141 FERC ¶ 61,044

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM10-23-002; Order No. 1000-B]

Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities

(Issued October 18, 2012)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on Rehearing and Clarification.

SUMMARY: The Federal Energy Regulatory Commission affirms its basic 

determinations in Order Nos. 1000 and 1000-A, 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. RM10-23-002 - 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:

Melissa Nimit

Federal Energy Regulatory Commission 

Office of the General Counsel

888 First Street, NE

Washington, DC 20426

(202) 502-6638

Shiv Mani

Federal Energy Regulatory Commission 

Office of Energy Policy and Innovation

888 First Street, NE

Washington, DC 20426

(202) 502-8240

SUPPLEMENTARY INFORMATION:
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. RM10-23-002

ORDER NO. 1000-B

ORDER ON REHEARING AND CLARIFICATION

(Issued October 18, 2012)

TABLE OF CONTENTS

Paragraph Numbers

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

II. Transmission Planning..........................................................................................................5.

A. Regional Transmission Planning......................................................................................5.

1. Role of Section 217(b)(4) of the Federal Power Act....................................................6.

2. Regional Transmission Planning Requirements...........................................................12.

3. Consideration of Transmission Needs Driven by Public Policy Requirements...........28.

B. Nonincumbent Transmission Developers ........................................................................32.

1. Legal Authority.............................................................................................................33.

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

Requirement.......................................................................................................................41.

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

Regional Transmission Plan for Purposes of Cost Allocation ..........................................56.

C. Interregional Transmission Coordination.........................................................................60.

1. Implementation of the Interregional Transmission Coordination Requirements.........61.

III. Cost Allocation....................................................................................................................65.

1. Cost Allocation Principle 2—No Involuntary Allocation of Costs to Nonbeneficiaries.......................................................................................................................67.

IV. Information Collection Statement .......................................................................................73.

V. Document Availability..........................................................................................................74.

VI. Effective Date......................................................................................................................77.

Appendix A: Abbreviated Names of Petitioners
Docket No. RM10-23-002 -2-

I. Introduction

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

allocation requirements established in Order No. 8902 to ensure that the rates, terms and 

conditions of service provided by public utility providers are 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 

 1 Transmission Planning and Cost Allocation by Transmission Owning and 

Operating Public Utilities, Order No. 1000, 76 FR 49842 (Aug. 11, 2011), FERC Stats. 

& Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132 

(2012).

2 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on 

reh’g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 

(2007), order on reh’g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 

123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 74 FR 12540 (Mar. 25, 

2009), 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 74 FR 61511 

(Nov. 25 2009), 129 FERC ¶ 61,126 (2009).
Docket No. RM10-23-002 -3-

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

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

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

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

interregional transmission coordination process required by this Final Rule. Order No. 

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

principles.

3. In Order No. 1000-A, the Commission largely affirmed the reforms adopted in 

Order No. 1000. The Commission concluded that 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 rejected requests to eliminate, 

or substantially modify, the various reforms adopted in Order No. 1000. The 

Commission did however, make a number of clarifications. 

4. Several petitioners have sought further rehearing and clarification of the 

Commission’s determinations in Order No. 1000-A.3

 The Commission largely affirms 

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

in Appendix A. Southwest Power Pool (SPP) filed a request for clarification and/or 

reconsideration of Order No. 1000-A. While SPP denominates its pleading as a request 

for clarification, it is, in fact, a late-filed request for rehearing. Pursuant to section 313(a) 

of the Federal Power Act (FPA), 16 USC 825l(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 SPP’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 

(continued)
Docket No. RM10-23-002 -4-

the determinations reached in Order No. 1000-A, making clarifications to address matters 

raised by petitioners.

II. Transmission Planning

A. Regional Transmission Planning

5. 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.4

 Second, Order No. 1000 adopted reforms under which transmission 

needs driven by Public Policy Requirements are considered in local and regional 

transmission planning processes.5

 The Commission explained that these reforms work 

together to ensure that public utility transmission providers in every transmission 

planning region, in consultation with stakeholders, evaluate proposed alternative 

 

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). Furthermore, we note that the issues raised by SPP are 

similar to those raised by other petitioners, which are summarized and addressed below in 

section II.B.2 of this order.

4 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 68.

5 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. P 2. Order No. 1000-A 

clarified that this included transmission needs driven by local laws or regulations. Order 

No. 1000-A, 139 FERC ¶ 61,132 at P 319.
Docket No. RM10-23-002 -5-

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.6

 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.7

1. Role of Section 217(b)(4) of the Federal Power Act

a. Order No. 1000-A

6. In Order No. 1000-A, the Commission affirmed Order No. 1000’s conclusion that 

the Commission has ample legal authority under the Federal Power Act (FPA) to 

undertake its regional transmission planning reforms. Among other things, Order No. 

1000-A rejected arguments that FPA section 217(b)(4)8 prohibits or otherwise limits the 

Commission’s ability to undertake these reforms.9

 Order No. 1000-A acknowledged

 6 Id.

7 Id. P 68 n.57.

8 16 U.S.C. 824s (2006).

9 Order No. 1000-A, 139 FERC ¶ 61,132 at PP 168-179.
Docket No. RM10-23-002 -6-

claims by some petitioners that Order No. 681,10 which requires transmission 

organizations that are public utilities with organized electricity markets to make available 

long-term firm transmission rights that satisfy certain guidelines, expressly notes a 

preference for load-serving entities.11 Order No. 1000-A found that Order No. 681’s 

priority for load-serving entities in the allocation of long-term firm transmission rights 

supported by existing transmission capacity is not inconsistent with Order No. 1000, 

which addresses planning and cost allocation for new transmission.12 Order No. 1000-A 

also found that the transmission planning reforms will aid, and not hinder, load-serving 

entities in meeting their reasonable transmission needs.13

b. Request for Rehearing

7. Transmission Access Policy Study Group argues that in Order No. 1000-A, the 

Commission suggested for the first time that the preference for load-serving entity longterm rights established in Order No. 681 applies only to existing transmission capacity 

“but not in the broader context of planning new transmission capacity.”14 Transmission 

Access Policy Study Group contends that the Commission erred in suggesting that Order 

 10 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order 

No. 681, FERC Stats. & Regs. ¶ 31,226, order on reh’g, Order No. 681-A, 117 FERC 

¶ 61,201 (2006), order on reh’g, Order No. 681-B, 126 FERC ¶ 61,254 (2009).

11 Order No. 1000-A, 139 FERC ¶ 61,132 at P 171.

12 Id. P 172.

13 Id.

14 Transmission Access Policy Study Group at 12 (quoting Order No. 1000-A, 139 

FERC ¶ 61,132 at P 171).
Docket No. RM10-23-002 -7-

No. 681 does not apply to new transmission facilities, contending that Order No. 681 

extended the preference to be afforded load-serving entities to long-term rights from 

existing capacity to new capacity by providing that “[w]hen...transmission upgrades [that 

are rolled into transmission rates] come into service, the transmission rights that result 

from such investments will be made available as rights from ‘existing capacity.’”15 

Transmission Access Policy Study Group states that this provision had one limited 

exception – where a transmission upgrade is participant-funded.16 It contends that this 

exception is inapplicable to the new transmission facilities at issue in this proceeding, as 

Order No. 1000 specifically ruled that participant funding will not comply with the 

regional or interregional cost allocation principles adopted by the Final Rule.17 

Transmission Access Policy Study Group urges the Commission to clarify that Order 

Nos. 1000 and 1000-A do not alter the scope or applicability of Order No. 681.18 In the 

alternative, it argues that Order No. 1000 should be reversed to the extent that it modifies 

the load-serving entity long-term rights preference established by Order No. 681, by 

limiting that preference to “existing” transmission facilities, rather than extending it to 

new transmission that is not participant-funded.19 

 15 Id. at 13 (quoting Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 211 

(emphasis added)).

16 Id.

17 Id.

18 Id.

19 Id.
Docket No. RM10-23-002 -8-

c. Commission Determination

8. In response to Transmission Access Policy Study Group, we clarify that nothing in 

either Order No. 1000 or Order No. 1000-A is intended in any way to undermine or alter 

the guidelines the Commission instituted in Order No. 681. Order No. 1000’s 

transmission planning reforms are distinct from the Commission’s rulemaking in Order 

No. 681, as we explain below. 

9. Section 1233(a) of the Energy Policy Act of 2005 enacted FPA section 217(b)(4), 

in which the Commission is directed 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.20

10. Section 1233(b) of the Energy Policy Act of 2005 further directed the Commission 

to promulgate a rule on long-term transmission rights in organized markets.21 The 

Commission consequently issued Order No. 681, which adopted guidelines that 

 20 16 U.S.C. 824q(b)(4) (2006).

21 EPAct 2005, Pub. L. No. 109-58, § 1233, 119 Stat. 594, 960 (2005); 16 U.S.C. 

§ 824q (2006)). Section 1233 provides:

FERC RULEMAKING ON LONG-TERM TRANSMISSION 

RIGHTS IN ORGANIZED MARKETS.—Within 1 year after the 

date of enactment of this section and after notice and an opportunity 

for comment, the Commission shall by rule or order, implement 

section 217(b)(4) of the Federal Power Act in Transmission 

Organizations, as defined by that Act with organized electricity 

markets.
Docket No. RM10-23-002 -9-

independent system operators (ISOs) and regional transmission organizations (RTOs) are 

required to follow regarding the availability of long-term firm transmission rights, 

including a guideline providing that load-serving entities “must have a priority over nonload serving entities in the allocation of long-term firm transmission rights that are 

supported by existing capacity.”22

11. As Order No. 1000-A explained, we do not find any inconsistency between Order 

No. 1000 and section 217(b)(4).23 Nor do we find any inconsistency between Order No. 

1000 and Order No. 681. The requirements adopted by the Commission in Order Nos. 

1000 and 1000-A are focused on the planning and cost allocation of new transmission 

facilities, as defined therein. The Commission did not intend its statements in Order No. 

1000-A regarding the planning and cost allocation of certain new transmission facilities 

to alter the requirement in Order No. 681 that “when [transmission upgrades that are 

rolled into transmission rates] . . . come into service, the transmission rights that result 

from such investments will be made available as rights from ‘existing capacity’ . . . . 

Prevailing cost allocation rules will apply.”24 Thus, we clarify for Transmission Access 

Policy Study Group that nothing in Order Nos. 1000 or 1000-A changes the requirements 

of Order No. 681, including the Order No. 681 established preference for load-serving 

 22 Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 325.

23 See Order No. 1000-A, 139 FERC ¶ 61,132 at PP 168-179 (addressing requests 

for rehearing and clarification of Order No. 1000 with respect to the role of section 

217(b)(4)).

24 See Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 211.
Docket No. RM10-23-002 -10-

entities in the allocation of long-term firm transmission rights, and that the Commission 

did not alter the application of Order No. 681 to new transmission facilities that are 

subject to the requirements of Order No. 1000. 

2. Regional Transmission Planning Requirements

a. Order No. 1000-A

12. Order No. 1000-A affirmed Order No. 1000’s conclusion that public utility 

transmission providers must revise their OATTs to provide for a regional transmission 

planning process that produces a regional transmission plan and satisfies Order No. 890’s 

transmission planning principles.25 The Commission explained that Order No. 1000 

requires neither the filing of the regional transmission plan resulting from the regional 

transmission planning process nor the filing of specific applications of cost allocation 

determinations.26 With respect to this latter point, Order No. 1000-A stated that such a 

requirement would be unnecessary to comply with Order No. 1000, noting that Order No. 

1000 requires that public utility transmission providers have an ex ante cost allocation 

method on file with and approved by the Commission. Order No. 1000-A also noted that 

this cost allocation method must 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. 1000.27 

 25 Order No. 1000-A, 139 FERC ¶ 61,132 at PP 263-301.

26 Id. PP 285-286.

27 Id. P 286.
Docket No. RM10-23-002 -11-

Consequently, customers, stakeholders, and others will have “notice” at the time the 

compliance filings are made, when the Commission acts on those filings, and as the 

regional transmission planning process results in the selection of a transmission facility in 

the regional transmission plan for purposes of cost allocation.28 However, consistent 

with the regional flexibility provided in Order No. 1000, Order No. 1000-A also 

concluded that 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.29

13. The Commission further stated in Order No. 1000-A that it will evaluate 

compliance filings to ensure that they comply with Order No. 1000 and that 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.30

b. Request for Rehearing

14. Transmission Access Policy Study Group argues that the Commission should not 

establish a generic rule that, if transmission providers elect not to propose a section 205 

 28 Id.

29 Id.

30 Id. P 287.
Docket No. RM10-23-002 -12-

filing of specific applications of their regional cost allocation, the only means to 

challenge such applications is under section 206.

31 It states that although Order No. 

1000-A nowhere uses the term “formula rate” to describe the rule’s treatment of regional 

cost allocation methodologies, it is creating a filing regimen where the cost allocation 

methodologies will function as just that.

32

15. Therefore, Transmission Access Policy Study Group contends that the 

Commission should require the section 205 filing of project-specific applications of the 

regional cost allocation methodology, or leave it to the compliance filing process to 

determine whether such a filing is required.33 If cost allocation methods are treated as 

formula rates, Transmission Access Policy Study Group maintains that the Commission 

can have no reasonable assurance that cost allocation methodologies will be sufficiently 

specific, grounded in objective criteria, and otherwise adequately constrain utility 

discretion.34 It further asserts that regional cost allocation methodologies, in combination 

with the process for selecting projects for regional cost allocation, will likely rely on 

assumptions and other judgments that undermine predictability.35

 31 Transmission Access Policy Study Group at 3.

32 Id. at 4.

33 Id. at 5.

34 Id. at 6.

35 Id. at 7.
Docket No. RM10-23-002 -13-

16. Transmission Access Policy Study Group argues that sole reliance on section 206 

to challenge specific implementation of a Commission-accepted Order No. 1000 

methodology when the transmission provider has not made a section 205 filing is 

unjustified.36 It contends that in the non-RTO context, application of the cost allocation 

methodology leaves ample room for transmission providers to engage in undue 

discrimination, and the Commission cannot reasonably assume that the cost allocation 

methodology, by itself, will in all cases provide customers with “notice” as to how 

regional facilities will be selected, and their costs allocated, in the future.37 It also 

contends that transmission providers have the enhanced ability to discriminate, 

particularly where a cost allocation methodology is unlikely to have the specificity and 

objectivity to cabin the transmission provider’s discretion, and where stakeholders only 

may have the opportunity to provide input that the transmission providers are free to 

ignore.38 It argues that, in these cases in particular, treating the cost allocation 

methodology as a formula rate improperly shifts the burdens imposed by section 205.39

17. Transmission Access Policy Study Group argues that, at minimum, the 

Commission should defer making a generic finding now that section 206 is the only 

available recourse to challenge specific applications of regional cost allocation 

 36 Id.

37 Id. at 7-8.

38 Id. at 8.

39 Id.
Docket No. RM10-23-002 -14-

methodologies absent transmission providers electing to propose section 205 filings of 

those specific applications.40 Instead, it suggests that the Commission should leave for 

determination on a case-by-case basis the process of evaluating Order No. 1000 

compliance filings, in response to requests by transmission providers or other 

stakeholders or on its own motion, whether in a particular region the filing of specific 

applications of the regional cost allocations is necessary.41 It maintains that deferral will 

enable the Commission to consider the specifics of the proposed regional cost allocation 

methodology in conjunction with the proposed project selection process and associated 

governance and other safeguards (if any), as well as the views of public utility 

transmission providers in that region and other stakeholders.42

c. Commission Determination

18. We deny rehearing. Transmission Access Policy Study Group has not persuaded 

us that the determination not to require the filing of specific applications of the cost 

allocation method was in error. Order No. 1000’s reforms are intended, in part, to 

establish an open and transparent transmission planning process and require transmission 

planning regions to adopt a cost allocation method or methods that provide ex ante

certainty. Both the Order No. 1000 compliance process and the resulting Commissionapproved regional transmission planning process and associated cost allocation method(s) 

 40 Id. at 9.

41 Id.

42 Id. at 10.
Docket No. RM10-23-002 -15-

are required to have built-in mechanisms to help ensure that the processes and cost 

allocation methods are in fact transparent and provide the certainty that Transmission 

Access Policy Study Group seeks. 

19. First, stakeholders have had the opportunity to participate fully in regional 

stakeholder meetings to advocate for a cost allocation method that provides the ex ante

certainty that Order No. 1000 seeks, as well as to advocate that public utility transmission 

providers include a provision requiring the filing of specific applications of the cost 

allocation method. We believe that this approach accords with the regional flexibility we 

provided in Order No. 1000 for public utility transmission providers and stakeholders in a 

transmission planning region to develop rules that meet the transmission needs of that 

region, consistent with the requirements and principles set forth in Order Nos. 1000 and 

1000-A.

20. Second, the Commission will carefully consider the Order No. 1000 compliance 

filings once they are submitted, as well as any protests filed by stakeholders, to ensure 

that proposals satisfy the requirements that regional transmission planning processes be 

open and transparent and that the cost allocation method or methods satisfy the Order No. 

1000 cost allocation principles. If a filing is deficient, the Commission will require 

public utility transmission providers to file revisions to address those deficiencies.

21. Third, once the regional transmission planning process is approved by the 

Commission and becomes effective, the Order No. 890 transmission planning principles, 

as incorporated into a regional transmission planning process in compliance with Order 

No. 1000, will help mitigate concerns about the transparency of the process and the 
Docket No. RM10-23-002 -16-

application of the cost allocation method. These principles address, among other things, 

stakeholder participation, information exchange, and dispute resolution.43 By 

incorporating these principles into the regional transmission planning process, the 

Commission’s expectation is that there will be increased openness and certainty 

concerning how beneficiaries of transmission facilities selected in the regional

transmission plan for purposes of cost allocation will be determined, as well as internal 

processes to resolve any questions that might arise as part of this process. And as noted 

in Order No. 1000-A, in identifying the benefits and beneficiaries for a new transmission 

facility, the regional transmission planning process must provide entities who will receive 

regional or interregional cost allocation an understanding of the identified benefits on 

which the cost allocation is based, all of which would occur prior to the recovery of such 

costs through a formula rate.

44

22. Moreover, as we explained in Order No. 1000-A, stakeholders always have the 

option of filing a section 206 complaint if they believe that, notwithstanding these 

protections, there was an incorrect application of the cost allocation method in a 

 43 Order No. 890 requires transmission providers to disclose to all customers and 

other stakeholders the basic criteria, assumptions, and data that underlie their 

transmission system plans. In addition, transmission providers will be required to reduce 

to writing and make available the basic methodology, criteria, and processes they use to 

develop their transmission plans, including how they treat retail native loads, in order to 

ensure that standards are consistently applied. Preventing Under Discrimination and 

Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 471 (2007).

44 Order No. 1000-A, 139 FERC ¶ 61,132 at P 746. 
Docket No. RM10-23-002 -17-

particular instance. 45 Finally, if stakeholders believe that the previously approved cost 

allocation method itself is no longer just and reasonable, they also have the option of 

filing a section 206 complaint with respect to the cost allocation method. 

23. Transmission Access Policy Study Group suggests that application of the ex ante

cost allocation to, or in, particular instance(s) should require a section 205 filing with the 

Commission. Order No. 1000 establishes no new requirement with respect to this issue. 

As we note above, Order No. 1000-A stated that we would consider proposals that would 

require public utility transmission providers to file specific applications of the cost 

allocation method. Therefore, Order No. 1000 provides flexibility in this regard and the 

Commission stated that it will not prejudge any method before the compliance filings are 

filed, so long as they satisfied the cost allocation principles articulated in Order No. 1000 

(with the exception that participant funding may not be the regional or interregional cost 

allocation method). We will carefully evaluate compliance filings to ensure that they 

satisfy these principles. 

24. Transmission Access Policy Study Group asserts that if the cost allocation method 

is thought of as a formula rate, it would improperly shift the burdens under section 205 of 

the FPA, especially where a cost allocation method is unlikely to have specificity or 

objectivity to cabin transmission providers’ discretion and where they can ignore 

stakeholder input. We disagree with this argument. As we discuss above, Order No. 

1000 provides for ex ante certainty. In Order No. 1000, the Commission stated that it 

 45 Id, P 231.
Docket No. RM10-23-002 -18-

required the development of regional and interregional cost allocation methods to provide 

greater certainty as to the cost allocation implications of a potential transmission 

project.46 The Commission also stated that under the regional transmission planning and 

interregional transmission coordination requirements, public utility transmission 

providers with stakeholders will identify, evaluate, and determine which transmission 

facilities meet the region’s needs, and apply the cost allocation method or methods 

associated with those transmission facilities.

47 In Order No. 1000-A, the Commission 

clarified that public utility transmission providers must consult with stakeholders in 

developing both regional and interregional cost allocation methods.48 Therefore, the 

Commission specifically requires public utility transmission providers to provide the 

opportunity for stakeholder input in the development of the regional and interregional 

cost allocation methods. If a stakeholder believes that its input is being ignored, it has the 

right to raise its issues with the cost allocation method or methods when the relevant 

Order No. 1000 compliance filing is made, or in a separate section 206 filing.

25. We also disagree with Transmission Access Policy Study Group’s argument that 

the use of a cost allocation method could result in burden shifting under section 205. 

Order No. 1000-A acknowledged that stakeholder participation is an important aspect of 

the development of compliance filings to meet the requirements of Order No. 1000, and 

 46 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 559, 579.

47 Id. P 499.

48 Id. PP 559, 579.
Docket No. RM10-23-002 -19-

should ensure that the cost allocation method or methods ultimately agreed upon is 

balanced and does not favor any particular entity.49 Additionally, the Commission 

clarified that the Commission’s cost allocation requirements do not interfere with section 

205 rights or otherwise impose an undue burden on parties to participate in a new and 

costly process, but rather build on the reforms to the transmission planning process 

required by Order No. 890, in which all interested parties should already be 

participating.50 As noted above, 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 will be based.51 Compliance proposals 

submitted by transmission providers will be reviewed by the Commission to ensure they 

provide the upfront certainty required by Order No. 1000.52 To the extent that 

Transmission Access Policy Study Group is concerned about cost recovery issues rather 

than cost allocation, Order No. 1000 explained that such questions are beyond the scope 

of the generic rulemaking proceeding, and Order No. 1000-A affirmed this, but clarified 

 49 Order No. 1000-A, 139 FERC ¶ 61,132 at P 637.

50 Id. P 649.

51 Id. P 746.

52 As Transmission Access Policy Study Group also recognizes, not all RTOs 

make section 205 filings for the application of an existing filed cost allocation 

methodology. See Transmission Access Policy Study Group at n.14. Transmission 

Access Policy Study Group has not justified its position that this will be an issue in nonISO/RTO regions at this time. Again, the Commission will carefully evaluate 

compliance filings, as well as protests thereto, to ensure that they satisfy Order No. 

1000’s requirements, and the Commission will require changes if they fail to do so.
Docket No. RM10-23-002 -20-

that public utility transmission providers, in consultation with stakeholders, may choose 

to address this cost recovery matter in their compliance filings.53

26. We do not believe that Transmission Access Policy Study Group has justified at 

this time its position that public utility transmission providers in non-RTO regions, at 

least, should be required to file specific applications of the cost allocation method. 

Again, as discussed above, our expectation is that the open and transparent transmission 

planning process and principle-based cost allocation method will provide stakeholders 

with clarity as to why and how costs are being allocated for any specific transmission 

facility selected in the regional transmission plan for purposes of cost allocation. This is 

true regardless of whether or not the transmission planning region is an ISO/RTO. As we 

also discuss above, the Commission will carefully evaluate compliance proposals and any 

resulting protests to ensure that the proposals meet the requirements of Order No. 1000.

27. Finally, with respect to Transmission Access Policy Study Group’s request that we 

defer a determination on using section 206 as the default mechanism to challenge a cost 

allocation proposal, references to section 206 in Order No. 1000-A were to remind 

stakeholders of their right under that provision to file complaints. In any event, as we 

have previously explained, Order No. 1000-A provides that public utility transmission 

providers in a transmission planning region, in consultation with stakeholders, could 

agree to require the filing of specific applications of the cost allocation method. The 

 53 Order No. 1000-A, 139 FERC ¶ 61,132 at P 616.
Docket No. RM10-23-002 -21-

Commission will review any such requirement during the Order No. 1000 compliance 

filings process and make a decision based on the record before us.

3. Consideration of Transmission Needs Driven by Public Policy 

Requirements

a. Order No. 1000-A

28. Order No. 1000-A affirmed Order No. 1000’s requirement that public utility 

transmission providers amend their OATTs to provide for the consideration of 

transmission needs driven by Public Policy Requirements.54 In affirming this 

requirement, Order No. 1000-A provided clarifications regarding the definition of the 

term “Public Policy Requirements”55 and what it means to “consider” transmission needs 

driven by such requirements.56 Order No. 1000-A explained that the Commission intends 

that public utility transmission providers consider transmission needs driven by Public 

Policy Requirements just as they consider transmission needs driven by reliability or 

economic concerns.57 Further, the Commission stated that it does not intend public utility 

transmission providers to substitute their policy judgments for those of legislatures and 

 54 Order No. 1000-A, 139 FERC ¶ 61,132 at PP 317-339. See also id. PP 203-216 

(affirming legal basis of requirement to consider transmission needs driven by Public 

Policy Requirements).

55 Order No. 1000 defined “Public Policy Requirements” as public policy 

requirements established by state or federal laws and regulations. Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 at P 2. Order No. 1000-A clarified that this term included duly 

enacted laws or regulations passed by a local governmental entity, such as a municipal or 

county government. Order No. 1000-A, 139 FERC ¶ 61,132 at P 319.

56 Order No. 1000-A, 139 FERC ¶ 61,132 at PP 320-325.

57 Id. P 205.
Docket No. RM10-23-002 -22-

regulators.58 Order No. 1000-A also explained that the Commission does not require that 

regional transmission plans support multiple likely power supply scenarios, although 

such a requirement could be proposed in Order No. 1000 compliance filings and the 

Commission would consider such a proposal.59

b. Request for Clarification

29. AEP requests clarification that an appropriate method for a region to consider 

transmission needs driven by Public Policy Requirements is to expressly include 

consideration of changes in resources and load driven by public policies as part of its 

baseline projection of changes in resources and load expected over the planning horizon, 

and then conduct reliability and congestion analyses to determine what transmission 

investments are optimal given those expected changes in resources and load.60 AEP 

argues that Public Policy Requirements should not be considered solely on a stand-alone 

basis in the planning process.61 It contends that generation or load changes driven by 

public policies should be factored into the scenarios, along with other anticipated 

resource and load changes, for which reliability and economic benefits analyses are 

performed.62 

 58 Id. PP 326-29.

59 Id. P 331.

60 AEP at 5.

61 Id. at 2. 

62 Id.
Docket No. RM10-23-002 -23-

30. AEP states that it is concerned that some transmission providers may seek to 

satisfy the Commission’s public policy requirement by employing only a stand-alone 

process or procedures that are specifically designed to evaluate transmission needs driven 

by Public Policy Requirements.63 It argues that regional planning processes should 

consider reliability, economic, and policy-driven transmission needs together.64 In 

particular, AEP asserts that a region should consider what changes in generation 

resources and load it expects over the planning horizon, including consideration of 

changes driven by public policies (such as renewable portfolio standards, new 

environmental regulations, and demand side management programs), and then conduct 

reliability and congestion analyses to determine what transmission investments are 

optimal given these anticipated changes.65 It contends that this approach enables 

transmission providers to build upon existing planning processes for the reliability and 

economic analyses used to identify baseline reliability and economic projects.66 AEP 

argues that integrated consideration of public policy-driven requirements can factor into 

efficient decisions to accelerate a needed baseline reliability upgrade or increase the 

capacity of a baseline reliability upgrade or baseline economic upgrade.67

 63 Id. at 4.

64 Id.

65 Id.

66 Id.

67 Id.
Docket No. RM10-23-002 -24-

c. Commission Determination

31. We grant AEP’s request for clarification to the extent discussed below. Order No. 

1000 requires public utility transmission providers to revise their OATTs to provide for 

the consideration of transmission needs driven by Public Policy Requirements.68 In 

Order No. 1000, the Commission provides for regional flexibility so that public utility 

transmission providers, in consultation with stakeholders, can design proposals 

addressing this requirement that they believe best meet the needs of their respective 

transmission planning regions, so long as those proposals satisfy the essential 

requirement that public utility transmission providers, in consultation with stakeholders, 

consider transmission needs driven by Public Policy Requirements as set forth in Order 

No. 1000 and clarified in Order No. 1000-A.69 The Commission anticipates that a variety 

of approaches could satisfy the Commission’s requirements and we expect that 

stakeholders supporting such proposals would have the opportunity to advocate for them 

in the stakeholder processes leading to the Order No. 1000 compliance filings. The 

 68 The requirement to consider transmission needs driven by Public Policy 

Requirements is described in more detail in Order No. 1000, FERC Stats. & Regs. 

¶ 31,323 at PP 203-222 and Order No. 1000-A, 139 FERC ¶ 61,132 at PP 317-339.

69 See, e.g., Order No. 1000-A, 139 FERC ¶ 61,132 at P 331 (“It may well be the 

case that evaluating different power supply scenarios will be an effective way of identify 

more efficient or cost-effective transmission solutions; however, we will not prescribe 

any such requirements here, consistent with our preference for regional flexibility in 

designing regional transmission planning processes.”).
Docket No. RM10-23-002 -25-

Commission will consider any such approaches in the compliance filings when they are 

submitted for review.70

B. Nonincumbent Transmission Developers

32. In Order No. 1000, the Commission addressed the removal from Commissionjurisdictional tariffs and agreements of provisions that contain a federal right of first 

refusal 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 by public utility transmission providers 

in the regional transmission planning process. The Commission further required that a

nonincumbent transmission developer of a transmission facility selected in the regional 

transmission plan for purposes of cost allocation have an opportunity comparable to that 

of an incumbent transmission developer to allocate the cost of such transmission facility 

through a regional cost allocation method or methods.71

1. Legal Authority

a. Order No. 1000-A

33. In Order No. 1000-A, the Commission affirmed its conclusion in Order No. 1000 

that it 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-

 70 See id.

71 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 225.
Docket No. RM10-23-002 -26-

jurisdictional rates that are unjust and unreasonable or unduly discriminatory or 

preferential.72 The Commission stated that, consistent with its authority under 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 a federal right of first refusal from Commission-jurisdictional tariffs and 

agreements and adopt the nonincumbent reforms. The Commission explained that in 

Order No. 1000, it had found that a federal right of first refusal applicable to transmission 

facilities selected in a regional transmission plan for purposes of cost allocation can lead 

to rates for Commission-jurisdictional services that are unjust and unreasonable or 

otherwise result in undue discrimination by public utility transmission providers.73

34. Finally, the Commission affirmed its decision in Order No. 1000 to address 

arguments that an individual contract contains a federal right of first refusal that is 

protected by a Mobile-Sierra provision when it reviews the compliance filings made by 

public utility transmission providers.74 Consistent with Order No. 1000, the Commission 

explained that 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. However, the Commission also clarified that any such compliance 

filing must include the revisions to any Commission-jurisdictional tariffs and agreements 

 72 Order No. 1000-A, 139 FERC ¶ 61,132 at P 357.

73 Id. P 360.

74 Id. P 388.
Docket No. RM10-23-002 -27-

necessary to comply with Order No. 1000 as well as the Mobile-Sierra provision 

arguments.75 The Commission concluded that this approach ensures that public utility 

transmission providers would not be required 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 ensuring that the Order No. 1000 

compliance process proceeds expeditiously and efficiently.

b. Requests for Rehearing and Clarification

35. Oklahoma Gas and Electric Company argues that the Commission failed to 

support its assertion that provisions that designate incumbent utilities to construct new 

transmission facilities are unduly discriminatory or preferential, or cause rates to be 

unreasonably high.76 Oklahoma Gas and Electric Company further argues that the 

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

Power Pool result in rates that are unjust or unreasonable.77

36. Oklahoma Gas and Electric Company also argues that the Commission ignores 

that the Mobile-Sierra standard is a threshold question and that the Commission cannot 

shift the burden of proof to the contracting parties to propose an alternative until the 

 75 Id. P 389.

76 Oklahoma Gas and Electric Company at 4.

77 Id.
Docket No. RM10-23-002 -28-

Commission has answered.78 Oklahoma Gas and Electric Company asserts that, under 

section 206 of the Federal Power Act, the Commission must first prove that the existing 

rates or practices are unjust, unreasonable, unduly discriminatory or preferential, and that 

courts have repeatedly held that the Commission has no power to force public utilities to 

file particular rates unless it first finds the existing filed rates unlawful.79 Oklahoma Gas 

and Electric Company asserts that this two-step process is even more vital in the context 

of applying the Mobile-Sierra doctrine because the Commission must presume that the 

rate set out in a freely negotiated wholesale-energy contract meets the just and reasonable 

requirement imposed by law.80 Accordingly, Oklahoma Gas and Electric Company 

argues that the Commission has no power to require parties to renegotiate and revise 

existing agreements unless it finds harm to the public interest.81

c. Commission Determination

37. We disagree with Oklahoma Gas and Electric Company that the Commission 

failed to support its determination that a federal right of first refusal for transmission 

facilities selected in a regional transmission plan for purposes of cost allocation may lead 

 78 Id. at 8.

79 Id. at 8-9 (citing Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 10 (D.C. Cir. 

2002); Complex Consol. Edison Co. of New York, Inc. v. FERC, 165 F.3d 992, 1001 

(D.C. Cir. 1999); Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 688 

(D.C. Cir. 2005)). 

80 Id. at 9 (citing NRG Power Marketing, LLC v. Maine Public Utilities 

Commission, 130 S. Ct. 693, 700 (2010)).

81 Id. at 9-10.
Docket No. RM10-23-002 -29-

to Commission-jurisdictional rates that are unjust and unreasonable or unduly 

discriminatory or preferential. Specifically, the Commission found that a federal right of 

first refusal has “the potential to undermine the identification and evaluation of more 

efficient or cost-effective solutions to regional transmission needs, which in turn can 

result in rates for Commission-jurisdictional services that are unjust and unreasonable or 

otherwise result in undue discrimination by public utility transmission providers.”82 The 

Commission further explained the direct effect that a federal right of first refusal can have 

on Commission-jurisdictional rates in Order No. 1000-A, stating that: 

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. The ability of an incumbent transmission provider 

to discourage or preclude participation of new transmission 

developers through discriminatory rules in a regional 

transmission planning process, and in particular, the inclusion 

of a federal right of first refusal, can have the effect of 

limiting the identification and evaluation of potential solutions 

to regional transmission needs. This in turn can directly 

increase the cost of new transmission development that is 

recovered from jurisdictional customers through rates.83

38. The Commission put forth several rationales to support its determination.84 In 

particular, the Commission noted that the Federal Trade Commission supported the 

Commission’s conclusion that a federal right of first refusal can create a barrier to entry 

 82 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 253.

83 Order No. 1000-A, 139 FERC ¶ 61,132 at P 358 (citations omitted).

84 Id. P 76.
Docket No. RM10-23-002 -30-

that discourages nonincumbent transmission developers from proposing alternative 

solutions for consideration at the regional level.85 In addition, the Commission stated 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 the region’s needs.86 Thus, 

the Commission concluded that it has a reasonable expectation that expanding the 

universe of transmission developers offering potential solutions to regional needs can 

lead to the identification and evaluation of potential solutions that are more efficient or 

cost-effective.87

39. Furthermore, as the Commission explained in the Need for Reform section of 

Order No. 1000-A, 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.88 Rather, the Commission can 

proceed by identifying a “theoretical threat” that would materialize and cause rates to be 

unjust and unreasonable, or unduly discriminatory or preferential.89 As discussed in the 

preceding paragraph, the Commission found that a federal right of first refusal has the 

 85 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 257; see Order No. 1000-A, 

139 FERC ¶ 61,132 at P 76.

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

87 Order No. 1000-A, 139 FERC ¶ 61,132 at PP 77, 83.

88 Id. P 56.

89 Id. P 57.
Docket No. RM10-23-002 -31-

potential to lead to rates for Commission-jurisdictional services that are unjust and 

unreasonable or otherwise unduly discriminatory. 

40. In response to Oklahoma Gas and Electric Company’s arguments regarding the 

Mobile-Sierra doctrine, we reiterate that 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 the Mobile-Sierra

doctrine and whether the Commission has met the applicable standard of review. As the 

Commission clarified in Order No. 1000-A, the Commission will first decide, based on a 

more complete record, including viewpoints of other interested parties, whether an 

agreement is protected by the Mobile-Sierra doctrine, and if so, whether the Commission 

has met the applicable standard of review such that it can require the modification of the 

particular agreement.

90 If the Commission determines based on the record submitted in 

the compliance filing that an agreement is protected by the Mobile-Sierra doctrine and 

that it cannot meet the applicable standard of review, then the Commission will not 

consider whether the revisions to the Commission-jurisdictional tariffs and agreements 

submitted by a public utility transmission provider that considers its agreement to be 

protected by the Mobile-Sierra doctrine comply with Order No. 1000.91 

 90 Id. P 389.

91 Id.
Docket No. RM10-23-002 -32-

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. Order No. 1000-A

41. In Order No. 1000-A, the Commission affirmed its decision in Order No. 1000 to 

require the elimination of a federal right of first refusal from Commission-jurisdictional 

tariffs and agreements for transmission facilities selected in a regional transmission plan 

for purposes of cost allocation.92 The Commission also clarified certain terms used in 

Order No. 1000. For instance, the Commission clarified 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.93 

42. The Commission stated that in general, any regional cost 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.94 As an example, the 

Commission stated that transmission owning members of an RTO may not retain a 

 92 Id. P 415.

93 Id. P 423.

94 Id. P 424.
Docket No. RM10-23-002 -33-

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.95 The Commission also stated that it 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. The Commission explained that 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, the Commission 

stated that public utility transmission providers may include specific situations in their 

compliance filings along with the filed regional cost allocation method or methods.96 

The Commission clarified that if any costs of a new transmission facility are allocated 

regionally or outside of a public utility transmission provider’s retail distribution service 

territory or footprint, there can be no federal right of first refusal associated with such 

transmission facility, except as provided in Order Nos. 1000 and 1000-A.97

b. Requests for Rehearing and Clarification

43. Petitioners seek rehearing of the Commission’s determination in Order No. 1000-

A that a transmission facility is considered selected in a regional transmission plan for 

 95 Id.

96 Id.

97 Id. P 430. For example, the Commission does not require an incumbent 

transmission provider to eliminate a federal right of first refusal for upgrades to its own 

transmission facilities. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 319. 
Docket No. RM10-23-002 -34-

purposes of cost allocation if any of the costs of that facility are allocated outside of the 

public utility transmission provider’s retail distribution service territory or footprint.98 

MISO Transmission Owners Group 2 argues that under a reasonable interpretation of 

Order No. 1000, a transmission provider may retain its right of first refusal if a 

transmission facility is not selected in a regional transmission plan for purposes of cost 

allocation as a more efficient or cost-effective solution to regional needs but instead was 

selected to primarily address local needs.99 MISO Transmission Owners Group 2 states 

that not all projects included in the regional transmission plan for which some costs are 

allocated outside of an individual utility’s footprint are “a more efficient or cost-effective 

solution to regional transmission needs,” such as projects constructed to meet compliance 

with state service obligations or where the most efficient or cost-effective solution may 

not be in-service in time to satisfy reliability criteria and the decision to include the 

project in the plan is made primarily on the basis of reliability.100

44. MISO Transmission Owners Group 2 argues, however, that statements in Order 

No. 1000-A suggest that the decision regarding whether a facility is more efficient or 

cost-effective is irrelevant to determining whether the requirement to remove federal 

 98 See, e.g. MISO Transmission Owners Group 2 and Oklahoma Gas and Electric 

Company.

99 MISO Transmission Owners Group 2 at 12-13.

100 Id. at 14-15 (citing Order No. 1000-A, 139 FERC ¶ 61,132 at P 430).
Docket No. RM10-23-002 -35-

rights of first refusal would apply.101 MISO Transmission Owners Group 2 argues that 

the Commission cites no record evidence or argument in favor of broadening the 

definition of transmission facilities selected in a regional transmission plan for purposes 

of cost allocation.102 Accordingly, MISO Transmission Owners Group 2 asks for the 

Commission to clarify that, in order for the requirement to eliminate the federal right of 

first refusal to apply, the costs of a transmission facility must not only be allocated 

outside of a transmission owner’s retail distribution service territory or footprint and the 

transmission facility must have been selected in the regional transmission plan, but it also 

must be selected as a more efficient or cost-effective solution to regional transmission 

needs. The MISO Transmission Owners Group requests that the Commission clarify that 

utilities may retain a right of first refusal for projects that are selected which may not be 

the “more efficient or cost-effective solution to regional transmission needs.”103

45. MISO Transmission Owners Group 2 also argues that eliminating the ability of a 

transmission-owning member of an RTO to construct and allocate the costs of a local 

transmission facility encourages free ridership by providing an incentive for transmission 

providers to keep cost allocation within their retail distribution service territory to retain a 

 101 Id. at 13-14 (citing Order No. 1000-A, 139 FERC ¶ 61,132 at P 430 (“if any

costs of a new transmission facility are allocated regionally or outside of a public utility 

transmission provider’s retail distribution service territory or footprint, then there can be 

no federal right of first refusal associated with such transmission facility.”)).

102 Id. at 18.

103 Id. at 15-19. 
Docket No. RM10-23-002 -36-

right of first refusal for local transmission facilities, even when entities outside of the 

retail distribution service territory or footprint may receive some benefit from such 

facilities despite their primarily local nature.104

46. Oklahoma Gas and Electric Company argues that a broader definition of what 

constitutes regional cost allocation prohibits transmission planning regions from adopting 

approaches they believe would effectively allocate costs and fairly balance stakeholder 

interests.105 For instance, Oklahoma Gas and Electric Company states that the Southwest 

Power Pool allocates costs using a Highway/Byway Plan.106 Oklahoma Gas and Electric 

Company asserts that the Commission should ensure that the Southwest Power Pool can 

retain its Highway/Byway Plan for cost allocation by designating lower voltage facilities 

as local facilities for purposes of Order No. 1000.107 

47. Some petitioners request that the Commission clarify that projects with costs 

allocated to a single zone should be considered local, even if the zone consists of more 

than one public utility transmission provider, so that the public utility transmission 

 104 Id. at 19.

105 Oklahoma Gas and Electric Company at 6.

106 Id. (citing Southwest Power Pool, Inc., 131 FERC ¶ 61,252 (2010), reh’g 

denied, 137 FERC ¶ 61,075 (2011)). Oklahoma Gas and Electric Company states that the 

Southwest Power Pool allocates: (1) 100% of the cost of a facility operating at 300 kV or 

above across the region on a postage stamp basis; (2) one-third of the cost of a facility 

operating above 100 kV and below 300 kV on a regional postage stamp basis and the 

remaining two-thirds of the costs to the zone in which the facility is located; and, (3) all 

the costs of a facility operating at or under 100 kV to the zone in which the facility is 

located. Id.

107 Id.
Docket No. RM10-23-002 -37-

provider may retain a federal right of first refusal.108 AEP contends that the 

Commission’s proposal to defer evaluation of multi-utility zones until the compliance 

filing stage does little to inform ongoing RTO stakeholder processes tasked with 

developing compliance filings.109 MISO Transmission Owners Group 2 asserts that the 

Commission failed to identify any record evidence or argument for its conclusion that 

transmission providers located in multi-transmission provider zones automatically lose 

their federal rights of first refusal for all transmission facilities.110 

48. MISO Transmission Owners Group 2 also argues that the Commission’s stated 

concern that such zones might be established to circumvent Order No. 1000 is 

misplaced.111 In support, MISO Transmission Owners Group 2 asserts that such zones 

were established prior to the issuance of Order No. 1000 and based on decades of 

cooperation and collaboration among transmission owners.

112 In addition, MISO 

Transmission Owners Group 2 argues that the Commission’s distinction between multitransmission provider zones and zones containing only one transmission provider results 

 108 See, e.g., AEP and MISO Transmission Owners Group 2.

109 AEP at 10-11. AEP cites as an example SPP’s stakeholder process which at the 

time of AEP’s request for clarification, was debating the interpretation of the 

Commission’s intended treatment of zones that have long included a single large, 

traditional load-serving public utility, as well as several small municipal or cooperative 

utilities that are dependent on the transmission system of the traditional public utility to 

serve their respective loads.

110 MISO Transmission Owners Group 2 at 24.

111 Id. at 22.

112 Id.
Docket No. RM10-23-002 -38-

in undue discrimination against transmission providers that happen to be located in a 

multi-transmission provider zone.113

49. Oklahoma Gas and Electric Company contends that the Commission incorrectly 

claimed in Order No. 1000-A that the scope of Order No. 1000 will be limited. It asserts 

that, in response to arguments that the requirement to eliminate the right of first refusal is 

beyond the Commission’s authority and will materially alter the business of public 

utilities, the Commission in Order No. 1000-A emphasized that the requirement did not 

extend to local transmission facilities.114 Oklahoma Gas and Electric Company asserts 

that based on the discussion of zones in Order No. 1000-A, it may not be possible to 

build a local facility under the Southwest Power Pool tariff, making all new construction 

subject to Order No. 1000.115 Similarly, MISO Transmission Owners Group 2 contends 

that RTO transmission-owning members lack individual mechanisms for cost allocation 

and recovery, and therefore would have no ability to build and recover the costs of local 

transmission facilities as they are defined in Order No. 1000.116

50. Oklahoma Gas and Electric Company argues that because the requirement to 

eliminate provisions that designate incumbent utilities to construct new transmission 

facilities is not limited in scope, and does materially alter the businesses of transmission 

 113 Id. at 26.

114 Oklahoma Gas and Electric Company at 3-5.

115 Id. at 5-6.

116 MISO Transmission Owners Group 2 at 23.
Docket No. RM10-23-002 -39-

owning companies, the Commission should find that there is no sound basis to require 

that public utility transmission providers remove such provisions.117 In the alternative, 

Oklahoma Gas and Electric Company asserts that the Commission should allow each 

region to define the scope of local transmission projects that will not be subject to the 

new rule.118

c. Commission Determination

51. On rehearing of Order No. 1000-A, petitioners have raised two issues related to 

Order No. 1000’s requirement that public utility transmission providers remove federal 

rights of first refusal from Commission-jurisdictional tariffs and agreements. First, some 

petitioners seek rehearing of Order No. 1000-A’s determination that if any of the costs of 

a new transmission facility are allocated regionally or outside of a public utility 

transmission provider’s retail distribution service territory or footprint, then there can be 

no federal right of first refusal associated with such transmission facility. Second, on 

rehearing some petitioners argue that projects with costs allocated to a single zone should 

be considered local, even if there is more than one public utility transmission provider 

located in that zone, so that the public utility transmission provider may retain a federal 

right of first refusal under those circumstances. We deny rehearing and will discuss each 

of these issues in turn.

 117 Oklahoma Gas and Electric Company at 7.

118 Id.
Docket No. RM10-23-002 -40-

52. As noted above, the first issue we address concerns requests for rehearing of Order 

No. 1000-A’s determination that if any costs of a new transmission facility are allocated 

regionally or outside of a public utility transmission provider’s retail distribution service 

territory or footprint, then there can be no federal right of first refusal associated with 

such transmission facility, except as provided in Order Nos. 1000 and 1000-A.119 Order 

No. 1000 requires that a federal right of first refusal be removed for new transmission 

facilities selected in a regional transmission plan for purposes of cost allocation. As 

noted above, the Commission stated in Order No. 1000 that in general, if any costs of a 

new transmission facility are allocated regionally or outside a single transmission 

provider’s retail distribution service territory or footprint, that is an application of the 

regional cost allocation method and that new transmission facility is not a local 

transmission facility.

120 Therefore, once a new transmission facility is selected in the 

regional transmission plan for purposes of cost allocation, it is no longer a local 

transmission facility exempt from the requirements of Order Nos. 1000 and 1000-A 

regarding the removal of federal rights of first refusal. For this reason, we deny rehearing

on this issue.

53. We note that neither Order No. 1000 nor Order No. 1000-A requires elimination 

of a federal right of first refusal in all circumstances.121 We also note that the 

 119 Order No. 1000-A, 139 FERC ¶ 61,132 at P 430. 

120 Id. P 424 (emphasis added).

121 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 318-319.
Docket No. RM10-23-002 -41-

Commission recognized that issuance of Order No. 1000 may have occurred in the 

middle of a transmission planning cycle for a particular region and, therefore, directed 

public utility transmission providers to explain in their respective compliance filings how 

they intend to implement the requirements of the Final Rule.122 Moreover, public utility 

transmission providers are required to describe the circumstances and procedures under 

which public utility transmission providers will reevaluate the regional transmission plan 

to determine if delays in the development of a transmission facility selected in a regional 

transmission plan for purposes of cost allocation require evaluation of alternative 

solutions, including those proposed by the incumbent transmission provider, to ensure the 

incumbent transmission provider can meet its reliability needs or service obligations.123

We will evaluate proposals related to these requirements on review of compliance filings. 

54. With respect to the second issue raised by petitioners—whether a project whose 

costs are allocated to a single zone with multiple transmission owners should be 

considered local and thus permit a public utility transmission provider to retain a federal 

 122 Id. P 162. See also id. P 65 (“Our intent here is that this Final Rule not delay 

current studies being undertaken pursuant to existing regional transmission planning 

processes or impede progress on implementing existing transmission plans. We direct 

public utility transmission providers to explain in their compliance filings how they will 

determine which facilities evaluated in their local and regional planning processes will be 

subject to the requirements of this Final Rule.”).

123 Order No. 1000-A, FERC Stats. & Regs. ¶ 31,132 at P 477. See also Order 

No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 329 (“[A]n incumbent transmission 

provider must have the ability to propose solutions that it would implement within its 

retail distribution service territory or footprint that will enable it to meet its reliability 

needs or service obligations.”).
Docket No. RM10-23-002 -42-

right of first refusal under these circumstances—the Commission recognized in Order 

No. 1000-A that special consideration is needed when a small transmission provider is 

located within the footprint of another transmission provider.124 The Commission 

acknowledged that there is a continuum of situations of multi-transmission provider 

zones, but opted to address such situations on compliance. This acknowledgement 

provides public utility transmission providers who may have zonal configurations, such 

as a zone with a small municipality and one transmission provider, or one with many 

public utility and non-public utility transmission providers, an opportunity to address 

whether a cost allocation to a multi-transmission provider zone is regional on a case-bycase basis based on the specific facts presented. We consider many of the arguments 

related to multi-transmission provider zones premature because the Commission did not 

adopt a generic rule as to whether a cost allocation solely to a multi-transmission provider 

zone is an application of the regional cost allocation method for which a federal right of 

first refusal must be eliminated. Petitioners have not presented evidence that would 

support the Commission making a generic finding or providing additional guidance for 

all multi-transmission provider zones in this rulemaking proceeding. Therefore, on this 

second issue, we find that the Commission’s determination is a reasonable balance of 

competing considerations that enables the Commission to implement the requirements of 

Order No. 1000 in a manner that will achieve the goal of improved transmission 

planning. 

 124 Order No. 1000-A, FERC Stats. & Regs. ¶ 31,132 at P 424.
Docket No. RM10-23-002 -43-

55. We therefore agree with petitioners that the Commission’s requirements have not 

entirely eliminated opportunities for free ridership. As evidenced by the multiple 

comments and petitions the Commission received in the Order No. 1000 proceedings, the 

Commission balanced many competing interests in determining how to best implement 

the requirements of Order No. 1000. Some presented their views of the advantages of 

retaining a federal right of first refusal for all new transmission facilities while others 

presented their views of the advantages of eliminating a federal right of first refusal for 

all new transmission facilities. The Commission has considered the arguments raised by 

petitioners on rehearing with respect to both of the above-mentioned issues and rejects 

petitioners’ requests for rehearing as we find that the approach taken in Order Nos. 1000 

and 1000-A provides the best balance of competing considerations. 

3. Framework To Evaluate Transmission Projects Submitted for 

Selection in the Regional Transmission Plan for Purposes of 

Cost Allocation

a. Evaluation of Proposals for Selection in the Regional 

Transmission Plan for Purposes of Cost Allocation

i. Order No. 1000-A

56. In Order No. 1000-A, the Commission affirmed its 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 
Docket No. RM10-23-002 -44-

allocation.125 The Commission also reiterated that there are many different approaches to 

transmission planning and that Order No. 1000 requires only that the transmission 

planning process adopted by a transmission planning region satisfy the transmission 

planning principles discussed in Order Nos. 1000 and 1000-A. Accordingly, the 

Commission declined 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.

57. The Commission also continued to emphasize that any qualification criteria or 

process for selecting transmission facilities in a regional transmission plan for purposes 

of cost allocation must be transparent and not unduly discriminatory.

126 Finally, the 

Commission affirmed its decision that, if a proposed transmission facility is selected in a 

regional transmission plan for purposes of cost allocation, then 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.127 The 

Commission also reiterated that it would not require public utility transmission providers 

in a region to adopt a provision for ongoing sponsorship rights, and pointed out that in 

Order No. 1000, the Commission concluded that granting transmission developers an 

 125 Order No. 1000-A, 139 FERC ¶ 61,132 at P 452.

126 Id. PP 439, 452.

127 Id. P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339.
Docket No. RM10-23-002 -45-

ongoing right to build sponsored transmission projects could adversely impact the 

regional transmission planning process.128 Accordingly, the Commission in Order No. 

1000-A declined to reverse this decision on the selection of transmission developers.129

ii. Requests for Rehearing and Clarification

58. AEP maintains that some regions are considering a process in which third parties 

(e.g., one or more states) select the developer for a transmission project after the regional 

planning entity has identified needed transmission projects in its regional transmission 

plan.130 AEP asserts that leaving the selection of a project developer to an entity other 

than the regional planning body threatens to lead to suboptimal results.131 It argues that 

the decision as to which entity is best suited to build a given transmission project 

necessarily relies on developer qualifications as assessed by the transmission provider, 

and on projected benefits, which will vary among developers.132 It contends that the 

selection of the best transmission solution for the region cannot be done effectively 

without information about the qualifications and the benefits offered by the developer for 

 128 Order No. 1000-A, 139 FERC ¶ 61,132 at P 456; Order No. 1000, FERC Stats. 

& Regs. ¶ 31,323 at P 339.

129 Order No. 1000-A, 139 FERC ¶ 61,132 at P 456; Order No. 1000, FERC Stats. 

& Regs. ¶ 31,323 at P 339.

130 AEP at 6.

131 Id. at 2.

132 Id. at 6.
Docket No. RM10-23-002 -46-

the project.133 Accordingly, AEP requests that the Commission provide clarification to 

discourage bifurcation of the planning process.134

iii. Commission Determination

59. We decline to clarify in advance of the compliance filings whether any particular 

approach to the selection of a transmission developer is a just and reasonable and not 

unduly discriminatory or preferential selection process. Order No. 1000 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.135 It also requires that if a transmission project is 

selected in a regional transmission plan for purposes of cost allocation, the transmission 

developer of that transmission facility must be able to rely on the relevant cost allocation 

method or methods within the region should it move forward with the transmission 

project.136 However, the Commission declined to otherwise address the selection of a 

transmission developer on a generic basis.137 We continue to believe that it is not 

appropriate to address in advance of the compliance filings the process for selecting 

transmission developers in greater detail. Instead, we reaffirm the flexibility that the 

 133 Id. at 6-7.

134 Id. at 6.

135 E.g., Order No. 1000-A, 139 FERC ¶ 31,132 at P 455.

136 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 332, 339; see also Order 

No. 1000-A, 139 FERC ¶ 61,132 at P 456.

137 E.g., Order No. 1000-A, 139 FERC ¶ 61,132 at P 455.
Docket No. RM10-23-002 -47-

Commission provided to the public utility transmission providers in each transmission 

planning region to propose a process for selecting transmission developers in accordance 

with each transmission planning region’s needs.138 

C. Interregional Transmission Coordination

60. 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.139 The Commission also required each public utility transmission provider, 

through its regional transmission planning process, to describe the methods by which it 

will identify and evaluate interregional transmission facilities and to include a description 

of the type of transmission studies that will be conducted to evaluate conditions on 

neighboring systems for the purpose of determining whether interregional transmission 

facilities are more efficient or cost-effective than regional facilities.140

 138 E.g., id.

139 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 493.

140 Id.
Docket No. RM10-23-002 -48-

1. Implementation of the Interregional Transmission Coordination 

Requirements

a. Procedure for Joint Evaluation

i. Order No. 1000-A

61. In Order No. 1000-A, the Commission reaffirmed 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.141 The Commission explained that 

Order No. 1000 establishes a closer link between transmission planning and cost 

allocation. Additionally, the Commission stated that Order No. 1000 provides for 

stakeholder involvement in the consideration of an interregional transmission facility 

primarily through the regional transmission planning processes.142 The Commission 

concluded 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.143

62. Additionally, the Commission acknowledged that, under the interregional 

transmission coordination procedures of Order No. 1000, an interregional transmission 

 141 Order No. 1000-A, 139 FERC ¶ 61,132 at P 509 (citing Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 at P 436).

142 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 465; see also id. P 443.

143 Order No. 1000-A, 139 FERC ¶ 61,132 at P 509.
Docket No. RM10-23-002 -49-

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. The Commission expressed its 

continued belief 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.144

ii. Requests for Rehearing and Clarification

63. AEP requests clarification that the inclusion of an interregional project in a 

regional plan need not be subject to the same benefits tests that would be applied to a 

single-region project, and that a region may include an interregional project in its plan if 

the benefits to the region compare favorably to the share of the costs that would be borne 

by that region (as distinct from the total project costs).145 Specifically, it states that in 

determining the costs and benefits of a proposed interregional transmission project for the 

purposes of the selection process, a regional transmission planning entity should be 

permitted to evaluate the benefits provided to an affected region and assume that a 

 144 Id. P 512.

145 AEP at 2, 7.
Docket No. RM10-23-002 -50-

portion of the costs of the project will be allocated to the affected region.146 For example, 

if a $100 million interregional project would have $180 million in benefits split evenly 

between two adjacent regions, both regions would find the project beneficial and would 

include it in the regional plan, if they assumed that one-half of the cost would be borne by 

each region.147

iii. Commission Determination

64. Order No. 1000 did not specify whether or how a regional or interregional benefitcost threshold should be applied when selecting a project in the regional transmission 

plan for purposes of cost allocation, or which costs should be included when calculating a 

benefit-cost threshold to use in this selection process. This was to provide the 

opportunity for each region to develop an appropriate calculation, if it chose to use a 

threshold at all. Therefore, we decline to clarify in advance of the compliance filings 

how a benefit-cost threshold should be applied. 

III. Cost Allocation

65. 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 

 146 Id. at 8.

147 Id.
Docket No. RM10-23-002 -51-

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”).148 The Commission required that the OATTs of all public utility 

transmission providers in a region include the same cost allocation method or methods 

adopted by the region.149 

66. The Commission also required that regional and interregional cost allocation 

methods each 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 

 148 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at 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.

149 Order No. 1000-A, 139 FERC ¶ 61,132 at P 523.
Docket No. RM10-23-002 -52-

transmission facilities.150 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.151 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.152 Finally, the 

Commission emphasized that its cost allocation requirements are designed to work in 

tandem with its transmission planning requirements to identify more appropriately the 

benefits and the beneficiaries of new transmission facilities so that transmission 

developers, planners and stakeholders can take into account in the transmission planning 

process who would bear the costs of transmission facilities, if constructed.153

1. Cost Allocation Principle 2—No Involuntary Allocation of Costs 

to Non-beneficiaries

a. Order Nos. 1000 and 1000-A

67. In Order No. 1000, the Commission adopted the following Cost Allocation 

Principle 2 for both regional and interregional cost allocation:

 150 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 622-693.

151 Id. P 588.

152 Id. P 482.

153 Id. P 483.
Docket No. RM10-23-002 -53-

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.154

68. 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.155

69. On rehearing, the Commission affirmed Order No. 1000’s adoption of Regional 

and Interregional Cost Allocation Principle 2. 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.156 The 

 154 Id. P 637.

155 Id. P 640. 

156 Id.
Docket No. RM10-23-002 -54-

Commission also found that the use of “likely future scenarios” would not expand the 

class of customers who would be identified as beneficiaries because it is limited to 

scenarios in which a beneficiary is identified as such on the basis of the cost causation 

principle.

70. The Commission clarified 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 purposes. If a project or group of projects 

is shown to have benefits in one or more of the transmission planning scenarios identified 

by public utility transmission providers in their Commission-approved Order No. 1000-

compliant cost allocation methods, Principle 2 would be satisfied. 

b. Requests for Rehearing or Clarification

71. Organization of MISO States argues that the Commission erred in paragraph 690 

of Order No. 1000-A when it concluded that if a project or group of projects is shown to 

have benefits in any one of the transmission planning scenarios studied by a public utility 

transmission provider in its planning process, then the conditions for satisfaction of Cost 

Allocation Principle 2 will be determined to have been met. It contends that, in response 

to ITC Companies’ request for clarification, the Commission stated 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.157 Organization of MISO States is concerned that the 

 157 Organization of MISO States at 2 (quoting Order No. 1000-A, 139 FERC 

(continued)
Docket No. RM10-23-002 -55-

Commission’s clarification reads out of Principle 2 the concept of the likelihood of a 

future scenario by suggesting that Principle 2 would be satisfied if benefits are shown 

under any scenario studied by the transmission provider in its planning process.158 

Accordingly, Organization of MISO States requests that the Commission clarify that its 

discussion in paragraph 690 of Order No. 1000-A only applies to likely future scenarios 

as required by Principle 2.

c. Commission Determination

72. We clarify that in finding that Cost Allocation Principle 2 would be satisfied if a 

project or group of projects is shown to have benefits in one or more of the transmission 

planning scenarios identified by public utility transmission providers in their 

Commission-approved Order No. 1000-compliant cost allocation methods, we did not 

intend to remove the “likely future scenarios” concept from transmission planning. We 

believe the evaluation of likely future scenarios can be an important factor in public 

utility transmission providers’ consideration of transmission projects and in the 

identification of beneficiaries consistent with the cost causation principle. 

 

¶ 61,132 at P 690 (“If a project or group of projects is shown to have benefits in one or 

more of the transmission planning scenarios identified by public utility transmission 

providers in their Commission-approved Order No. 1000-compliant cost allocation 

methods, Principle 2 would be satisfied.”)). 

158 Id. 
Docket No. RM10-23-002 -56-

IV. Information Collection Statement

73. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain information collection requirements imposed by an agency.159 The 

revisions in Order Nos. 1000 and 1000-A to the information collection requirements were 

approved under OMB Control No. 1902-0233. While this order provides clarification, it 

does not modify any information collection requirements. Accordingly, a copy of this 

order will be sent to OMB for informational purposes only.

V. Document Availability

74. 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.

75. 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.

 159 5 CFR 1320.11.
Docket No. RM10-23-002 -57-

76. 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

VI. Effective Date

77. Changes to Order Nos. 1000 and 1000-A made in this order on rehearing and 

clarification will be effective on [insert 30 days after publication in the Federal 

Register].

By the Commission. Commissioner LaFleur is dissenting in part with a separate 

statement. 

Commissioner Clark is not participating.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary. 
Docket No. RM10-23-002 -58-

Note: The following appendices will not be published in the Code of Federal Regulations.

Appendix A: Abbreviated Names of Petitioners

Abbreviation Petitioner Names

AEP American Electric Power Service Corporation

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. 

Oklahoma Gas and Electric 

Company

Oklahoma Gas and Electric Company

Organization of MISO States Illinois Commerce Commission; Indiana Utility 

Regulatory Commission; Iowa Utilities Board; 

Kentucky Public Service Commission; 

Michigan Public Service Commission; 

Minnesota Public Utilities Commission; 

Missouri Public Service Commission; 
Docket No. RM10-23-002 -59-

Abbreviation Petitioner Names

Wisconsin Public Service Commission; and 

Montana Public Service Commission

Transmission Access Policy 

Study Group

Transmission Access Policy Study Group
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities

Docket No. RM10-23-002

(Issued October 18, 2012)

LaFLEUR, Commissioner, dissenting in part:

As part of today’s order, the Commission affirms its holding in Order No. 1000-A that 

an incumbent transmission provider may not retain a federal right of first refusal (ROFR) for a 

new transmission project—even a local reliability project—if that project receives any amount 

of regional funding.1

 After further consideration, I believe this decision is premature and 

denies transmission-planning regions the flexibility to define local projects. I am now 

persuaded that the Commission should have deferred judgment on this issue until compliance, 

where it could have evaluated—on a case-by case-basis—proposals to define local projects in 

light of the principles underlying elimination of the ROFR and the requirement that costs must 

be allocated in a manner that is at least roughly commensurate with benefits. Because I would 

grant rehearing on this point, and defer the issue to compliance, I respectfully dissent in part 

from today’s order.

In Order No. 1000, the Commission eliminated the ROFR for projects “selected in a 

regional transmission plan for purposes of cost allocation” but allowed it to continue for local 

projects.2

 In response, certain petitioners requested guidance as to whether the requirement to 

remove the ROFR for projects “selected in a regional transmission plan for purposes of cost 

allocation” required eliminating it in two specific situations: first, when costs are allocated only 

to multiple transmission providers within a single, local zone; and second, when local 

reliability projects receive some amount of regional funding as part of a cost allocation 

methodology.3

 In essence, petitioners requested clarification as to whether these specific cost 

allocation mechanisms converted otherwise local reliability projects to regional projects for 

purposes of eliminating the ROFR. 

 1 Transmission Planning and Cost Allocation by Transmission Owning and Operating 

Public Utilities, Order No. 1000, 76 FR 49842 (Aug. 11, 2011), FERC Stats. & Regs. ¶ 31,323 

(2011), order on reh’g, Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132

at P 430 (2012).

2 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 313, 318; see also P 63 (defining 

local projects). 

3 Order No. 1000-A, 139 FERC ¶ 61,132 at PP 409-410; see also n. 495 (examples of 

cost allocation methodologies reflecting distinctions between regional and local projects that 

were previously approved by the Commission.). 
Docket No. RM10-23-002 -2-

With respect to the question about zones, in Order No. 1000-A the Commission 

acknowledged that “there may be a continuum of examples” that require fact specific 

determinations.4

 Rather than lay down a categorical rule, the Commission opted for flexibility 

and invited parties to raise their specific situations on compliance.5

 Today’s order affirms this 

approach.

In contrast, in Order 1000-A the Commission did reach a definitive conclusion with 

respect to whether any amount of regional funding converts an otherwise local reliability 

project in to a regional project for purposes of the ROFR. The Commission clarified, without 

explanation,6 that the ROFR must be eliminated if a project receives any amount of regional 

funding.7

 As a result, a local reliability project that receives any amount of regional funding, 

no matter how small, is no longer local for purposes of the ROFR. Today’s order summarily 

affirms this decision.

After further consideration, I believe the Commission acted prematurely in concluding 

that any amount of regional funding converts an otherwise local reliability project to a regional 

project for purposes of the ROFR. By reaching this conclusion in the abstract, without the 

benefit of considering stakeholder-vetted proposals to define local projects in light of the 

principles underlying elimination of the ROFR and the requirement that costs must be 

allocated in a manner that is at least roughly commensurate with benefits, the Commission has 

denied transmission planning regions the flexibility it wisely acknowledged to be necessary 

with respect to the zone issue. I agree with SPP and OGE that we should provide that 

flexibility.8

 4 Id. P 424.

5 Id. 

6 For example, the Commission did not explain, in light of its distinction in Order No, 

1000 between projects in a regional plan and projects “selected in a regional transmission plan 

for purposes of cost allocation,” why eliminating the ROFR for projects “selected in a regional 

transmission plan for purposes of cost allocation” requires eliminating it for local projects that 

are primarily locally funded. 

7 Id. P 430.

8 In its request for clarification of Order 1000-A, SPP seeks guidance on how to 

reconcile the definitions and principles underlying Order No. 1000 with the Commission’s 

summary determination in Order No. 1000-A that any amount of regional funding for local 

reliability projects requires elimination of the ROFR. See SPP Request for Clarification at 7-

16. Unlike my colleagues, I believe that SPP’s filing may properly be characterized as a 

request for clarification, and therefore, should be addressed in this order. However, I would 

(continued)
Docket No. RM10-23-002 -3-

In Order No. 1000, the Commission balanced many competing policy considerations in 

an effort to adopt the reforms necessary to assure just and reasonable rates.9

 This balance may 

be most pronounced in the Commission’s efforts to ensure that the regional planning process is 

broad, inclusive, and fair, while at the same time, mindful of the obligations and attributes of 

incumbent transmission providers. The Commission also went to great lengths to provide 

transmission-planning regions with the flexibility to negotiate cost allocation methodologies 

that allocate costs in a manner that they believe is at least roughly commensurate with benefits. 

Where the mutual achievement of these objectives raises complex questions, as it does with 

respect to whether any amount of regional funding converts an otherwise local reliability 

project in to a regional project for purposes of the ROFR, the Commission should decide the 

issue on compliance, with a record, rather than by establishing categorical rules that may 

undermine the planning and cost allocation goals Order No. 1000 was intended to achieve.10

Accordingly, I respectfully dissent in part.

________________________

Cheryl A. LaFleur

Commissioner

 

not reach the merits of SPP’s arguments. Instead, I would grant rehearing on the grounds that 

the Commission should have deferred deciding the issue until compliance and invite SPP to 

make its arguments on compliance.

9 Order 1000-B at P 55.

10 See e.g. OGE Request for Rehearing at 6 (“[T]he broad definition of what constitutes 

regional cost allocation would prohibit regional entities such as SPP from adopting approaches 

they believe would effectively allocate costs and fairly balance stakeholder interests.”).