs to beneficiaries 

consistent with the relevant cost allocation method, an opportunity that not only 

encourages development but also promotes development of more efficient or costeffective transmission solution to regional and interregional transmission needs. 

733. We think that this point helps illuminate why participant funding does not 

constitute an appropriate regional or interregional cost allocation method. Entities that 

might develop a transmission project through participant funding remain free to do so. 

However, exclusive reliance on such an approach creates an incentive not to consider 

potential regional or interregional transmission needs. It thus is not a method that is 

tailored to promote better regional and interregional transmission planning. 

734. We deny Southern Companies’ request for clarification on the situations in which 

participant funding should be impermissible. Southern Companies asserts that participant 
Docket No. RM10-23-001 -540-

funding should only be impermissible if there are identified beneficiaries and those 

beneficiaries would receive non-trivial, direct benefits and would be expected to 

participate in the facilities as a transmission customer or co-owner but for others valuing 

the new transmission facility more and agreeing to go ahead and support the project 

financially. The focus of the cost allocation reforms of Order No. 1000 is on 

transmission projects that are selected in the regional transmission plan for purposes of 

cost allocation, not the circumstances under which voluntary use of participant funding is 

appropriate. 

735. We disagree with ELCON, AF&PA, and the Associated Industrial Groups who 

see inconsistency in the Commission’s willingness to allow consideration of postage 

stamp rates as a cost allocation method, but not participant funding. As we noted above, 

Order No. 1000 found that a postage stamp cost allocation method may be appropriate 

where all customers within a specified transmission planning region are found to benefit 

from the use or availability of a transmission facility or class or group of transmission 

facilities, especially if the distribution of benefits associated with a class or group of 

transmission facilities is likely to vary considerably over the long depreciation life of the 

transmission facilities amid changing power flows, fuel prices, population patterns, and 

local economic considerations.856 Accordingly, unlike participant funding, if such a 

 856 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 605.
Docket No. RM10-23-001 -541-

showing can be made, a postage stamp cost allocation would meet Cost Allocation 

Principle 1’s requirement that costs be allocated roughly commensurate with benefits. 

Participant funding, on the other hand, is incapable of meeting the regional or 

interregional cost allocation principles set forth in Order No. 1000, because by its nature 

it is not a cost allocation method that accounts for potential regional or interregional 

benefits. 

736. We clarify, in response to Transmission Dependent Utility System’s request, that 

Order No. 1000 did not address or change the Commission’s policy on “and” pricing.857 

Order No. 1000 applies only to transmission projects that are selected in the regional 

transmission planning process for purposes of cost allocation. Participant funding cannot 

be the regional or interregional cost allocation method under Order No. 1000. Therefore, 

if a project’s costs are allocated under a participant funding method, by definition, it was 

not selected in the regional transmission planning process for purposes of cost 

allocation.858

 857 Standardization of Generator Interconnection Agreements and Procedures, 

Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order No. 2003-

A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003-B, FERC Stats. & 

Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 

(2005), aff'd sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277 

(D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008).

858 The Commission made clear in Order No. 1000 that transmission facilities that 

are selected in the regional transmission plan for purposes of cost allocation may not 

(continued...)
Docket No. RM10-23-001 -542-

737. Lastly, a number of petitioners argue that participant funding is the form of cost 

allocation that corresponds to what they assert is a requirement that cost allocation be 

premised on a contractual relationship. As we explained above,859 we reject the 

interpretation of the FPA that petitioners have offered, specifically that the FPA requires 

a contractual relationship before rates can be assessed. Contracts do not define or limit 

the benefits that a transmission customer receives from the entire transmission grid, 

which the courts have recognized in finding that the customer relationship is to the 

transmission grid as a whole, rather than the dictates of contracts.860 Therefore, 

petitioners’ arguments that the Commission’s finding that participant funding cannot be 

the regional or interregional cost allocation method are unfounded. 

F. Other Cost Allocation Issues 

1. Final Rule

738. In Order No. 1000, the Commission reiterated the approach it took in Order No. 

890, requiring that generation, demand resources, and transmission be treated comparably 

 

comprise all of the transmission facilities in the regional transmission plan, and therefore, 

participant funded facilities may be included in the regional transmission plan for other 

purposes. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 63.

859 See discussion supra at section IV.A.2.

860 See discussion supra at section IV.A.3.
Docket No. RM10-23-001 -543-

in the regional transmission planning process.861 Also, the Commission stated that while 

the consideration of non-transmission alternatives to transmission facilities may affect 

whether certain transmission facilities are in a regional transmission plan, the 

Commission concluded that the issue of cost recovery for non-transmission alternatives 

was beyond the scope of the cost allocation reforms adopted in Order No. 1000, which 

are limited to allocating the costs of new transmission facilities.

862

2. Requests for Rehearing or Clarification

739. California State Water Project argues that on rehearing the Commission should 

require all public utilities to exempt sponsors of demand-based transmission alternatives 

from Order No. 1000’s benefits-based cost allocation, as well as apply time-sensitive cost 

allocation. Specifically, it argues that customers investing in demand-based nontransmission alternatives and sponsors of demand-based transmission alternatives should 

not be subject to benefits-based cost allocation that in effect imposes discriminatory 

double billing for both the transmission alternative provided and for unused transmission 

automatically deemed to provide benefits. Moreover, it adds that the Commission has 

stated that customers’ ability to modify their behavior in response to price signals 

 861 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 779.

862 The Commission also recognized that, in appropriate circumstances, alternative 

technologies may be eligible for treatment as transmission for ratemaking purposes. 

Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 779 & n.563.
Docket No. RM10-23-001 -544-

benefits the entire grid and is among the best means of holding down costs and 

countering market power.863

740. California State Water Project also argues that the rule unduly discriminates 

against demand-based non-transmission alternatives as it stressed the need for clear cost 

allocation to promote transmission construction, yet declined to consider compensation 

and cost allocation for demand-based non-transmission alternatives. California State 

Water Project states that in the Energy Policy Act of 2005 Congress declared that the 

national policy of the United States is to promote demand response and to eliminate 

unnecessary barriers to demand response.864 It also states that the Commission followed 

up on this policy in Order No. 719, stating that “[a]ny reforms must ensure that demand 

response resources are treated on a basis comparable to other resources.”865 California 

State Water Project adds that under the FPA the Commission also must not permit undue 

discrimination against such resources. It notes that the Commission has applied this 

principle to avert undue discrimination against various kinds of resources, such as the 

 863 California State Water Project at 18 (quoting Order No. 719, FERC Stats. & 

Regs. ¶ 31,281 at P 41).

864 California State Water Project at 9-10 (citing Energy Policy Act of 2005, Pub. 

L. No. 109-58, § 1252(f), 119 Stat. 594 (2005)). 

865 California State Water Project at 10 (quoting Order No. 719, FERC Stats. & 

Regs. ¶ 31,281 at P 14).
Docket No. RM10-23-001 -545-

measures to remedy undue discrimination against non-incumbent transmission developers 

in Order No. 1000.866

741. California State Water Project recommends that the Commission incorporate 

benchmarks or metrics to support periodic evaluation of its success or failure in achieving 

nondiscriminatory promotion of both physical transmission upgrades and nontransmission alternatives. It argues that incorporating such benchmarks will ensure that 

the Commission and all concerned undertake appropriate improvements on a timely 

basis.

742. Transmission Dependent Utility Systems point out that in their comments during 

the Order No. 1000 proceeding, they requested that the Commission align local, regional 

and interregional planning and cost allocation processes and methods with formula rate 

protocols because those who pay the costs of needed new transmission infrastructure 

should not learn about projects for the first time in formula rate updates. In particular, 

Transmission Dependent Utility Systems argue that to the extent project upgrade costs 

are not discussed in the planning processes with stakeholders, a separate FPA section 205 

filing must be made for recovery of these costs. It argues that most public utility 

transmission providers have incentive rates and that the formula rate annual update 

 866 California State Water Project at 11 (citing Order No. 888, FERC Stats. & 

Regs. ¶ 31,036 at 31,669; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 229).
Docket No. RM10-23-001 -546-

process provides only limited opportunity to review and challenge costs included in the 

formula rate update filing. Transmission Dependent Utility Systems argue that their 

requested link between formula rate cost recovery and the local and regional planning 

and interregional coordination processes is within the scope of issues raised in this 

proceeding because it is a safeguard needed to ensure that load-serving customers, which 

pay for the costs of transmission upgrades, have a meaningful role in the development of 

regional and interregional projects and the allocation of the costs of those projects. 

Transmission Dependent Utility Systems further assert that Order No. 1000 failed to 

address this issue in a manner that comports with reasoned decision-making.867

743. Dayton Power and Light requests clarification that the Commission will issue a 

separate order on remand from the Seventh Circuit on Opinion No. 494868 in the near 

future that will specify a cost allocation mechanism for new high voltage facilities that 

complies with the Order No. 1000 principles.869 Dayton Power and Light states that 

failing to issue an order on remand would lead to renewed litigation a year from now to 

address the same issues using substantially the same evidence that is already before the 

 867 Transmission Dependent Utility Systems at 31 (citing K N Energy Inc. v. 

FERC, 968 F.2d 1295, 1303)). 

868 PJM Interconnection, L.L.C., 130 FERC ¶ 61,052 (2010).

869 Dayton Power and Light at 2, 4 (citing Illinois Commerce Commission v. 

FERC, 576 F.3d 470).
Docket No. RM10-23-001 -547-

Commission for decision and waste the resources of PJM members, PJM, and the 

Commission and its staff.

744. Dayton Power and Light urges the Commission to state explicitly that the use of 

the Distribution Factor analysis complies with the Order No. 1000 cost allocation 

principles. In support, Dayton Power and Light states that PJM has used distribution 

factor analysis to allocate the costs of new PJM facilities operating at less than 500 kV 

without question or challenge.

3. Commission Determination

745. We deny California State Water Project’s arguments and affirm Order No. 1000’s 

determination that cost allocation for non-transmission alternatives is beyond the scope of 

this proceeding, which is limited to allocating the costs of new transmission facilities. In 

response to California State Water Project’s suggestions regarding time-sensitive rates 

and the establishment of benchmarks, we affirm Order No. 1000, and therefore, will not 

establish minimum requirements governing which non-transmission alternatives should 

be considered or the appropriate metrics to measure non-transmission alternatives against 

transmission alternatives. We continue to believe that those considerations are best 

managed among the stakeholders and the public utility transmission providers 

participating in the regional transmission planning process.870 

 870 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 155.
Docket No. RM10-23-001 -548-

746. We deny Transmission Dependent Utility Systems’ request that we address a link 

between formula rates and cost allocation as beyond the scope of this proceeding. As we 

note above, and as we found in Order No. 1000, we are not addressing cost recovery 

issues here.871 In any event, we disagree with Transmission Dependent Utility Systems’ 

premise that those who pay for project upgrade costs that are selected in a regional 

transmission plan for purposes of cost allocation under the provisions of Order No. 1000 

may learn about these costs for the first time when flowed through a formula rate, when 

there would be only a limited opportunity to review the costs.872 As is clear in Order No. 

1000, any entity can participate in the regional transmission planning process and costs 

will be allocated only for those regional and interregional transmission facilities that have 

been selected in the regional transmission plan for purposes of cost allocation.873 

Therefore, Transmission Dependent Utility Systems will have a meaningful opportunity 

to participate in the development of regional and interregional transmission projects and 

the allocation of the costs of those transmission projects, whether or not these are 

incorporated into formula rates, through their ability to participate in the regional 

transmission planning process. Additionally, as noted above, in identifying the benefits 

 871 Id. P 563.

872 In any event, we note that when ratepayers learn of other formula costs is 

outside the scope of this proceeding.

873 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 503.
Docket No. RM10-23-001 -549-

and beneficiaries for a new transmission facility, the regional transmission planning 

process must provide entities who will receive regional or interregional cost allocation an 

understanding of the identified benefits on which the cost allocation is based, all of which 

would occur prior to the recovery of such costs through a formula rate.

747. In response to Dayton Power and Light’s request that the Commission find that the 

use of the distribution factor analysis complies with Order No. 1000 cost allocation 

principles, we reiterate what the Commission said in Order No. 1000 in response to 

commenters making similar arguments. We decline to prejudge whether any existing 

cost allocation method complies with the requirements of Order No. 1000. To the extent 

that Dayton Power and Light believes that to be the case in its transmission planning 

region, it can take such a position during the development of compliance proposals and 

during Commission review of compliance filings.874 Last, with respect to the timing 

concerns Dayton Power and Light describes regarding the relationship between our order 

on remand from the U.S. Court of Appeals for the Seventh Circuit on Opinion No. 494 

and the development of an Order No. 1000-compliant cost allocation method in PJM, the 

Commission has since issued an order in the Opinion No. 494 proceeding.875

 874 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 565.

875 PJM Interconnection, L.L.C., 138 FERC ¶ 61,230 (2012).
Docket No. RM10-23-001 -550-

V. Compliance and Reciprocity

A. Compliance

1. Final Rule

748. The Commission required that each public utility transmission provider must 

submit a compliance filing within twelve months of the effective date of Order No. 1000 

revising its OATT or other document(s) subject to the Commission’s jurisdiction as 

necessary to demonstrate that it meets the local and regional transmission planning and 

cost allocation requirements set forth in Order No. 1000. The Commission also required 

each public utility transmission provider to submit a compliance filing within eighteen 

months of the effective date of Order No. 1000 revising its OATT or other document(s) 

subject to the Commission’s jurisdiction as necessary to demonstrate that it meets the 

requirements set forth therein with respect to interregional transmission coordination 

procedures and an interregional cost allocation method or methods.876 

2. Requests for Rehearing or Clarification

749. Duke requests that the Commission rule on requests for clarification as soon as 

possible before issuance of an Order No. 1000 rehearing order so that stakeholders’ 

compliance efforts are not interrupted or entirely disrupted. MISO requests that the 

Commission clarify that RTOs and ISOs are not required to make any changes to their 

 876 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 792.
Docket No. RM10-23-001 -551-

tariffs or processes in connection with the participation of non-jurisdictional entities in 

regional or interregional planning and cost allocation processes. According to MISO, 

requiring the development of a regional plan and cost allocation process with an entity 

that has no such corresponding mandate is unreasonable, and it may not be possible to 

comply with such a requirement because compliance would depend entirely on the desire 

of such non-jurisdictional entities to coordinate. MISO states that at most, the 

Commission should require that Commission-jurisdictional entities engage in a good faith 

effort at regional coordination, planning, and cost allocation with non-jurisdictional 

entities.

750. NextEra seeks clarification that generator tie line owners that have OATTs on file 

can seek waiver of compliance with Order No. 1000 requirements, as the Commission 

has previously found that such lines are not integrated with the regional transmission grid 

for ratemaking purposes. It suggests that there may be confusion as to whether such tie 

line owners can seek waiver because of use of the word “and” rather than “or” when 

Order No. 1000 states that entities must seek waivers of Order Nos. 888, 889, and 890. 

NextEra contends that if the Commission intended to mean “or,” then the vast majority of 

tie line owners would not be subject to Order No. 1000.877 It also urges the Commission 

to adopt a broad-based waiver that focuses on the nature of a radial line, which it argues 

 877 NextEra at 16.
Docket No. RM10-23-001 -552-

would be consistent with the intent of the transmission planning process. NextEra argues 

that the fact that such tie lines are not integrated in the transmission grid should not be 

ignored. It states that the nature of a radial line does not change simply because one tie 

line owner may provide interconnection and transmission service to affiliates and have 

waivers from Order Nos. 888, 889, and 890 while another may provide the same service 

under an OATT to non-affiliates. NextEra states further that no generation tie lines 

should be required to participate in the regional transmission planning process unless they 

voluntarily choose to do so.878

3. Commission Determination

751. In response to Duke, we believe that addressing the requests for clarification of 

Order No. 1000 in this order is appropriate. Many of the requests for clarification are 

linked with requests for rehearing and are thus best addressed in the same order. 

Moreover, the Commission considered the need for providing timely clarifications in 

issuing this order now, and we believe that its issuance now allows stakeholders adequate 

time to address these clarifications in their compliance processes.

752. We clarify for MISO that a public utility transmission provider will not be deemed 

out of compliance with Order No. 1000 if it demonstrates that it made a good faith effort, 

 878 NextEra at 17 (citing Southern Cal. Edison Co., 117 FERC ¶ 61,103 (2006); 

Mansfield Mun. Elec. Dept. v. New England Power Co., 97 FERC ¶ 61,134 (2001)).
Docket No. RM10-23-001 -553-

but was ultimately unable, to reach resolution with neighboring non-public utility 

transmission providers on a regional transmission planning process, interregional 

transmission coordination procedures, or a regional or interregional cost allocation 

method.

753. In response to NextEra, we clarify that Order No. 1000’s determination that it 

“applies to public utilities that own, control or operate interstate transmission facilities 

other than those that have received waiver of the obligation to comply with Order Nos. 

888, 889, and 890”879 was meant to provide assurance to those entities that have existing 

waivers of those three rules that they would not also have to seek waiver of Order No. 

1000 in order to obtain waiver from it. This is consistent with the approach the 

Commission took to waivers in Order No. 890.880 This determination, however, was not 

meant to affect the ability of an entity that does not have a waiver to seek one. The 

 879 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 832.

880 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at n.105 (“The Commission 

clarifies that existing waivers of the obligation to file an OATT or otherwise offer open 

access transmission service in accordance with Order No. 888 shall remain in place. The 

reforms to the pro forma OATT adopted in this Final Rule therefore do not apply to 

transmission providers with such waivers, although we expect those transmission 

providers to participate in the regional planning processes in place in their regions, as 

discussed in more detail in section V.B. Whether an existing waiver of OATT 

requirements should be revoked will be considered on a case-by-case basis in light of the 

circumstances surrounding the particular transmission provider.”); see also Order No. 

890-A, FERC Stats. & Regs. ¶ 31,261 at P 36.
Docket No. RM10-23-001 -554-

Commission will entertain requests for waiver of Order No. 1000 on a case-by-case basis 

from any entity, including a generation tie line owner, that believes it meets the criteria 

for such waiver, which the Commission made clear in Order No. 1000 remains 

unchanged from that used to evaluate requests for waiver under Order Nos. 888, 889, and 

890.881 

B. Reciprocity

1. Final Rule

754. In Order No. 1000, the Commission found that to maintain a safe harbor tariff, a 

non-public utility transmission provider must ensure that the provisions of that tariff 

substantially conform, or are superior, to the pro forma OATT as it has been revised by 

Order No. 1000.882 The Commission stated that it was encouraged that, based on the 

efforts that followed Order No. 890, both public utility and non-public utility 

transmission providers collaborate in a number of regional transmission planning 

processes.883 Therefore, the Commission did not believe it was necessary to invoke its 

authority under FPA section 211A, which gives it authority to require non-public utility 

transmission providers to provide transmission services on a comparable and not unduly 

 881 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 832.

882 Id. P 815.

883 Id.
Docket No. RM10-23-001 -555-

discriminatory or preferential basis.884 However, the Commission stated that if it finds on 

the appropriate record that non-public utility transmission providers are not participating 

in the transmission planning and cost allocation processes required by Order No. 1000, 

the Commission may exercise its authority under FPA section 211A on a case-by-case 

basis.885 The Commission also emphasized that it is not modifying the scope of the 

reciprocity provision as established in Order No. 890.886 However, the Commission 

noted that it expects all public and non-public utility transmission providers in an existing 

regional transmission planning process comprised of both public and non-public utility 

transmission providers to participate in the transmission planning and cost allocation 

processes set forth in Order No. 1000. The Commission also noted that those non-public 

utility transmission providers that take advantage of open access under an OATT, 

including the OATT’s new provisions for improved transmission planning and cost 

allocation, should be expected to follow the same requirements as public utility 

transmission providers.887

 884 Id.

885 Id.

886 Id. P 816.

887 Id. P 818.
Docket No. RM10-23-001 -556-

2. Requests for Rehearing or Clarification

755. Petitioners request rehearing of Order No. 1000’s reciprocity requirement, arguing 

that the Commission is changing the scope of the principle of reciprocity under Order 

Nos. 888 and 890. For example, Large Public Power Council states that reciprocity as 

initially conceived in Order No. 888 was a matter of fundamental fairness. It states that 

this concept was clarified in Order No. 2004-A, where the Commission found that service 

provided by a non-public utility transmission provider did not have to be identical to the 

service provided by an investor-owned utility, only comparable to the service the nonpublic utility would receive for its own purposes. Large Public Power Council explains 

that Order No. 1000 appears to hold that a non-public utility’s obligation to provide 

reciprocal service outside a safe harbor tariff includes an obligation to participate in the 

planning and cost allocation processes implemented pursuant to Order No. 1000. Large 

Public Power Council states that including these planning and cost allocation obligations 

within a non-public utility’s reciprocity obligations would modify the scope of 

reciprocity, and thus requests that the Commission clarify whether this is its intention.

756. Likewise, National Rural Electric Coops state that it appears that the Commission 

misstated the reciprocity requirement in Order No. 1000 when it stated in paragraph 819 

that “the non-public utility transmission provider that owns, controls or operates 

transmission facilities must provide comparable transmission service that it is capable of 
Docket No. RM10-23-001 -557-

providing on its own system.”888 They assert that under the Commission’s existing 

reciprocity requirement, a non-public utility transmission provider is not obligated to 

provide such service, because a public utility transmission provider is not obligated to 

refuse to provide service if a non-public utility transmission provider does not 

reciprocate. Rather, they point out that there are three alternatives available to non-public 

utilities to meet the reciprocity requirement, including obtaining a waiver from, or 

entering into a bilateral agreement with, the public utility transmission provider from 

which the non-public utility seeks service, and that providing service under a safe harbor 

tariff is only one alternative. National Rural Electric Coops state that only a few nonpublic utilities have Commission-approved reciprocity tariffs and significant disputes 

could arise from the unintentional language in Order No. 1000. They state that 

clarification would help to minimize controversies over the scope of non-public utilities’ 

obligations with respect to regional planning and cost allocation, and would be consistent 

with the Commission’s statement that it is not proposing any changes to the reciprocity 

provision of the pro forma OATT or any other document.

757. Sacramento Municipal Utility District also states that by asserting that all nonpublic utilities must abide by Order No. 1000’s transmission planning and cost allocation 

 888 National Rural Electric Coops at 5-6 (quoting Order No. 1000, FERC Stats. & 

Regs. ¶ 31,323 at P 819).
Docket No. RM10-23-001 -558-

provisions if they take open access service, the Commission both: (1) eviscerates the 

waiver option expressly contemplated under Order Nos. 888 and 890 and (2) creates an 

automatic trigger directly at variance with the principle that non-public utilities must 

reciprocate if asked to do so. Sacramento Municipal Utility District points out that Order 

Nos. 888 and 890 unambiguously require safe harbor candidates to adopt tariffs that 

match or exceed the terms of the pro forma OATT. It argues, however, that the 

Commission’s interpretation in Order No. 1000 that non-public utilities without safe 

harbor tariffs that take service under open access tariffs also are automatically bound to 

follow the transmission planning and cost allocation provisions of Order No. 1000 

improperly conflates the safe harbor tariff provisions found in Order Nos. 888 and 890 

since markedly different reciprocity requirements apply when a non-public utility does 

not employ a safe harbor tariff. 

758. Sacramento Municipal Utility District further argues that the Commission’s 

longstanding policy has been that reciprocity under Order Nos. 888 and 890 only 

obligates the non-public utility to provide transmission service to individual public utility 

transmission providers requesting reciprocity as a condition of obtaining their 

transmission service if a non-public utility has not sought a “safe-harbor” tariff.889 

Sacramento Municipal Utility District argues that the actual provisions of Order Nos. 888 

 889 Sacramento Municipal Utility District at 3. 
Docket No. RM10-23-001 -559-

and 890 make clear that a reciprocity obligation is not automatic, is purely bilateral and 

applies only to the transmission provider that asks the non-public utility to reciprocate.890 

Thus, Sacramento Municipal Utility District states that the Commission’s determination 

that the act of taking service from a public utility with a regional cost allocation plan in 

its open access tariff automatically triggers the non-public utility’s reciprocity obligation 

under Order Nos. 888 and 890 constitutes an arbitrary and unexplained departure from 

the policies established in those orders.891 

759. Bonneville Power further argues that the Commission is inappropriately 

attempting to regulate Bonneville Power and other non-public utility transmission 

providers under section 206 of the FPA. In support, Bonneville Power asserts that the 

Commission’s action is more extreme than its attempt to impose refund liability on nonpublic utilities in, for example, BPA v. FERC.

892 Bonneville Power contends that in that 

case, the court held the Commission lacked refund authority over non-public utilities that 

 890 Sacramento Municipal Utility District at 18 (citing Promoting Wholesale 

Competition Through Open Access Non-discriminatory Transmission Serv. By Pub. 

Utils; Recovery of Stranded Costs by Pub. Utils. And Transmitting Utils., Order No. 888-

A, FERC Stats. & Regs. ¶ 31,048, at P 30, 180-81(1997)). 

891 Sacramento Municipal Utility District at 3 (citing FCC v. Fox Television 

Stations, Inc., 129 S. Ct. 1800, 1811 (2009); Greater Boston Television Corp. v. FCC, 

444 F.2d 841, 952 (D.C. Cir. 1970), cert. denied, 403 U.S. 923 (1971)).

892 Bonneville Power at 17 (citing BPA v. FERC, 422 F.3d 908, 921 (9th Cir. 

2005)).
Docket No. RM10-23-001 -560-

participated in a power market established by a public utility. Bonneville Power argues 

that the Commission is similarly imposing cost responsibility on non-public utilities 

under section 206 absent statutory authority to do so. Bonneville Power contends that if 

the Commission denies clarification that the regional planning process determination 

would not be binding on Bonneville Power and that instead, it and transmission 

developers could use the cost allocation analysis as input to their negotiations and other 

required statutory processes, then the Commission is directly regulating Bonneville 

Power by not allowing Bonneville Power to follow its own statutory authority in 

implementing cost allocation in place of the Commission’s policy adopted under section 

206, which the Commission cannot do.

760. Sacramento Municipal Utility District argues that the Commission lacks the 

authority to mandate regional transmission planning and therefore it cannot attach an 

obligation to accept the cost allocation agreement negotiated under a regional 

transmission planning process that the non-public utility was not mandated to join. 

Sacramento Municipal Utility District therefore contends that since non-public utilities 

under section 201(f) are not subject to section 205 and 206, they cannot be required as a 

condition of reciprocity to accept cost allocation agreements that the Commission has no 

authority to impose even on public utilities. 

761. Sacramento Municipal Utility District states that when a non-public utility takes 

service from a jurisdictional public utility, it will pay a tariff rate approved by the 
Docket No. RM10-23-001 -561-

Commission, and a reciprocity provision is simply unnecessary to ensure proper cost 

recovery. Sacramento Municipal Utility District argues that if the non-public utility takes 

no service from a transmission provider that has constructed a new facility approved by a 

regional transmission planning body, and the costs of that facility are not properly 

included in the rates of other transmission providers from whom the non-public utility 

does take service, the reciprocity provision should be completely inapplicable.

762. Moreover, Sacramento Municipal Utility District argues that cost allocation is not 

a transmission service so that a non-public utility requesting only transmission service 

can be deemed to have reciprocated only by participating in regional cost allocation. 

Similarly, Bonneville Power contends that the Commission should not condition a nonjurisdictional transmitting utility’s ability to receive transmission service from a public 

utility on the non-jurisdictional utility’s inclusion of Order No. 1000’s planning and cost 

allocation reforms in its own tariff because the provisions of Order No. 1000 go well 

beyond the basic provision of transmission service and are not the type of provisions that 

reasonably fall within the reciprocity construct. 

763. Edison Electric Institute seeks clarification that section 6 of the OATT, which 

codifies the reciprocity requirement, enables a public utility to refuse transmission service 

to unregulated transmitting utilities that refuse to participate in regional transmission 

planning and cost allocation processes. Furthermore, Edison Electric Institute seeks 

clarification that, to satisfy the reciprocity requirements, unregulated transmitting utilities 
Docket No. RM10-23-001 -562-

must fulfill each of the compliance requirements imposed on public utilities. If 

unregulated transmitting utilities do not, then Edison Electric Institute argues that the 

Commission should clarify that they have failed to offer the “comparable” service 

required under section 6 of the OATT. 

764. Large Public Power Council seeks clarification that the Commission did not intend 

that it would enforce reciprocity tariff provisions itself. Large Public Power Council 

states that if the Commission does intend to enforce the reciprocity provisions itself, 

Large Public Power Council seeks rehearing. Large Public Power Council argues that to 

date, the Commission has not intimated that it has authority to enforce these provisions 

with respect to a non-public utility, which is consistent with case law finding that a nonpublic utility’s involvement in Commission-jurisdictional service does not authorize the 

Commission to regulate the non-public utility. 

765. Other petitioners argue that the Commission does not have authority under section 

211A to compel a non-public utility transmission provider to participate in planning or 

pay for regional or interregional transmission projects.893 For instance, Large Public 

Power Council asserts that section 211A makes it plain that the Commission’s authority 

is limited to compelling a non-public utility to provide transmission service at rates and 

 893 See, e.g., Large Public Power Council; Sacramento Municipal Utility District; 

and Bonneville Power.
Docket No. RM10-23-001 -563-

on terms and conditions that are essentially inward looking. As such, Large Public Power 

Council contends that the Commission cannot redefine the terms under which service is 

to be provided under section 211A in a manner that would give the Commission broader 

authority than that given by Congress. Accordingly, it states that the Commission does 

not have the authority to compel non-public utilities to contribute to new regional or 

interregional cost allocation mechanisms, or to operate according to Commissionapproved transmission plans directing the level and nature of transmission investment. 

766. Sacramento Municipal Utility District asserts that section 211A of the FPA makes 

clear that the comparability the Commission is empowered to enforce is comparability to 

the transmission services the non-public utility provides to itself, and that if a non-public 

utility chooses not to participate in a regional cost allocation process as part of its service 

to itself, it cannot be compelled to participate or to accept a regional cost allocation plan 

under section 211A. Bonneville Power contends that the Commission is inappropriately 

attempting to indirectly regulate non-public utility transmission providers by suggesting 

that it will use section 211A to obtain their compliance with mandatory cost allocation. 

Sacramento Municipal Utility District and Bonneville Power, therefore, argue that the 

Commission should remove its statement that it will use section 211A against non-public 

utility transmission providers to obtain compliance with Order No. 1000. Sacramento 

Municipal Utility District alternatively urges the Commission to clarify that its 

interpretation is not binding and is without prejudice to the rights of non-public utilities to 
Docket No. RM10-23-001 -564-

challenge such an interpretation in any actual case in which the Commission invokes the 

authority to mandate non-public utility participation in regional planning and cost 

allocation.

767. On the other hand, Edison Electric Institute argues that the Commission erred by 

relying on non-public utility transmission providers to voluntarily participate in regional 

transmission planning and cost allocation processes.894 Edison Electric Institute argues 

that the Commission should have exercised its authority under section 211A to ensure 

that unregulated transmitting utilities comply with the transmission planning and regional 

cost allocation provisions on the same terms and conditions as jurisdictional public 

utilities. Edison Electric Institute also asserts that the Commission has not demonstrated 

or otherwise explained why mandatory action is required in the case of public utility but 

is not required for non-public utility transmission providers. Edison Electric Institute 

asserts that both sets of utilities own transmission facilities, provide transmission service 

to customers, and may currently participate in regional transmission planning processes.

768. Edison Electric Institute asserts that the Commission is authorized through section 

211A to act “by rule” to require unregulated transmitting utilities to remedy 

 894 Edison Electric Institute at 26 (citing Order No. 1000, FERC Stats. & Regs. ¶ 

31,323 at P 815).
Docket No. RM10-23-001 -565-

discriminatory transmission rates and practices.895 Edison Electric Institute states that the 

Commission has recognized that section 211A allows it to require an unregulated 

transmitting utility to provide transmission services on a comparable and not unduly 

discriminatory basis. Edison Electric Institute further states that section 211A contains 

the same “unduly discriminatory or preferential” standard found in section 206. Thus, 

Edison Electric Institute concludes that FPA section 211A, along with section 206, vests 

the Commission with the duty to eliminate undue discrimination and to ensure open 

access to transmission across the entire interstate grid.

769. Edison Electric Institute argues that the Commission’s decision to rely on 

voluntary compliance is ill-founded and inadequate because there is no indication that 

non-jurisdictional utilities will voluntarily comply. It also argues that since Order No. 

888, non-jurisdictional utilities have not fully embraced voluntary compliance with the 

Commission’s open access reforms. Furthermore, Edison Electric Institute argues that 

allowing non-public utilities to participate voluntarily injects uncertainty in transmission 

planning and cost allocation, especially in areas that are predominately served by 

unregulated entities. Edison Electric Institute asserts that participants in regional 

transmission planning and cost allocation processes should not have to wait to know 

whether an unregulated transmitting utility, and potential beneficiary of a transmission 

 895 Edison Electric Institute at 27 (quoting 16 U.S.C. 824j-1(b)).
Docket No. RM10-23-001 -566-

project, is going to be subject to regional cost allocation. Edison Electric Institute adds 

that it also is unclear if, when, and how the Commission will exercise its authority under 

section 211A. Edison Electric Institute asserts that the lack of certainty, layered on to the 

short period for compliance, will undermine confidence in the planning and regional cost 

allocation processes and hinder their development.

770. Edison Electric Institute requests that the Commission clarify and strengthen the 

obligations of unregulated transmitting utilities to facilitate full compliance with regional 

planning and cost allocation provisions, and make clear when and how it will act on a 

case-by-case basis under section 211A. In addition, Edison Electric Institute states that 

the Commission has the authority to direct unregulated transmitting utilities to comply 

with the requirements in Order No. 1000, whether it learns of non-compliance through a 

complaint or on its own motion. Edison Electric Institute argues that failure by the 

Commission to act would be an abdication of its obligation to ensure non-discriminatory 

treatment in transmission service.

3. Commission Determination 

771. In response to petitioners who are concerned that the Commission is modifying the 

scope of the reciprocity requirement under Order Nos. 888 and 890, we clarify that the 

reciprocity requirement remains unchanged. A non-public utility transmission provider 

may continue to satisfy the reciprocity condition in one of three ways. First, it may 

provide service under a tariff that has been approved by the Commission under the 
Docket No. RM10-23-001 -567-

voluntary “safe harbor” provision of the pro forma OATT. A non-public utility 

transmission provider using this alternative submits a reciprocity tariff to the Commission 

seeking a declaratory order that the proposed reciprocity tariff substantially conforms to, 

or is superior to, the pro forma OATT. The non-public utility transmission provider then 

must offer service under its reciprocity tariff to any public utility transmission provider 

whose transmission service the non-public utility transmission provider seeks to use. 

Second, the non-public utility transmission provider may provide service to a public 

utility transmission provider under a bilateral agreement that satisfies its reciprocity 

obligation. Finally, the non-public utility transmission provider may seek a waiver of the 

reciprocity condition from the public utility transmission provider.896 

772. We affirm the Commission’s determination in Order No. 1000 that to maintain a 

reciprocity tariff under the voluntary “safe harbor” provision, a non-public utility 

transmission provider must ensure that the provisions of that tariff substantially conform, 

or are superior, to the pro forma OATT and its Attachment K as these have been revised 

by Order No. 1000.897 As such, if a non-public utility transmission provider wishes to 

 896 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 799 & n.574 (citing Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 at P 163 (citing Order No. 888-A, FERC Stats. & 

Regs. ¶ 31,048 at 30,285-86)). 

897 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 815 and Appendix C: Pro 

Forma Open Access Transmission Tariff.
Docket No. RM10-23-001 -568-

maintain its safe harbor tariff, it will need to ensure that it addresses Order No. 1000’s 

transmission planning and cost allocation reforms, so that it continues to substantially 

conform, or be superior, to the pro forma OATT. 

773. As we note above, the other two ways of satisfying the reciprocity requirement 

also remain intact. For example, a non-public utility transmission provider seeking 

service from a public utility transmission provider may seek to enter into a bilateral 

agreement with the public utility transmission provider that addresses that public utility 

transmission provider’s desire for reciprocity. In such case, a public utility transmission 

provider may agree to provide service to a non-public utility transmission provider 

without requiring that non-public utility transmission provider to provide reciprocal 

service under terms and conditions that are necessarily substantially conforming with, or 

superior to, the pro forma OATT, which includes the transmission planning and cost 

allocation reforms in Order No. 1000. With respect to such bilateral agreements, the 

Commission in Order No. 888-A stated that it “must leave these agreements to case-bycase determinations.”898 In doing so, the Commission stated that the terms and 

conditions that “may be necessary for a non-public utility to provide reciprocal service to 

the public utility in a bilateral agreement is necessarily a fact-specific matter not 

 898 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,289. 
Docket No. RM10-23-001 -569-

susceptible to resolution in a generic rulemaking proceeding.”899 As such, we deny 

Edison Electric Institute’s request for generic clarification that section 6 of the pro forma 

OATT, which codifies the reciprocity requirement, would allow a public utility 

transmission provider to refuse service to a non-public utility transmission provider that 

refused to enroll in the regional transmission planning and cost allocation processes. 

However, we note that in Order No. 888-A, the Commission also made clear that “a 

public utility may refuse to provide open access transmission service to a non-public 

utility if its denial is based on a good faith assertion that the non-public utility has not met 

the Commission’s reciprocity requirements.”900 While we will continue to address such 

matters on a case-by-case basis consistent with Order No. 888-A, we nevertheless note 

our finding in Order No. 1000 that those that “take advantage of open access, including 

improved transmission planning and cost allocation, should be expected to follow the 

 899 Id.

900 Id. This approach is also consistent with Order No. 890 where the Commission 

stated that “[u]nder the reciprocity provision in section 6 of the pro forma OATT, if a 

public utility seeks transmission service from a non-public utility to which it provides 

open access transmission service, the non-public utility that owns, controls, or operates 

transmission facilities must provide comparable transmission service that it is capable of 

providing on its own system. Under the pro forma OATT, a public utility may refuse to 

provide open access transmission service to a non-public utility if the non-public utility 

refuses to reciprocate.” Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 163.
Docket No. RM10-23-001 -570-

same requirements as public utility transmission providers.”901 Finally, a public utility 

transmission provider remains free to waive any reciprocity requirement for a non-public 

utility transmission provider that seeks service from it. 

774. We further clarify in response to National Rural Electric Coops that, in the 

absence of a safe harbor tariff, a non-public utility transmission provider’s obligation to a 

public utility transmission provider to provide a comparable transmission service that it is 

capable of providing on its own system begins when that public utility transmission 

provider requests comparable reciprocal service from the non-public utility transmission 

provider.902 We also clarify for Large Public Power Council that the Commission did not 

intend that it would enforce reciprocity tariff provisions sua sponte, except insofar as the 

Commission permits a public utility transmission provider to refuse to offer open access 

transmission service to that non-public utility transmission provider, in accordance with 

Order No. 888. 

775. Because the reciprocity provisions of Order Nos. 888, 890, and 1000 do not 

impose any requirement on non-public utility transmission providers, we reject 

Bonneville Power’s and Sacramento Municipal Utility District’s arguments that the 

Commission is attempting to regulate non-public utility transmission providers. As the 

 901 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 818. 

902 Id. P 819 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 163).
Docket No. RM10-23-001 -571-

Commission stated in Order No. 1000, non-public utility transmission providers are free 

to decide whether they will seek transmission service that is subject to the Commission’s 

jurisdiction, and the Commission does not exercise jurisdiction over them when it 

determines the terms under which public utility transmission providers must provide that 

transmission service.903 As such, the reciprocity provision of Order No. 1000 does not 

require non-public utility transmission providers to comply with the Order No. 1000 

transmission planning and cost allocation reforms. In addition, as explained above in the 

discussion of our legal authority to implement Order No. 1000’s transmission planning 

reforms, we disagree with Sacramento Municipal Utility District’s contention that the 

Commission lacks the authority to mandate regional transmission planning for public 

utility transmission providers.904 

776. In response to Sacramento Municipal Utility District’s concern that a reciprocity 

provision is “unnecessary to ensure proper cost recovery,”905 and Bonneville Power’s and 

Sacramento Municipal Utility District’s concerns that the transmission planning and cost 

allocation reforms should be outside the reciprocity construct, we disagree. Any nonpublic utility transmission provider that takes transmission service from a public utility 

 903 Id.

904 See discussion supra at section III.A.1.b.ii.

905 Sacramento Municipal Utility District at 20.
Docket No. RM10-23-001 -572-

transmission provider after implementation of Order No. 1000 is likely to benefit from 

the new OATT provisions of the public utility transmission providers in that region 

providing for improved regional transmission planning and for regional cost allocation 

commensurate with benefits for selected facilities, as provided in Order No. 1000. We 

therefore in Order No. 1000 applied the reciprocity provisions of Order Nos. 888 and 890 

to provide that it is within the Commission’s discretion to allow a public utility 

transmission provider to refuse to offer open access transmission service to any nonpublic utility transmission provider that does not provide comparable reciprocal 

transmission service insofar as it is capable of doing so, including regional planning and 

cost allocation. However, we reiterate a clarification made above that it is only when a 

non-public utility transmission provider actually makes the choice to become part of a 

transmission planning region by enrolling in that region that it would be subject to the 

regional and interregional cost allocation methods for that region.906 

777. In response to Bonneville Power’s and Sacramento Municipal Utility District’s 

contention that certain provisions of Order No. 1000, such as those relating to cost 

allocation, go beyond the provision of transmission service and thus should not be 

incorporated in the Commission’s reciprocity condition, we reiterate that both 

transmission planning and cost allocation are integral and essential components of the 

 906 See discussion supra at section III.A.2.c.
Docket No. RM10-23-001 -573-

provision of transmission service. The transmission planning and cost allocation reforms 

adopted in Order No. 1000 are intended to facilitate the development of a robust 

transmission system capable of providing improved open access transmission service and 

to help ensure that transmission rates are just and reasonable and not unduly 

discriminatory or preferential. 

778. We decline to address petitioners’ arguments concerning the scope of our 

authority under FPA section 211A in this proceeding because the Commission did not act 

under FPA section 211A in Order No. 1000.907 As the Commission stated in Order No. 

1000, the success of the transmission planning process set forth therein will be enhanced 

if all transmission owners participate. The Commission further stated that non-public 

utility transmission providers will benefit greatly from the improved transmission 

planning and cost allocation processes required for public utility transmission providers 

because a well-planned grid is more reliable and provides more available, less congested 

paths for the transmission of electric power in interstate commerce.908

VI. Information Collection Statement

779. The Office of Management and Budget (OMB) requires that OMB approve 

certain information collection and data retention requirements imposed by agency 

 907 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 821.

908 Id. P 818.
Docket No. RM10-23-001 -574-

rules.909 Upon approval of a collection(s) of information, OMB will assign an OMB 

control number and an expiration date. Respondents subject to the filing requirements of 

a rule will not be penalized for failing to respond to these collections of information 

unless the collections of information display a valid OMB control number.

780. Previously, the Commission submitted to OMB the information collection 

requirements arising from Order No. 1000 and OMB approved those requirements. In 

this order, the Commission is making no substantive changes to those requirements, but 

has provided clarifications that require public utility transmission providers, and 

transmission developers, to collect additional information. Therefore, the Commission 

finds it necessary to make a formal submission to OMB for review and approval under 

section 3507(d) of the Paperwork Reduction Act of 1995.910

781. The burden estimates in this order on rehearing and clarification of Order No. 

1000 represent the incremental burden changes related only to the new and revised 

requirements set forth in this order. It also should be noted that the burden estimates are 

averages for all of the filers. 

Burden Estimate and Information Collection Costs: The estimated Public Reporting 

burden and cost for the new and revised requirements contained in this order follow.

 909 5 C.F.R. 1320.11(b).

910 44 U.S.C. 3507(d).
Docket No. RM10-23-001 -575-

Cost to Comply:

FERC-917 - New and Revised 

Reporting Requirements in 

Order 1000-A 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

Transmission Providers (TP) 

develop & maintain enrollment 

process defining how entities make 

choice to become part of trans. 

planning region; and include (& 

maintain) in OATT a list of all pub. 

& non-pub. utility trans. providers 

enrolled as TP in planning region 132 1

2 in Year 

1; 1 in 

Yrs. 2 & 3 264 132

Transmission Developers (TD) 

submit development schedule (if 

selected in regional plan for cost 

allocation) 140 1

4 (each in 

Yrs. 1-3) 560 560

TP describe in OATT how regional 

trans. planning process gives 

stakeholders chance to participate & 

how stakeholders & TD can 

propose interregional trans. 

facilities for TP in neighboring 

region to evaluate jointly 132 1

5 in Year 

1; 0.5 in 

Yrs. 2&3 660 66

To the extent that a TP considers 

either cost containment or cost 

recovery provisions as part of cost 

allocat. method for regional or 

interregional facility, such 

provisions may be included in its 

compliance filing 132 1

18 in Year 

1; 1 in 

Yrs. 2&3 2,376 132

Total Estimated Additional 

Burden Hours, for FERC-917 due 

to Order 1000-A in RM10-23 3,860 890
Docket No. RM10-23-001 -576-

Year 1: $440,040 [3,860 hours X $114 per hour911]

Subsequent Years: $101,460 [890 hours X $114 per hour]

Title: FERC-917

Action: Clarification to Collection.

OMB Control No: 1902-0233.

Respondents: Transmission Developers and Public Utility Transmission Providers. An 

RTO or ISO also may file some materials on behalf of its members.

Frequency of Responses: Initial filing and subsequent filings. 

Necessity of the Information: 

782. Building on the reforms in Order No. 890, the Federal Energy Regulatory 

Commission provides these clarifications to the amendments to the pro forma OATT to 

correct certain deficiencies in the transmission planning and cost allocation requirements 

for public utility transmission providers adopted in Order No. 1000. The purpose of 

Order No. 1000 is to strengthen the pro forma OATT, so that the transmission grid can 

better support wholesale power markets and ensure that Commission-jurisdictional 

services are provided at rates, terms, and conditions that are just and reasonable and not 

unduly discriminatory or preferential. We expect to achieve this goal through Order No. 

 911 The estimated cost of $114 an hour is the average of the hourly costs of: 

attorney ($200), consultant ($150), technical ($80), and administrative support ($25).
Docket No. RM10-23-001 -577-

1000 by reforming electric transmission planning requirements and establishing a closer 

link between cost allocation and regional transmission planning processes. 

783. Interested persons may obtain information on reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 

Comments concerning the collection of information and the associated burden 

estimate(s), may also be sent to the Office of Information and Regulatory Affairs, Office 

of Management and Budget, 725 17th Street, NW, Washington, DC 20503 [Attention: 

Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4638, 

fax (202) 395-7285]. Due to security concerns, comments should be sent electronically

to the following e-mail address: oira_submission@omb.eop.gov. Comments submitted 

to OMB should include OMB Control No. 1902-0233 and Docket No. RM10-23-001.

VII. Document Availability

784. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.
Docket No. RM10-23-001 -578-

785. From the Commission’s Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number excluding the last three digits of this 

document in the docket number field.

786. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-

208-3676) or e-mail at ferconlinesupport@ferc.gov, or the Public Reference Room at 

(202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

VIII. Effective Date and Congressional Notification

787. Changes to Order No. 1000 made in this order on rehearing and clarification will 

be effective on [insert 30 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 on rehearing and clarification 

of Order No. 1000 is not a “major rule” as defined in section 351 of the Small Business 

Regulatory Enforcement Fairness Act of 1996.

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM10-23-001 -579-

Note: The following appendices will not be published in the Code of Federal Regulations.

Appendix A: Abbreviated Names of Petitioners

Abbreviation Petitioner Names

Ad Hoc Coalition of 

Southeastern Utilities

Central Electric Power Cooperative, Inc.; 

Dalton Utilities; Georgia Transmission 

Corporation; JEA; MEAG Power; Orlando 

Utilities Commission; Progress Energy Service 

Company, LLC (on behalf of Progress Energy 

Carolinas, Inc. and Progress Energy Florida, 

Inc.); South Carolina Electric & Gas Company; 

South Carolina Public Service Authority 

(Santee Cooper); and Southern Company 

Services, Inc. (on behalf of Alabama Power 

Company, Georgia Power Company, Gulf 

Power Company, Mississippi Power Company, 

and Southern Power Company)

AEP American Electric Power Service Corporation

Alabama PSC Alabama Public Service Commission

Ameren Ameren Services Company

American Transmission American Transmission Company LLC

APPA American Public Power Association

Arizona Cooperative and 

Southwestern Transmission

Arizona Electric Power Cooperative, Inc. and 

Southwest Transmission Cooperative, Inc.

AWEA American Wind Energy Association

Baltimore Gas & Electric Baltimore Gas & Electric Company

Bonneville Power Bonneville Power Administration

California ISO California Independent System Operator 
Docket No. RM10-23-001 -580-

Abbreviation Petitioner Names

Corporation

California State Water Project California Department of Water Resources 

State Water Project

Coalition for Fair 

Transmission Policy

CMS Energy Corporation; Consolidated 

Edison; DTE Energy Company; Progress 

Energy, Inc.; Public Service Enterprise Group; 

SCANA Corporation; Southern Company912*

Dayton Power and Light Dayton Power and Light Company (The)

Duke Duke Energy Corporation

Edison Electric Institute Edison Electric Institute

ELCON, AF&PA, and the 

Associated Industrial Groups

Electricity Consumers Resource Council, 

American Forest and Paper Association, 

Electricity Consumers Resource Council; 

American Chemistry Council; Association of 

Businesses Advocating Tariff Equity; Carolina 

Utility Customers Association; Coalition of 

Midwest Transmission Customers; Florida 

Industrial Power Users Group; Georgia 

Industrial Group-Electric; Industrial Energy 

Users – Ohio; Oklahoma Industrial Energy 

Consumers; PJM Industrial Customer 

Coalition; West Virginia Energy Users Group; 

and Wisconsin Industrial Energy Group

Energy Future Coalition 

Group

Energy Future Coalition; American Wind 

Energy Association; Center for Energy 

Efficiency and Renewable Technologies; 

Center for Rural Affairs; Climate and Energy 

 912 A “*” indicates that the composition of this group has changed since the Final 

Rule proceeding.
Docket No. RM10-23-001 -581-

Abbreviation Petitioner Names

Project; Denali Energy Inc.; Fresh Energy; 

Gradient Resources, Inc.; Iberdrola 

Renewables; Interwest Energy Alliance; 

Natural Resources Defense Council; Project for 

Sustainable FERC Energy Policy; Solar Energy 

Industries Association; The Stella Group, Ltd.; 

Union of Concerned Scientists; Western Grid 

Group; Wind on the Wires; and WIRES* 

FirstEnergy Service Company FirstEnergy Service Company, on behalf of 

FirstEnergy Companies: Ohio Edison 

Company; Pennsylvania Power Company; The 

Cleveland Electric Illuminating Company; The 

Toledo Edison Company; American 

Transmission Systems, Incorporated; Jersey 

Central Power & Light Company; Metropolitan 

Edison Company; and Pennsylvania Electric 

Company, and FirstEnergy Solutions Corp. and 

their respective electric utility subsidiaries and 

affiliates

Florida PSC Florida Public Service Commission

Georgia PSC Georgia Public Service Commission

Illinois Commerce 

Commission

Illinois Commerce Commission

ITC Companies International Transmission Company; 

Michigan Electric Transmission Company, 

LLC; ITC Midwest LLC; ITC Great Plains, 

LLC; and Green Power Express LP

Joint Petitioners American Electric Power Corp.; AWEA; 

Iberdrola Renewables; ITC Holdings Corp.; 

NextEra Energy, Inc.; MidAmerican Energy

Kentucky PSC Kentucky Public Service Commission
Docket No. RM10-23-001 -582-

Abbreviation Petitioner Names

Large Public Power Council Austin Energy; Chelan County Public Utility 

District No. 1; Clark Public Utilities; Colorado 

Springs Utilities; CPS Energy (San Antonio); 

ElectriCities of North Carolina; Grant County 

Public Utility District; IID Energy (Imperial 

Irrigation District); JEA (Jacksonville, FL); 

Long Island Power Authority; Los

Angeles Department of Water and Power; 

Lower Colorado River Authority; MEAG 

Power, Nebraska Public Power District; New 

York Power Authority; Omaha Public Power 

District; Orlando Utilities Commission; Platte 

River Power Authority; Puerto Rico Electric 

Power Authority; Sacramento Municipal Utility 

District; Salt River Project; Santee Cooper; 

Seattle City Light; Snohomish County Public 

Utility District No. 1; and Tacoma Public 

Utilities*

Long Island Power Authority Long Island Power Authority and LIPA

LS Power LS Power Transmission, LLC

MEAG Power MEAG Power 

MISO Midwest Independent System Transmission 

Operator, Inc.

MISO Transmission Owners 

Group 1

The Midwest ISO Transmission Owners for this 

filing consist of: Ameren Services Company, as 

agent for Union Electric Company d/b/a Ameren 

Missouri, Ameren Illinois Company d/b/a 

Ameren Illinois and Ameren Transmission 

Company of Illinois; American Transmission 

Company LLC (“ATC”); City Water, Light & 

Power (Springfield, IL); Dairyland Power 

Cooperative; Great River Energy; Indianapolis 

Power & Light Company; MidAmerican Energy 

Company; Minnesota Power (and its subsidiary 
Docket No. RM10-23-001 -583-

Abbreviation Petitioner Names

Superior Water, L&P); Montana- Dakota 

Utilities Co.; Northern Indiana Public Service 

Company; Northern States Power Company, a 

Minnesota corporation, and Northern States 

Power Company, a Wisconsin corporation, 

subsidiaries of Xcel Energy Inc.; Northwestern 

Wisconsin Electric Company; Otter Tail Power 

Company; Southern Indiana Gas & Electric 

Company (d/b/a Vectren Energy Delivery of 

Indiana); Southern Minnesota Municipal Power 

Agency; and Wolverine Power Supply 

Cooperative, Inc.

MISO Transmission Owners 

Group 2

The Midwest ISO Transmission Owners for 

this filing consist of: Ameren Services 

Company, as agent for Union Electric 

Company d/b/a Ameren Missouri, Ameren 

Illinois Company d/b/a Ameren Illinois and 

Ameren Transmission Company of Illinois; 

City Water, Light & Power (Springfield, IL); 

Dairyland Power Cooperative; Great River 

Energy; Hoosier Energy Rural Electric 

Cooperative, Inc.; Indianapolis Power & Light 

Company; MidAmerican Energy Company; 

Minnesota Power (and its subsidiary Superior 

Water, L&P); Montana-Dakota Utilities Co.; 

Northern Indiana Public Service Company; 

Northern States Power Company, a Minnesota 

corporation, and Northern States Power 

Company, a Wisconsin corporation, 

subsidiaries of Xcel Energy Inc.; Northwestern 

Wisconsin Electric Company; Otter Tail Power 

Company; Southern Illinois Power 

Cooperative; Southern Indiana Gas & Electric 

Company (d/b/a Vectren Energy Delivery of 

Indiana); Southern Minnesota Municipal Power 

Agency; and Wolverine Power Supply 

Cooperative, Inc. 
Docket No. RM10-23-001 -584-

Abbreviation Petitioner Names

MISO Northeast MISO Northeast Transmission Customers of 

Consumers

NARUC National Association of Regulatory Utility 

Commissioners

National Rural Electric Coops National Rural Electric Cooperative 

Association

NV Energy Nevada Power Company and Sierra Pacific 

Power Company

New York ISO New York Independent System Operator, Inc.

New York PSC New York State Public Service Commission

New York Transmission 

Owners

Central Hudson Gas & Electric Corporation; 

Consolidated Edison Company of New York, 

Inc.; New York Power Authority; Long Island 

Power Authority; New York State Electric & 

Gas Corporation; and Niagara Mohawk Power 

Corporation; Orange and Rockland Utilities, 

Inc.; and Rochester Gas and Electric 

Corporation

NextEra NextEra Energy, Inc.

North Carolina Agencies North Carolina Utilities Commission and 

Public Staff of the North Carolina Utilities 

Commission

Northern Tier Transmission 

Group

Northern Tier Transmission Group

Oklahoma Gas and Electric 

Company

Oklahoma Gas and Electric Company

PPL Companies PPL Electric Utilities Corporation; Lower 

Mount Bethel Energy, LLC; PPL Brunner 

Island, LLC; PPL Holtwood, LLC; PPL 
Docket No. RM10-23-001 -585-

Abbreviation Petitioner Names

Martins Creek, LLC; PPL Montour, LLC; PPL

Susquehanna, LLC; PPL University Park, LLC; 

PPL EnergyPlus, LLC; PPL GreatWorks, LLC; 

PPL Maine, LLC; PPL Wallingford Energy, 

LLC; PPL New Jersey Solar, LLC; PPL New 

Jersey Biogas, LLC; PPL Renewable Energy,

LLC; PPL Montana, LLC; PPL Colstrip I, 

LLC; PPL Colstrip II, LLC; Louisville Gas and 

Electric Company; Kentucky Utilities 

Company; and LG&E Energy Marketing LLC*

PSEG Companies Public Service Electric and Gas Company; 

PSEG Power LLC; and PSEG Energy 

Resources & Trade LLC

Sacramento Municipal Utility 

District

Sacramento Municipal Utility District

South Carolina 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

Sponsoring PJM 

Transmission Owners

Certain Sponsoring PJM Transmission Owners 

(American Transmission Systems, 

Incorporated; Jersey Central Power & Light 

Company; Metropolitan Edison Company; 

Monongahela Power Company; Pennsylvania 

Electric Company; The Potomac Edison 

Company; Trans-Allegheny Interstate Line 

Company; and West Penn Power Company 

(collectively, the FirstEnergy Companies); 

Baltimore Gas and Electric Company; The 

Dayton Power and Light Company; Duquesne 

Light Company; Public Service Electric and 
Docket No. RM10-23-001 -586-

Abbreviation Petitioner Names

Gas Company; PSEG Power LLC and PSEG 

Energy Resources & Trade LLC (collectively, 

PSEG Companies); and Virginia Electric and 

Power Company)

Sunflower, Mid-Kansas and 

Western Farmers

Sunflower Electric Power Corporation and 

Mid-Kansas Electric Company, LLC and 

Western Farmers Electric Cooperative 

Transmission Access Policy 

Study Group

Transmission Access Policy Study Group

Transmission Dependent 

Utility Systems

Arkansas Electric Cooperative Corporation; 

Golden Spread Electric Cooperative, Inc.; 

Kansas Electric Power Cooperative, Inc.; North 

Carolina Electric Membership Corporation; and 

Seminole Electric Cooperative, Inc.; and 

PowerSouth Energy Cooperative*

Vermont Department of 

Public Service and the 

Vermont Public Service 

Board

Vermont Department of Public Service and the 

Vermont Public Service Board

Western Independent 

Transmission Group

Western Independent Transmission Group

WIRES Working Group for Investment in Reliable and 

Economic Electric Systems

Wisconsin PSC Public Service Commission of Wisconsin

Xcel Xcel Energy Services Inc.
Docket No. RM10-23-001 -587-

Appendix B: Pro Forma Open Access Transmission Tariff

Pro Forma OATT

ATTACHMENT K

Transmission Planning Process

Local Transmission Planning

The Transmission Provider shall establish a coordinated, open and transparent planning 

process with its Network and Firm Point-to-Point Transmission Customers and other 

interested parties to ensure that the Transmission System is planned to meet the needs of 

both the Transmission Provider and its Network and Firm Point-to-Point Transmission 

Customers on a comparable and not unduly discriminatory basis. The Transmission 

Provider’s coordinated, open and transparent planning process shall be provided as an 

attachment to the Transmission Provider’s Tariff. 

The Transmission Provider’s planning process shall satisfy the following nine principles, 

as defined in Order No. 890: coordination, openness, transparency, information 

exchange, comparability, dispute resolution, regional participation, economic planning 

studies, and cost allocation for new projects. The planning process also shall include the 

procedures and mechanisms for considering transmission needs driven by Public Policy 
Docket No. RM10-23-001 -588-

Requirements consistent with Order No. 1000. The planning process also shall provide a 

mechanism for the recovery and allocation of planning costs consistent with Order No. 

890. 

The description of the Transmission Provider’s planning process must include sufficient 

detail to enable Transmission Customers to understand:

(i) The process for consulting with customers;

(ii) The notice procedures and anticipated frequency of meetings;

(iii) The methodology, criteria, and processes used to develop a transmission plan;

(iv) The method of disclosure of criteria, assumptions and data underlying a 

transmission plan;

(v) The obligations of and methods for Transmission Customers to submit data to the 

Transmission Provider;

(vi) The dispute resolution process;

(vii) The Transmission Provider’s study procedures for economic upgrades to address 

congestion or the integration of new resources; 

(viii) The Transmission Provider’s procedures and mechanisms for considering 

transmission needs driven by Public Policy Requirements, consistent with Order 

No. 1000; and
Docket No. RM10-23-001 -589-

(ix) The relevant cost allocation method or methods.

Regional Transmission Planning

The Transmission Provider shall participate in a regional transmission planning process 

through which transmission facilities and non-transmission alternatives may be proposed 

and evaluated. The regional transmission planning process also shall develop a regional 

transmission plan that identifies the transmission facilities necessary to meet the needs of 

transmission providers and transmission customers in the transmission planning region. 

The regional transmission planning process must be consistent with the provision of 

Commission-jurisdictional services at rates, terms and conditions that are just and 

reasonable and not unduly discriminatory or preferential, as described in Order No. 1000. 

The regional transmission planning process shall be described in an attachment to the 

Transmission Provider’s Tariff. 

The Transmission Provider’s regional transmission planning process shall satisfy the 

following seven principles, as set out and explained in Order Nos. 890 and 1000: 

coordination, openness, transparency, information exchange, comparability, dispute 

resolution, and economic planning studies. The regional transmission planning process 

also shall include the procedures and mechanisms for considering transmission needs 
Docket No. RM10-23-001 -590-

driven by Public Policy Requirements, consistent with Order No. 1000. The regional 

transmission planning process shall provide a mechanism for the recovery and allocation 

of planning costs consistent with Order No. 890.

The regional transmission planning process shall include a clear enrollment process for 

public and non-public utility transmission providers that make the choice to become part 

of a transmission planning region. The regional transmission planning process shall be 

clear that enrollment will subject enrollees to cost allocation if they are found to be 

beneficiaries of new transmission facilities selected in the regional transmission plan for 

purposes of cost allocation. Each Transmission Provider shall maintain a list of enrolled 

entities in the Transmission Provider’s Tariff.

Nothing in the regional transmission planning process shall include an unduly 

discriminatory or preferential process for transmission project submission and selection. 

The description of the regional transmission planning process must include sufficient 

detail to enable Transmission Customers to understand:

(i) The process for enrollment in the regional transmission planning process;

(ii) The process for consulting with customers;

(iii) The notice procedures and anticipated frequency of meetings;
Docket No. RM10-23-001 -591-

(iv) The methodology, criteria, and processes used to develop a transmission plan;

(v) The method of disclosure of criteria, assumptions and data underlying transmission 

plan;

(vi) The obligations of and methods for transmission customers to submit data;

(vii) Process for submission of data by nonincumbent developers of transmission 

projects that wish to participate in the transmission planning process and seek 

regional cost allocation;

(viii) Process for submission of data by merchant transmission developers that wish to 

participate in the transmission planning process;

(ix) The dispute resolution process;

(x) The study procedures for economic upgrades to address congestion or the 

integration of new resources; 

(xi) The procedures and mechanisms for considering transmission needs driven by 

Public Policy Requirements, consistent with Order No. 1000; and

(xii) The relevant cost allocation method or methods.

The regional transmission planning process must include a cost allocation method or 

methods that satisfy the six regional cost allocation principles set forth in Order No. 

1000. 

Interregional Transmission Coordination
Docket No. RM10-23-001 -592-

The Transmission Provider, through its regional transmission planning process, must 

coordinate with the public utility transmission providers in each neighboring transmission 

planning region within its interconnection to address transmission planning coordination 

issues related to interregional transmission facilities. The interregional transmission 

coordination procedures must include a detailed description of the process for 

coordination between public utility transmission providers in neighboring transmission 

planning regions (i) with respect to each interregional transmission facility that is 

proposed to be located in both transmission planning regions and (ii) to identify possible 

interregional transmission facilities that could address transmission needs more 

efficiently or cost-effectively than separate regional transmission facilities. The 

interregional transmission coordination procedures shall be described in an attachment to 

the Transmission Provider’s Tariff.

The Transmission Provider must ensure that the following requirements are included in 

any applicable interregional transmission coordination procedures:

(1) A commitment to coordinate and share the results of each transmission planning 

region’s regional transmission plans to identify possible interregional transmission 

facilities that could address transmission needs more efficiently or cost-effectively than 
Docket No. RM10-23-001 -593-

separate regional transmission facilities, as well as a procedure for doing so; 

(2) A formal procedure to identify and jointly evaluate transmission facilities that are 

proposed to be located in both transmission planning regions;

(3) An agreement to exchange, at least annually, planning data and information; 

and (4) A commitment to maintain a website or e-mail list for the communication of 

information related to the coordinated planning process.

The Transmission Provider must work with transmission providers located in neighboring 

transmission planning regions to develop a mutually agreeable method or methods for 

allocating between the two transmission planning regions the costs of a new interregional 

transmission facility that is located within both transmission planning regions. Such cost 

allocation method or methods must satisfy the six interregional cost allocation principles 

set forth in Order No. 1000 and must be included in the Transmission Provider’s Tariff.