131 FERC ¶ 61,253 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

[Docket No. RM10-23-000] 

Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities 

(Issued June 17, 2010) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: The Federal Energy Regulatory Commission is proposing to amend the 

transmission planning and cost allocation requirements established in Order No. 890 to 

ensure that Commission-jurisdictional services are provided on a basis that is just, 

reasonable and not unduly discriminatory or preferential. With respect to transmission 

planning, the proposed rule would (1) provide that local and regional transmission 

planning processes account for transmission needs driven by public policy requirements 

established by state or federal laws or regulations; (2) improve coordination between 

neighboring transmission planning regions with respect to interregional facilities; and 

(3) remove from Commission-approved tariffs or agreements a right of first refusal 

created by those documents that provides an incumbent transmission provider with an 

undue advantage over a nonincumbent transmission developer. Neither incumbent nor 

nonincumbent transmission facility developers should, as a result of a Commissionapproved tariff or agreement, receive different treatment in a regional transmission 
Docket No. RM10-23-000 - 2 - 

planning process. Further, both should share similar benefits and obligations 

commensurate with that participation, including the right, consistent with state or local 

laws or regulations, to construct and own a facility that it sponsors in a regional 

transmission planning process and that is selected for inclusion in the regional 

transmission plan. With respect to cost allocation, the proposed rule would establish a 

closer link between transmission planning processes and cost allocation and would 

require cost allocation methods for intraregional and interregional transmission facilities 

to satisfy newly established cost allocation principles. 

DATES: Comments are due [insert date that is 60 days after publication in the

FEDERAL REGISTER]. 

ADDRESSES: You may submit comments, identified by docket number by any of the 

following methods: 

 Agency Web Site: http://www.ferc.gov. Documents created electronically using 

word processing software should be filed in native applications or print-to-PDF 

format and not in a scanned format. 

 Mail/Hand Delivery: Commenters unable to file comments electronically must 

mail or hand deliver an original and 14 copies of their comments to: Federal 

Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE, 

Washington, DC 20426. 

Instructions: For detailed instructions on submitting comments and additional 

information on the rulemaking process, see the Comment Procedures Section of this 

document 
Docket No. RM10-23-000 - 3 - 

FOR FURTHER INFORMATION CONTACT: 

Russell Profozich 

Federal Energy Regulatory Commission 

Office of Energy Policy and Innovation 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6478 

John Cohen 

Federal Energy Regulatory Commission 

Office of the General Counsel 

888 First Street, NE 

Washington, DC 20426 

(202) 502-8705 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities 

Docket No. RM10-23-000 

NOTICE OF PROPOSED RULEMAKING 

TABLE OF CONTENTS

Paragraph Numbers

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

II. Background...........................................................................................................................6.

A. Order Nos. 888 and 890 ...................................................................................................6.

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

Planning and Cost Allocation ................................................................................................13.

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

III. The Need for Reform...........................................................................................................32.

IV. Proposed Reforms: Transmission Planning .......................................................................44.

A. Participation in the Regional Planning Process ..............................................................45.

B. Public Policy Driven Projects...........................................................................................55.

C. Opportunities for Undue Discrimination against Nonincumbent Transmission 

Developers .............................................................................................................................71.

1. Nonincumbent Transmission Developer Participation in the Transmission 

Planning Process................................................................................................................71.

2. Proposed Reforms Regarding Nonincumbents ............................................................87.

D. Interregional Coordination ..............................................................................................102.

1. The Need for Interregional Planning Reforms .............................................................102.

2. Proposed Interregional Planning Reforms....................................................................114.

V. Proposed Reforms: Cost Allocation ....................................................................................121.

A. Introduction ......................................................................................................................121.

1. Order No. 890’s Transmission Planning Principle on Cost Allocation for New 

Transmission Facilities .....................................................................................................121.
Docket No. RM10-23-000 ii 

2. October 2009 Notice and Subsequent Comments ........................................................129.

B. Legal Authority and Need for Reform ............................................................................138.

1. The Cost Causation Principle .......................................................................................139.

2. Need for Reform...........................................................................................................148.

C. Proposed Reforms ............................................................................................................155.

1. Intraregional Cost Allocation ......................................................................................164.

2. Interregional Cost Allocation .......................................................................................170.

VI. Compliance Filings .............................................................................................................179.

VII. Information Collection Statement......................................................................................182.

VIII. Environmental Analysis ...................................................................................................186.

IX. Regulatory Flexibility Act Analysis....................................................................................187.

X. Comment Procedures............................................................................................................188.

XI. Document Availability ........................................................................................................192.

Regulatory Text 

Appendix A: List of Short Names of Commenters on the Federal Energy Regulator 

Commission’s Notice of Request for Comments on Transmission Planning Processes 

under Order No. 890—Docket No. AD09-8-000, October 2009 

Appendix B: Pro Forma Open Access Transmission Tariff Attachment K 
131 FERC ¶ 61,253 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities 

Docket No. RM10-23-000 

NOTICE OF PROPOSED RULEMAKING 

(Issued June 17, 2010) 

I. Introduction

1. In this Notice of Proposed Rulemaking (Proposed Rule), the Federal Energy 

Regulatory Commission (Commission) is proposing to reform its electric transmission 

planning and cost allocation requirements for public utility transmission providers. The 

proposed reforms are intended to correct deficiencies in transmission planning and cost 

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

markets and thereby ensure that Commission-jurisdictional services are provided at rates, 

terms and conditions that are just and reasonable and not unduly discriminatory or 

preferential. 

2. This Proposed Rule builds on Order No. 890,1

 in which the Commission reformed 

the pro forma open access transmission tariff (OATT). Among other changes, Order 

 

(continued)

1 Preventing Undue Discrimination and Preference in Transmission Service, 

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

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

(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on 
Docket No. RM10-23-000 - 2 - 

No. 890 required each public utility transmission provider to have a coordinated, open, 

and transparent regional transmission planning process. Order No. 890 also established 

nine transmission planning principles, one of which addressed cost allocation for new 

projects. 

3. The Commission acknowledges that significant work has been done in recent 

years to enhance regional transmission planning processes. The reforms proposed herein 

seek to build on this progress by improving the effectiveness of regional transmission 

planning and the efficiency of resulting transmission development. In formulating this 

proposal, the Commission has sought to balance competing interests and identify a 

package of reforms that, if implemented, would support the development of transmission 

facilities identified by the region as necessary to satisfy reliability standards, reduce 

congestion, and enable compliance with public policy requirements established by state 

or federal laws or regulations. The Commission recognizes that opinions may differ as to 

whether the proposal as formulated will best achieve the Commission's goals. The 

Commission therefore seeks comment on the reforms proposed herein and encourages 

commenters to identify enhancements to the reforms that could better support the 

efficient and effective development of transmission facilities. 

4. With respect to transmission planning, the reforms proposed in this Proposed Rule 

would provide that: (1) local and regional transmission planning processes account for 

 

clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009). 
Docket No. RM10-23-000 - 3 - 

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

laws or regulations; (2) coordination between neighboring transmission planning regions 

is improved with respect to facilities that are proposed to be located in both regions, as 

well as interregional facilities that could address transmission needs more efficiently than 

separate intraregional facilities; and (3) a right of first refusal that is created by a 

document subject to the Commission’s jurisdiction and that provides an incumbent utility 

with an undue advantage over nonincumbent transmission project developers is removed 

from that document. Neither incumbent nor nonincumbent transmission facility 

developers should, as a result of a Commission-approved OATT or agreement, receive 

different treatment in a regional transmission planning process. Further, both should 

share similar benefits and obligations commensurate with that participation, including the 

right, consistent with state or local laws or regulations, to construct and own a facility 

that it sponsors in a regional transmission planning process and that is selected for 

inclusion in the regional transmission plan. The Commission preliminarily finds that 

these proposed reforms are needed to protect against unjust and unreasonable rates, terms 

and conditions and undue discrimination in the provision of Commission-jurisdictional 

services. 

5. With respect to transmission cost allocation, the Commission is proposing to 

require public utility transmission providers to establish a closer link between cost 

allocation and regional transmission planning processes in which the beneficiaries of new 

transmission facilities are identified, as well as to establish principles that cost allocation 

methods must satisfy. The Commission sees these proposals as steps that would increase 
Docket No. RM10-23-000 - 4 - 

the likelihood that facilities included in regional transmission plans are actually 

constructed. For example, establishing a closer link between transmission planning and 

cost allocation processes would diminish the likelihood that a transmission facility would 

be included in a regional transmission plan, only to later encounter cost allocation 

disputes that inhibit construction of that facility. 

II. Background

A. Order Nos. 888 and 890

6. In Order No. 888,2

 issued in 1996, the Commission found that it was in the 

economic interest of transmission providers to deny transmission service or to offer 

transmission service on a basis that is inferior to that which they provide to themselves.3

 

Concluding that unduly discriminatory and anticompetitive practices existed in the 

electric industry and that, absent Commission action, such practices would increase as 

competitive pressures in the industry grew, the Commission in Order No. 888 and the 

accompanying pro forma OATT implemented open access to transmission facilities 

owned, operated, or controlled by a public utility. 

 2

 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), order 

on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order 

No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC 

¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group 

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002). 

3

 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,682. 
Docket No. RM10-23-000 - 5 - 

7. As part of those reforms, Order No. 888 and the pro forma OATT set forth certain 

minimum requirements for transmission planning. For example, the pro forma OATT 

required a public utility transmission provider to account for the needs of its network 

customers in its transmission planning activities on the same basis as it provides for its 

own needs.4

 The pro forma OATT also required that new facilities be constructed to 

meet the service requests of long-term firm point-to-point customers.5

 While Order 

No. 888-A went on to encourage utilities to engage in joint and regional transmission 

planning with other utilities and customers, it did not require those actions.6

 

8. In early 2007, the Commission issued Order No. 890 to remedy flaws in the pro 

forma OATT that the Commission identified based on the decade of experience since the 

issuance of Order No. 888. Among other things, the Commission found that pro forma

OATT obligations related to transmission planning were insufficient to eliminate 

opportunities for undue discrimination in the provision of transmission service. The 

Commission stated that particularly in an era of increasing transmission congestion and 

the need for significant new transmission investment, it could not rely on the self-interest 

of transmission providers to expand the grid in a not unduly discriminatory manner. 

Among other shortcomings in the pro forma OATT, the Commission pointed to the lack 

of clear criteria regarding the transmission provider’s planning obligation; the absence of 

a requirement that the overall transmission planning process be open to customers, 

 4 See Section 28.2 of the pro forma OATT. 

5 See Sections 13.5, 15.4, & 27 of the pro forma OATT. 

6

 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,311. 
Docket No. RM10-23-000 - 6 - 

competitors, and state commissions; and the absence of a requirement that key 

assumptions and data underlying transmission plans be made available to customers. 

9. In light of these findings, one of the primary goals of the reforms undertaken in 

Order No. 890 was to address the lack of specificity regarding how customers and other 

stakeholders should be treated in the transmission planning process. To remedy the 

potential for undue discrimination in transmission planning activities, the Commission 

required each public utility transmission provider to develop a transmission planning 

process that satisfies nine principles and to clearly describe that process in a new 

attachment to its OATT (Attachment K). The Order No. 890 transmission planning 

principles are: (1) coordination; (2) openness; (3) transparency; (4) information 

exchange; (5) comparability; (6) dispute resolution; (7) regional participation; 

(8) economic planning studies; and (9) cost allocation for new projects.7

 

10. The transmission planning reforms adopted in Order No. 890 apply to all public 

utility transmission providers, including Commission-approved regional transmission 

organizations (RTOs) and independent system operators (ISOs). The Commission also 

stated that it expected all non-public utility transmission providers to participate in the 

planning processes required by Order No. 890. The Commission noted that reciprocity 

dictates that non-public utility transmission providers that take advantage of open access 

due to improved planning should be subject to the same requirements as jurisdictional 

 7

 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 418-601. 
Docket No. RM10-23-000 - 7 - 

transmission providers.8

 The Commission stated that a coordinated, open, and 

transparent regional planning process cannot succeed unless all transmission owners 

participate. However, the Commission did not invoke its authority under FPA section 

211A, which allows the Commission to require an unregulated transmitting utility (i.e., a 

non-public utility transmission provider) to provide transmission services on a 

comparable and not unduly discriminatory or preferential basis.9

 The Commission 

instead stated that if it found on the appropriate record that non-public utility 

transmission providers are not participating in the planning processes required by Order 

No. 890, then the Commission may exercise its authority under FPA section 211A on a 

case-by-case basis. 

11. On December 7, 2007, pursuant to Order No. 890, most public utility transmission 

providers and several non-public utility transmission providers submitted compliance 

filings that describe their proposed transmission planning processes.10 The Commission 

addressed these filings in a series of orders that were issued throughout 2008. Generally, 

the Commission accepted the compliance filings to be effective December 7, 2007, 

subject to further compliance filings as necessary for the proposed transmission planning 

 8 Id. P 441. 

9

 FPA section 211A(b) provides, in pertinent part, that “the Commission may, by 

rule or order, require an unregulated transmitting utility to provide transmission services 

– (1) at rates that are comparable to those that the unregulated transmitting utility charges 

itself; and (2) on terms and conditions (not relating to rates) that are comparable to those 

under which the unregulated transmitting utility provides transmission services to itself 

and that are not unduly discriminatory or preferential.” 16 U.S.C. 824j (2006).

10 A small number of transmission providers were granted extensions. 
Docket No. RM10-23-000 - 8 - 

processes to satisfy the nine transmission planning principles. The Commission issued 

additional orders on Order No. 890 transmission planning compliance filings in the 

spring and summer of 2009. 

12. As a result of these compliance filings, RTOs and ISOs have enhanced their 

regional transmission planning processes, making them more open, transparent, and 

inclusive. Regions of the country outside of RTO and ISO regions have also made 

significant strides with respect to transmission planning by working together to enhance 

existing, or create new, regional transmission planning processes.11 These improvements 

to transmission planning processes have given customers and other stakeholders the 

opportunity to participate in the identification of regional needs and corresponding 

solutions, thereby facilitating the development of more efficient and effective 

transmission expansion plans. 

B. Technical Conferences and Notice of Request for Comments on 

Transmission Planning and Cost Allocation

13. In several of the above-noted orders issued in 2008 and early 2009 on filings 

submitted to comply with the Order No. 890 transmission planning requirements, the 

Commission stated that it would continue to monitor implementation of these 

 11 The regional transmission planning processes that public utility transmission 

providers in regions outside of RTOs and ISOs have relied on to comply with certain 

requirements of Order No. 890 are the North Carolina Transmission Planning 

Collaborative, Southeast Inter-Regional Participation Process, SERC Reliability 

Corporation, ReliabilityFirst Corporation, Mid-Continent Area Power Pool, Florida 

Reliability Coordination Council, WestConnect, ColumbiaGrid, and Northern Tier 

Transmission Group. 
Docket No. RM10-23-000 - 9 - 

transmission planning processes. The Commission also announced its intention to 

convene regional technical conferences in 2009. 

14. Consistent with the Commission’s announcement, Commission staff in September 

2009 convened three regional technical conferences in Philadelphia, Atlanta, and 

Phoenix, respectively. The focus of the technical conferences was to: (1) determine the 

progress and benefits realized by each transmission provider’s transmission planning 

process, obtain customer and other stakeholder input, and discuss any areas that may 

need improvement; (2) examine whether existing transmission planning processes 

adequately consider needs and solutions on a regional or interconnection-wide basis to 

ensure adequate and reliable supplies at just and reasonable rates; and (3) explore 

whether existing processes are sufficient to meet emerging challenges to the transmission 

system, such as the development of interregional transmission facilities and the 

integration of large amounts of location-constrained generation. Issues discussed at the 

technical conferences included the effectiveness of the current transmission planning 

processes, the development of regional and interregional transmission plans, and the 

effectiveness of existing cost allocation methods used by transmission providers and 

alternatives to those methods. 

15. Following these technical conferences, the Commission in October 2009 issued a 

Notice of Request for Comments.12 The October 2009 Notice presented numerous 

 12 Federal Energy Regulatory Commission, Transmission Planning Processes 

Under Order No. 890; Notice of Request for Comments; Docket No. AD09-8-000, 

October 8, 2009 (October 2009 Notice). 
Docket No. RM10-23-000 - 10 - 

questions with respect to enhancing regional transmission planning processes and 

allocating the cost of transmission. 

16. In response to the October 2009 Notice, the Commission received 107 initial 

comments and 45 reply comments.13 Many of these comments are discussed in greater 

detail later in this Proposed Rule, in the context of the Commission’s proposals on 

specific issues. 

17. In general, some commenters oppose additional Commission action at this time 

with respect to transmission planning. Among these commenters, some argue that 

existing transmission planning processes are adequate to achieve the Commission’s stated 

goals.14 Some of these commenters highlight work already underway in their own 

transmission planning regions, arguing that no Commission action is needed at least in 

those regions. Other commenters argue that existing processes are new or are being 

revised and should be given time to mature before additional changes are proposed. 

Many of these commenters state that if the Commission chooses to act, it should do so in 

a manner that does not disrupt existing transmission planning processes. Some 

commenters that oppose Commission action on transmission planning at this time state 

that it is important to maintain what they describe as a “bottom-up” approach to 

transmission planning, in which regional transmission planning is based on transmission 

 13 See Appendix A for a list of the commenters and their abbreviated names. 

14 E.g., Dominion, Large Public Power Council, Midwest ISO, New York PSC, 

Northern Tier Transmission Group, and WECC. 
Docket No. RM10-23-000 - 11 - 

planning conducted by the individual transmission-owning utilities in a transmission 

planning region.15

18. Many other commenters support additional Commission action on transmission 

planning at this time.16 These commenters offer a wide range of views on why and how 

the planning process should be improved. Although these commenters express diverse 

views, there appears to be a consensus among those supporting action that the 

Commission should—at a minimum—provide guidance about planning for large, 

interregional transmission projects. 

19. Many commenters that support Commission action on transmission planning raise 

issues related to the procedural characteristics or geographic scope of existing 

transmission planning processes. Some commenters contend that the Order No. 890 

transmission planning principles should be extended to support interregional 

coordination, while others argue that additional planning principles are necessary to 

ensure the effectiveness of transmission planning processes. Some commenters suggest 

that the type of “bottom-up” transmission planning described above is insufficient,17 and 

other commenters advocate changes such as establishing a regional or interconnectionwide planning coordinator.18 A few commenters suggest that the Commission add to the 

 15 E.g., Ohio Commission, PPL, Southern Companies, and WECC. 

16 E.g., American Transmission, CAlifornians for Renewable Energy, Dayton 

Power and Light, E.ON, LS Power, NRG, Pioneer Transmission, San Diego Gas & 

Electric, and Transmission Access Policy Study Group. 

17 E.g., Calvin Daniels (commenting as an individual). 

18 E.g., AEP. 
Docket No. RM10-23-000 - 12 - 

OATT a pro forma seams agreement that includes joint collaborative planning and cost 

allocation across planning regions.19 Still other commenters support changes to 

transmission planning processes, but caution against adopting a one-size-fits-all or an 

interconnectionwide approach.20 

20. Other commenters that support Commission action on transmission planning argue 

that some existing transmission planning processes provide an incumbent transmission 

owner with an unfair advantage over merchant and independent transmission project 

developers, such as by providing an incumbent transmission owner with a right of first 

refusal21 to construct a transmission facility that is included in a regional transmission 

plan and meets certain other criteria.22 These commenters argue that such practices 

discourage other, merchant and independent transmission developers’23 participation in 

the transmission planning process and present a significant barrier to transmission 

 19 E.g., Midwest ISO Transmission Owners, National Rural Electric Coops, and 

SPP. 

20 E.g., Pacific Gas and Electric and Transmission Agency of Northern California. 

21 A right of first refusal is defined, for the purposes of this proposed rulemaking, 

as the right of an incumbent transmission owner to construct, own, and propose cost 

recovery for any new transmission project that is: (1) located within its service territory; 

and (2) approved for inclusion in a transmission plan developed through the Order 

No. 890 planning process. 

22 E.g., AWEA, EPSA, LS Power, and Transmission Dependent Utility Systems. 

23 Merchant transmission projects are defined as those for which the costs of 

constructing the proposed transmission facilities will be recovered through negotiated 

rates instead of cost-based rates. For purposes of this proposed rulemaking, an 

incumbent transmission developer is an entity that develops a project within its own 

service territory. We note that a transmission owner that proposes a project outside of its 

own service territory is not considered an incumbent for purposes of that project. 
Docket No. RM10-23-000 - 13 - 

investment. Other commenters state that projects proposed by merchant and independent 

transmission project developers need to be included fully in regional transmission 

planning processes on the same basis as other projects.24 

21. Still other commenters that support Commission action on transmission planning 

express concern that current transmission planning processes do not adequately assess all 

of the potential benefits associated with transmission project proposals.25 Some of these 

commenters state that more attention needs to be devoted to analyzing the benefits 

associated with economic-based projects and incorporating such projects into regional 

transmission plans.26 PJM states that generic planning principles are needed to deal with 

the various social, environmental and economic impacts of regional transmission 

projects. In addition, several commenters recommend that the Commission incorporate 

state and federal public policy objectives into the transmission planning process,27 noting, 

for example, that doing so could facilitate cost-effective achievement of those objectives. 

 24 E.g., Allegheny Companies, AEP, CAlifornians for Renewable Energy, 

Delaware Municipal and Southwestern Electric, E.ON Climate & Renewables North 

America, Great River Energy, Sun Flower and Mid-Kansas, National Nuclear Security 

Administration Service Center, Organization of MISO States, and Transmission Agency 

of Northern California. 

25 E.g., AEP, AWEA, Baltimore Gas and Electric, Energy Future Coalition, 

Exelon, Green Energy Express, ITC Holdings, MidAmerican, National Audubon Society, 

et al., NextEra, and Public Interest Organizations & Renewable Energy Groups. 

26 E.g., MidAmerican and Old Dominion. 

27 E.g., AWEA, Baltimore Gas and Electric, Exelon, Eastern PJM Governors, The 

Brattle Group, ITC Holdings, LS Power, National Audubon Society, et al., National Grid, 

NextEra, Old Dominion, PJM, Public Interest Organizations & Renewable Energy 

Groups, Renewable Energy Systems Americas, and Trans-Elect. 
Docket No. RM10-23-000 - 14 - 

Commenters also recommend that the Commission provide for flexibility so that each 

transmission planning region could determine which resources it would use to fulfill 

these public policy objectives.28

22. The Commission’s questions in the October 2009 Notice with respect to allocating 

the cost of transmission also drew wide-ranging responses. For example, some 

commenters express concern that the lack of a link between transmission planning and 

cost allocation procedures may unnecessarily block or delay needed projects.29 Other 

commenters support establishing a generic cost allocation method as a backstop that 

would apply when parties or transmission planning regions cannot agree on a cost 

allocation method.30 

23. Some commenters indicate that the Commission should provide more detailed 

guidelines or principles for allocating the costs of new transmission facilities.31 These 

commenters generally agree that those who share in the benefits of transmission facilities 

should be responsible for their costs. However, there is not a consensus on how this 

principle should be implemented, what benefits should be considered for purposes of cost 

allocation, or how to determine who is a beneficiary. 

 28 E.g., Consolidated Edison, et al.

29 E.g., ITC Holdings, AEP, American Transmission, Green Energy Express, and 

WIRES. 

30 E.g., American Transmission; National Grid; and NEPOOL Participants. 

31 E.g., APPA, Green Energy Express, ITC Holdings, NEPOOL Participants, 

NextEra, Ohio Commission, Solar Energy Industries, and Transmission Access Policy 

Study Group. 
Docket No. RM10-23-000 - 15 - 

24. Some commenters urge the Commission to avoid rushing to a one-size-fits-all 

approach to determining beneficiaries of transmission projects, due to the varying nature 

of projects and benefits.32 Others express the view that it is difficult to quantify certain 

benefits that they consider relevant, such as carbon emission reduction, integration of 

renewable generation, or the most efficient use of existing rights-of-way.33 Other 

commenters suggest that there are ways to factor difficult to quantify benefits into the 

planning process such that they are adequately considered.34 

C. Additional Developments Since Issuance of Order No. 890 

25. Other developments with important implications for transmission planning have 

occurred amid the above-noted Order No. 890 compliance efforts on transmission 

planning and as the Commission gathered information through the technical conferences 

and the October 2009 Notice discussed above. 

26. For example, in February 2009, Congress enacted the American Recovery and 

Reinvestment Act (ARRA), which provided $80 million for the U.S. Department of 

Energy (DOE), in coordination with the Commission, to support the development of 

interconnection-based transmission plans for the Eastern, Western, and Texas 

interconnections. In seeking applications for use of those funds, DOE described the 

 32 E.g., APPA, Bonneville, California ISO, ColumbiaGrid, Consolidated Edison, et 

al., Dayton Power and Light, EEI, Entergy, Midwest ISO, Southern Companies. 

33 E.g., California ISO, Electricity Consumers Resource Council, MidAmerican, 

National Grid. 

34 E.g., AWEA, Energy Future Coalition, Entergy, Exelon, ITC Holdings, 

Integrys, et al. 
Docket No. RM10-23-000 - 16 - 

initiative as intended to: (1) improve coordination between electric industry participants 

and states on the regional, interregional, and interconnection-wide levels with regard to 

long-term electricity policy and planning; (2) provide better quality information for 

industry planners and state and federal policymakers and regulators, including a portfolio 

of potential future supply scenarios and their corresponding transmission requirements; 

(3) increase awareness of required long-term transmission investments under various 

scenarios, which may encourage parties to resolve cost allocation and siting issues; and 

(4) facilitate and accelerate development of renewable or other low-carbon generation 

resources.35 

27. In December 2009, DOE announced award selections for much of this ARRA 

funding. In each interconnection, applicants awarded funds under what DOE defined as 

Topic A are responsible for conducting interconnection-level analysis and transmission 

planning. Applicants awarded funds under Topic B are to facilitate greater cooperation 

among states and stakeholders within each interconnection to guide the analyses and 

planning performed under Topic A.36 Broad participation in sessions to date related to 

this initiative suggest that the availability of federal funds to pursue these goals has 

increased awareness of the potential for greater coordination among regions in 

transmission planning. 

 35 Department of Energy, Recovery Act- Resource Assessment and 

Interconnection-Level Transmission Analysis and Planning Funding Opportunity 

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

36 Id. at 4-8.
Docket No. RM10-23-000 - 17 - 

28. DOE has also been involved in the development of several recent reports that may 

have implications for transmission planning. In its 2008 report, 20% Wind Energy by 

2030, DOE concludes that “[s]ignificant expansion of the transmission grid will be 

required under any future electric industry scenario. Expanded transmission will increase 

reliability, reduce costly congestion and line losses, and supply access to low-cost remote 

resources, including renewables.”37

29. Similarly, in its 2009 report, Keeping the Lights On in a New World, the DOE 

Electricity Advisory Committee concluded that expanding and strengthening the nation’s 

transmission infrastructure is becoming increasingly important for two reasons: “First, 

increasing transmission capability will help ensure a reliable electric supply and provide 

greater access to economically priced power. Second, the growth in renewable energy 

development, stimulated in part by state-adopted renewable portfolio standards (RPS) 

and the possibility of a national RPS, will require significant new transmission to bring 

these resources, which are often remotely located, to consumer load centers.”38

30. The number of states that have adopted renewable portfolio standard measures, as 

well as the target levels set in those measures, has continued to increase. Some 30 states 

and the District of Columbia have now adopted renewable portfolio standard measures. 

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

38 Electricity Advisory Committee, Keeping the Lights On in a New World, at 45 

(Jan. 2009). The Electricity Advisory Committee was formed to provide advice to DOE 

in implementing the Energy Policy Act of 2005 and the Energy Independence and 

Security Act of 2007, and in modernizing the nation’s electricity delivery infrastructure. 

The Electricity Advisory Committee includes representatives from industry, academia, 

and state government. 
Docket No. RM10-23-000 - 18 - 

These measures typically require that a certain percentage of energy sales (MWh) or 

installed capacity (MW) come from renewable energy resources, with the target level and 

qualifying resources varying among the renewable portfolio standard measures. 

31. In its role as the Commission-designated Electric Reliability Organization, the 

North American Electric Reliability Corporation (NERC) concluded that significant 

transmission expansion will be needed to comply with renewable mandates. Even in the 

absence of a national renewable portfolio standard, NERC has stated that “an analysis of 

the past 14 years shows that the siting and construction of transmission lines will need to 

significantly accelerate to maintain reliability over the coming years.”39 In its 2009 

assessment of transmission needs, NERC found that if a national renewable portfolio 

standard of 15 percent were adopted, an additional 40,000 miles of transmission lines 

would be needed and “transmission would be a key component to accommodating new 

resources, linking geographically remote generation to demand centers.”40 

III. The Need for Reform

32. The Commission notes that transmission planning processes, particularly at the 

regional level, have seen substantial improvement through compliance with Order 

No. 890. As noted above, these improvements have increased opportunities for 

customers and other stakeholders to participate in the identification of regional needs and 

 39 North American Electric Reliability Corporation, 2009 Long-Term Reliability 

Assessment: 2009-2018, October 2009, at 29. 

40 North American Electric Reliability Corporation, 2009 Scenario Reliability 

Assessment: 2009-2018, October 2009, at 9. 
Docket No. RM10-23-000 - 19 - 

corresponding solutions, facilitating the development of more efficient and effective 

transmission plans. The Commission believes that the expanded cooperation and 

collaboration that is now occurring in transmission planning both among transmission 

providers and between transmission providers and their stakeholders is to be commended. 

33. Although Order No. 890 became effective just a few years ago, there have been 

significant changes in the nation’s electric power industry in those few years that require 

the Commission to consider additional reforms to transmission planning and cost 

allocation to reflect these new circumstances. These changes have been widely 

recognized within the industry.41 Our intention in this Proposed Rule is not to disrupt the 

progress that is already being made with respect to transmission planning and investment 

in transmission infrastructure, but rather to address remaining deficiencies in 

transmission planning and cost allocation processes so that the transmission grid can 

better support wholesale power markets and thereby ensure that Commission-

 41 For example, a trend of increased investment in the country’s transmission 

infrastructure has emerged in recent years. EEI attributes that trend to, among other 

factors, recognition of the reliability and other developments discussed above, as well as 

enactment of the Energy Policy Act of 2005 and the Commission’s implementation of its 

new transmission pricing policies. EEI has also observed that even amid this trend of 

increased investment in transmission infrastructure, transmission projects that would be 

located in more than one state “face significant challenges for siting, permitting, cost 

allocation and cost recovery.” Transmission Projects: At a Glance, Prepared by Edison 

Electric Institute with assistance from Navigant Consulting, Inc., February 2010, at iii-iv. 

EEI has also stated that “[t]hese challenges must be resolved to facilitate the movement 

of large quantities of renewable energy.” Transmission Projects Supporting Renewable 

Resources, Prepared by Edison Electric Institute, February 2009, at iv. 
Docket No. RM10-23-000 - 20 - 

jurisdictional services are provided at rates, terms and conditions that are just and 

reasonable and not unduly discriminatory or preferential. 

34. The siting, permitting, and cost allocation of transmission facilities face significant 

challenges. These challenges may be present whether an interstate transmission project is 

proposed to be located within a single region for which transmission planning is 

conducted in accordance with Order No. 890 (i.e., an intraregional transmission facility) 

or is instead proposed to be located in more than one such transmission planning region 

(i.e., an interregional transmission facility). The failure to address these challenges also 

can lead to increases in congestion costs. For example, PJM stated recently that prices 

for new generating capacity in the eastern part of its transmission planning region have 

increased due to constraints on its transmission system. Observing that capacity prices in 

the western portion of PJM were $27.73 per megawatt-day, while capacity prices in the 

transmission-constrained areas of PJM were between $226.15 and $247.14 per megawattday, PJM noted that “the great difference in prices for the eastern portion of PJM 

compared with elsewhere shows the need for increased transmission line capacity into the 

region. Transmission line additions and upgrades would reduce capacity price 

differences.”42

35. In light of the comments and developments discussed above, one deficiency that 

has arisen is the lack of a requirement for a regional transmission plan, without which the 

construction of new transmission facilities could be inhibited. Additionally, in the 

 42 PJM Interchange, News Release, May 14, 2010. 
Docket No. RM10-23-000 - 21 - 

absence of such a requirement, the facilities best suited to meet the needs of a particular 

region may not be identified. 

36. Another deficiency that has arisen since the issuance of Order No. 890 involves 

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

laws or regulations. For example, state policies to promote increased reliance on 

renewable energy resources, such as the renewable portfolio standard measures discussed 

above, accentuate the need for transmission to deliver electricity from locationconstrained renewable energy resources to load centers. Other state policies, such as 

goals for use of energy efficiency or demand response, may lower load forecasts within a 

given load zone and thereby affect transmission planning determinations. In addition, 

states may adopt economic development policies associated with meeting energy needs 

that may be relevant to assumptions made in a transmission planning process. Future 

public policy requirements established by federal laws or regulations also could have a 

significant effect on transmission planning. 

37. However, existing transmission planning processes generally were not designed to 

account for, and do not explicitly consider, these types of public policy requirements 

established by state or federal laws or regulations. Indeed, some comments submitted in 

response to the October 2009 Notice indicate that current transmission planning 

processes may not permit consideration of public policy requirements within regional 

transmission plans.43 As discussed in greater detail below, the Commission preliminarily 

 

(continued)

43 E.g., Baltimore Gas and Electric, Eastern PJM Governors, ITC Holdings, LS 
Docket No. RM10-23-000 - 22 - 

finds that the failure to account explicitly for such public policy requirements in the 

transmission planning process may result in undue discrimination and rates, terms, and 

conditions of service that are not just and reasonable. 

38. A third deficiency involves obstacles to nonincumbent transmission project 

developers’ participation in regional transmission planning processes. The Commission 

in recent years has seen increasing interest in transmission investment among these 

developers. Such interest, however, often has been coupled with expressions of concern 

about the treatment of merchant and independent transmission project developers in 

relevant transmission planning processes.44 Many commenters raised similar concerns in 

response to the October 2009 Notice, describing what they see as remaining opportunities 

for undue discrimination against nonincumbent transmission project developers in 

transmission planning processes. Such undue discrimination could discourage these 

developers from presenting projects in regional transmission planning processes, which, 

in turn, could inhibit development of beneficial transmission facilities. 

39. A fourth deficiency involves the relative lack of coordination between 

transmission planning regions. In Order No. 890, the Commission found that when 

transmission providers engage in regional transmission planning, they may identify 

solutions to regional needs that are more efficient than those that would have been 

 

Power, National Grid, Old Dominion, PJM, and Trans-Elect. 

44 See, e.g., Green Energy Express LLC, 129 FERC ¶ 61,165 (2009); Western Grid 

Dev., LLC, 130 FERC ¶ 61,056 (2010); Pioneer Transmission LLC, 126 FERC ¶ 61,281 

(2009). 
Docket No. RM10-23-000 - 23 - 

identified if needs and potential solutions were evaluated only independently by each 

individual transmission provider.45 Similarly, in the absence of coordination between 

transmission planning regions, transmission providers may not identify more efficient 

and cost-effective solutions to the individual needs identified in their respective utilitylevel and regional transmission planning processes, potentially including interregional 

transmission projects. In the few years since the issuance of Order No. 890, interest in 

multiregional facilities has grown significantly.46 The October 2009 Notice observed 

that the lack of coordinated planning over the seams of current transmission planning 

regions could be needlessly increasing costs for customers of individual transmission 

providers. Accordingly, the Order No. 890 transmission planning requirements may not 

be just and reasonable in that they may not be sufficient to address the need for greater 

coordination in interregional transmission planning. 

 

40. Finally, we preliminarily conclude that existing methods for allocating the costs 

of new transmission may not be just and reasonable because they may inhibit the 

development of efficient, cost-effective transmission facilities necessary to produce just 

and reasonable rates. While challenges associated with allocating the cost of 

transmission are not new, those challenges appear to have become more acute as the need 

45 “The coordination of planning on a regional basis will also increase efficiency 

through the coordination of transmission upgrades that have region-wide benefits, as 

opposed to pursuing transmission expansion on a piecemeal basis.” Order No. 890, 

FERC Stats. & Regs. ¶ 31,241 at P 524. 

46 See, e.g., Pioneer Transmission LLC, 126 FERC ¶ 61,281 (2009); Green Power 

Express, 127 FERC ¶ 61,031 (2009). 
Docket No. RM10-23-000 - 24 - 

for transmission infrastructure has grown. For example, the expansion of regional power 

markets and the increasing adoption of state policies to promote increased reliance on 

renewable energy resources have led to a growing need for regional or interregional 

transmission facilities. Meanwhile, determining the benefits of adding transmission 

infrastructure to the grid is a complex process, particularly for projects that affect 

multiple utilities’ transmission systems and therefore may have multiple beneficiaries. In 

such circumstances, any individual beneficiary of a project has an incentive to defer 

investment in the hopes that other beneficiaries will value the project enough to fund its 

development. 

41. Moreover, as stated in the October 2009 Notice, constructing new transmission 

facilities requires a significant amount of capital. Therefore, a threshold consideration for 

any company considering investing in transmission is whether it will have a reasonable 

opportunity to recover its costs. However, there are few rate structures in place today 

that provide for the allocation and recovery of costs for projects that are proposed to be 

located either within a transmission planning region that is outside of an RTO or ISO, or 

in more than one transmission planning region. The lack of such rate structures creates 

significant risk for transmission project developers that they will have no identified group 

of customers from which to recover the cost of their investment. 

42. Therefore, the Commission proposes to reform transmission planning and cost 

allocation processes as described in the following sections of this Proposed Rule. 

Although focused on discrete aspects of the transmission planning and cost allocation 

processes, these reforms are integrally related and should be understood as a package. 
Docket No. RM10-23-000 - 25 - 

With these related reforms, more transmission projects would be considered in the 

transmission planning process on an equitable basis, and more facilities that are included 

in transmission plans are likely to move forward to construction. 

43. The Commission recognizes that many of the existing regional transmission 

planning processes are comprised of both public utility and non-public utility 

transmission providers. Consistent with the approach taken in Order No. 890,47 the 

Commission expects all public utility and non-public utility transmission providers to 

participate in the regional transmission planning and cost allocation processes proposed 

by this Proposed Rule. Reciprocity dictates that non-public utility transmission providers 

that take advantage of open access, including improved regional transmission planning 

and cost allocation, should be subject to the same requirements as public utility 

transmission providers. We are encouraged, based on the efforts that followed Order 

No. 890, that both public utility and non-public utility transmission providers collaborate 

in a number of regional transmission planning processes. We therefore do not believe it 

is necessary at this time to invoke our authority under FPA section 211A, which allows 

us to require non-public utility transmission providers to provide transmission services on 

a comparable and not unduly discriminatory or preferential basis. However, if the 

Commission finds on the appropriate record that non-public utility transmission providers 

are not participating in the regional transmission planning and cost allocation processes 

 47 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 441. 
Docket No. RM10-23-000 - 26 - 

proposed in this Proposed Rule, the Commission may exercise its authority under FPA 

section 211A on a case-by-case basis. 

IV. Proposed Reforms: Transmission Planning

44. Transmission planning is a critical component of the provision of transmission 

service in interstate commerce. Among other purposes, transmission planning is the 

means by which the transmission needs of a given area and the facilities that are best 

suited to meet those needs are identified. Based on the comments received in response to 

the October 2009 Notice and the other developments and considerations discussed above, 

the Commission believes that further steps with respect to transmission planning may be 

necessary to protect against unjust and unreasonable rates, terms and conditions and 

undue discrimination in the provision of Commission-jurisdictional services. 

A. Participation in the Regional Planning Process 

45. In Order No. 890, the Commission adopted a regional participation principle as a 

necessary component of a public utility transmission provider’s transmission planning 

process. To meet that principle, the Commission required that each public utility 

transmission provider coordinate with interconnected systems to: (1) share system plans 

to ensure that the plans are simultaneously feasible and otherwise use consistent 

assumptions and data; and (2) identify system enhancements that could relieve 

congestion or integrate new resources.48 This requirement for coordination at the 

regional level can be contrasted with the separate requirement in Order No. 890 that each 

 48 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 523. 
Docket No. RM10-23-000 - 27 - 

public utility transmission provider use an open and transparent process to develop a 

transmission plan for its own control area.49 In other words, by adopting the regional 

participation principle, the Commission did not require development of a comprehensive 

regional transmission plan. 

46. The Commission explained that in complying with the regional participation 

principle, the specific features of a public utility transmission provider’s regional 

transmission planning process should take account of and accommodate, where 

appropriate, existing institutions, as well as historical practices and the physical 

characteristics of the region.50 The Commission recognized that regional transmission 

planning already occurs, for example, as part of the NERC Regional Entity planning 

process.51 The Commission urged public utility transmission providers to closely 

examine whether improvements in these regional transmission planning processes could 

be implemented to satisfy the requirements of Order No. 890 imposed on individual 

transmission providers.52

47. The Commission also stated that to satisfy the regional participation principle, an 

existing transmission planning process must be open and inclusive and address both 

reliability and economic considerations.53 The Commission required each public utility 

 49 Id. P 494, 523. 

50 Id. P 524. 

51 Id. P 528. 

52 Id. P 526. 

53 Id. P 528. 
Docket No. RM10-23-000 - 28 - 

transmission provider to participate in a transmission planning process that facilitates 

regional participation and that is open to all interested customers and stakeholders.54 

However, the Commission did not require each regional transmission planning process to 

comply with each of the nine transmission planning principles established in Order 

No. 890.55

48. On compliance with these Order No. 890 requirements, many public utility 

transmission providers relied on existing regional entities and transmission planning 

processes, modified as necessary, to comply with the regional participation principle.56 

49. Since the issuance of Order No. 890, it has become apparent to the Commission 

that Order No. 890’s regional participation principle may not be sufficient, in and of 

itself, to ensure an open, transparent, inclusive, and comprehensive regional transmission 

planning process. Without such a process, each transmission provider will not have 

information needed to assess proposed projects and determine which project or group of 

projects could satisfy local and regional needs more efficiently and cost-effectively. As a 

result, the rates, terms and conditions of transmission services may not be just and 

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

55 See, e.g., Entergy Services, Inc., 124 FERC ¶ 61,268, at P 104 (2008). 

56 As we note above, the regional transmission planning processes that public 

utility transmission providers in regions outside of RTOs and ISOs have relied on to 

comply with certain requirements of Order No. 890 are North Carolina Transmission 

Planning Collaborative, Southeast Inter-Regional Participation Process, SERC Reliability 

Corporation, ReliabilityFirst Corporation, Mid-Continent Area Power Pool, Florida 

Reliability Coordination Council, WestConnect, ColumbiaGrid, and Northern Tier 

Transmission Group. 
Docket No. RM10-23-000 - 29 - 

reasonable. For example, greater regional coordination in transmission planning would 

expand opportunities for transmission providers, their transmission customers, and other 

stakeholders to identify and implement regional solutions to local and regional needs that 

are more cost-effective than those proposed in the transmission planning process of 

individual transmission providers. In addition, more effective regional transmission 

planning could better facilitate the integration of location-constrained renewable energy 

resources, which may be needed to fulfill public policy requirements such as the 

renewable portfolio standards adopted by many states. 

50. Given this concern, we propose to require that each public utility transmission 

provider participate in a regional transmission planning process that produces a regional 

transmission plan and that meets the following transmission planning principles 

established in Order No. 890: (1) coordination; (2) openness; (3) transparency; 

(4) information exchange; (5) comparability; (6) dispute resolution; and (7) economic 

planning studies.57 

51. More specifically, we propose to require that each regional transmission planning 

process consider and evaluate transmission facilities and other non-transmission solutions 

that may be proposed and develop a regional transmission plan that identifies the 

transmission facilities that cost-effectively meet the needs of transmission providers, their 

 57 This proposal does not include the regional participation principle and cost 

allocation for new projects principle of Order No. 890 because we address interregional 

coordination in transmission planning and cost allocation for transmission facilities 

included in a regional transmission plan elsewhere in this Proposed Rule. 
Docket No. RM10-23-000 - 30 - 

transmission customers, and other stakeholders.58 When an individual transmission 

provider engages in local transmission planning, it considers and evaluates transmission 

facilities and non-transmission solutions that are proposed and then develops a local 

transmission plan that identifies what transmission facilities are needed to meet the needs 

of its native load (if any), transmission customers, and other stakeholders. Likewise, the 

regional transmission planning process would consider and evaluate transmission 

facilities and non-transmission solutions that are proposed and develop a regional 

transmission plan that identifies what transmission facilities are needed to meet the needs 

of transmission customers and other stakeholders in the region.59 

52. In addition, because of the increased importance of regional transmission planning 

that is designed to produce a regional transmission plan, transmission customers and 

other stakeholders must be provided with an opportunity to participate meaningfully in 

that process. Therefore, we propose to apply the above-noted Order No. 890 

 58 When evaluating potential solutions to identified needs, transmission providers 

must evaluate proposals for transmission, generation, and demand resources against one 

another based on criteria set forth in their tariffs. See Order No. 890, FERC Stats. & 

Regs. ¶ 31,241 at P 494-95; Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 216. 

The Commission also has recognized that in appropriate circumstances alternative 

technologies may be eligible for treatment as transmission for ratemaking purposes. 

Western Grid, 130 FERC ¶ 61,056 (2010). 

59 As noted in Order No. 890, the planning obligations proposed here do not 

address or dictate which investments identified in a transmission plan should be 

undertaken by transmission providers. Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 438. As also noted in Order No. 890, the ultimate responsibility for transmission 

planning remains with transmission providers. With that said, the Commission fully 

intends that the transmission planning processes provide for the timely and meaningful 

input and participation of customers into the development of transmission plans. Id. 

P 454. 
Docket No. RM10-23-000 - 31 - 

transmission planning principles to the regional transmission planning process, which 

would ensure that transmission customers and other stakeholders can express their needs 

before a regional transmission plan is finalized and thus help to identify solutions that 

more efficiently address the region’s needs. Similarly, ensuring access to the models and 

data used in the regional transmission planning process would allow transmission 

customers and other stakeholders to determine if their needs are being addressed in a 

cost-effective manner. Greater access to information and transparency would also help 

transmission customers and other stakeholders to recognize and understand the benefits 

that they will receive from a transmission facility that is included in a regional 

transmission plan. This consideration is particularly important in light of our proposal 

below to require that each public utility transmission provider have a cost allocation 

method for transmission facilities included in its regional transmission plan that reflects 

the benefits that those facilities provide. 

53. Although the explicit requirement for a public utility transmission provider to 

participate in a regional transmission planning process that complies with the Order 

No. 890 transmission planning principles identified above would be new, we note that the 

existing regional transmission planning processes that many utilities relied upon to 

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

comply with these requirements. 

54. We seek comment on any issue of interest or concern related to the requirements 

proposed in this section of the Proposed Rule. 
Docket No. RM10-23-000 - 32 - 

B. Public Policy Driven Projects

55. In Order No. 890, the Commission included an Economic Planning Studies 

principle among the nine transmission planning principles. The Commission stated that 

its primary objective in adopting that principle was “to ensure that the transmission 

planning process encompasses more than reliability considerations.”60 The Commission 

explained that although planning to maintain reliability is a critical priority, transmission 

planning also involves economic considerations.61 

56. More specifically, the Commission stated that when conducting transmission 

planning to serve native load customers, a prudent vertically integrated transmission 

provider will plan not only to maintain reliability, but also consider whether transmission 

upgrades or other investments can reduce the overall costs of serving native load.62 The 

Commission identified this potential for undue discrimination among a transmission 

provider’s customers as a justification to implement the Economic Planning Studies 

principle requiring transmission providers to make available to their customers services 

that are comparable to those they are performing on behalf of their native loads.63

57. The Economic Planning Studies principle requires that stakeholders be given the 

right to request a defined number of high priority studies annually through the 

 60 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 542. 

61 Id. 

62 The Commission further stated that such upgrades could, for example, reduce 

congestion (redispatch) costs or integrate efficient new resources (including demand 

resources) and new or growing loads. Id. 

63 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 240. 
Docket No. RM10-23-000 - 33 - 

transmission planning process. As defined in Order No. 890, these high priority studies 

are intended to identify solutions that could relieve transmission congestion or integrate 

new resources and loads, including upgrades to integrate new resources or loads on an 

aggregated or regional basis.64 

58. In Order No. 890, the Commission also required each public utility transmission 

provider to coordinate its transmission planning activities with the relevant state and local 

regulatory authorities that choose to participate in the transmission planning process and 

stated its expectation that “all transmission providers will respect states’ concerns.”65 As 

such, state and local regulatory authorities may fully participate in the existing Order 

No. 890 transmission planning process and identify, among other issues, public policy 

requirements established by state or federal laws or regulations that they see as relevant 

to transmission needs. However, when choosing whether to include a proposed 

transmission project in its local or regional transmission plan, a public utility 

transmission provider has no explicit obligation under Order No. 890 or the pro forma

OATT to evaluate the project based on its potential to facilitate the achievement of public 

policy requirements established by state or federal laws or regulations. 

59. The October 2009 Notice observed that some areas are struggling with how to 

adequately address transmission expansion necessary to, for example, integrate 

renewable generation resources into the transmission system. The October 2009 Notice 

 64 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 547-48. 

65 Id. P 574. 
Docket No. RM10-23-000 - 34 - 

attributed these difficulties in part to the fact that planning transmission facilities 

necessary to meet state resource requirements, such as the renewable portfolio standard 

measures discussed above, must be integrated with existing transmission planning 

processes that are based on metrics or tariff provisions focused on reliability or in some 

cases production cost savings.66 Drawing on these observations, the October 2009 

Notice sought comment as to whether reliability impact studies are properly aligne

evaluations of economic-based projects or projects proposed to satisfy renewable energy 

standards. To the extent that assessments of various possible project benefits are not 

properly aligned, the October 2009 Notice sought comment as to how reliability 

assessments, economic evaluations and assessments of a project’s ability to meet public 

policy goals could be aligned to better identify options that meet all of these regional 

needs.

d with 

 

67

60. The Commission received a number of comments on these issues, expressing a 

range of opinions. Several commenters argue that the existing transmission planning and 

stakeholder processes properly align reliability impact studies with evaluations of other 

projects designed to meet economic-based or public policy requirements.68 Other 

66 October 2009 Notice at 3. 

67 Id. at 4. 

68 E.g., Dominion, Entergy, Large Public Power Council, Midwest ISO, New York 

PSC, Northern Tier Transmission Group, Southern Companies, WestConnect Planning 

Parties, and WECC. In addition, PSEG Companies state that while it is true that 

reliability impact studies are performed independently of economic planning, such a 

distinction is appropriate because ensuring reliability is the primary objective of the 

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

commenters suggest that it would be inappropriate for the Commission to require that 

renewable energy standards be incorporated into the transmission planning process.69 

For example, Public Power Council contends that the Commission lacks jurisdiction

require that the resources necessary to comply with state renewable energy standards are 

accounted for in the transmission planning process, as such standards are state-level 

policies.

 to 

 

70 

61. In addition, several commenters recommend that the Commission incorporate 

public policy objectives into the transmission planning process.71 For example, PJM 

argues that “additional guidance from the Commission is needed if public policy 

imperatives such as aggressive integration of renewable resources are to be met.”72 PJM 

states that while ensuring system reliability should remain the primary goal of the 

transmission planning process, providing for incorporation of public policy objectives, 

where applicable, could facilitate cost-effective achievement of those objectives. In 

particular, PJM suggests that the Commission move beyond a strict application of “bright 

line” criteria currently used for reliability and economic projects and allow transmission 

69 E.g., Massachusetts Departments and Public Power Council. 

70 Massachusetts Departments share a similar concern. 

71 E.g., AWEA, Baltimore Gas and Electric, Public Interest Organizations & 

Renewable Energy Groups, Exelon, Eastern PJM Governors, ITC Holdings, LS Power, 

National Grid, NextEra, Old Dominion, PJM, Renewable Energy Systems Americas, 

Trans-Elect, and The Brattle Group. 

72 PJM Order No. 890 Technical Conference Comments, op. cit. at 6. 
Docket No. RM10-23-000 - 36 - 

providers more flexibility to take into account the multiple reliability, economic, or 

public policy-based benefits a single project may be able to provide.73

62. Other commenters propose various approaches to incorporating public policy 

objectives into the transmission planning process. Some of these commenters argue that 

if the goal of the transmission planning process is to allow load-serving entities to satisfy 

their resource needs, such needs could include resources required to comply with state 

and federal public policy objectives.74 Still other commenters recommend that the 

Commission provide flexibility in the transmission planning process so that each region 

can determine which resources it will use to fulfill any applicable public policy 

objectives.75 

63. To ensure that each public utility transmission provider’s transmission planning 

process supports rates, terms, and conditions of transmission service in interstate 

commerce that are just and reasonable and not unduly discriminatory or preferential, 

the Commission preliminarily finds that transmission needs driven by public policy 

requirements established by state or federal laws or regulations should be taken into 

account in the transmission planning process. Indeed, consideration of such public policy 

requirements raises issues similar to those raised in the Commission’s discussion in Order 

 73 Citing, PJM Interconnection, L.L.C., 119 FERC ¶ 61,265 (2007) (directing PJM 

to adopt a formulaic approach to applying metrics used to choose economic projects). 

74 E.g., APPA and Bay Area Municipal Transmission Group. 

75 E.g., Consolidated Edison, et al. 
Docket No. RM10-23-000 - 37 - 

No. 890 of the Economic Planning Studies principle.76 When conducting transmission 

planning to serve native load customers, a prudent transmission provider will not only 

plan to maintain reliability and consider whether transmission upgrades or other 

investments can reduce the overall costs of serving native load, but also consider how to 

enable compliance with relevant public policy requirements established by state or 

federal laws or regulations in a cost-effective manner. Therefore, we propose to find that, 

to avoid acting in an unduly discriminatory manner, a public utility transmission provider 

must consider these same needs on behalf of all of its customers. In addition, providing 

for incorporation of public policy requirements established by state or federal laws or 

regulations in transmission planning processes, where applicable, could facilitate costeffective achievement of those requirements. 

64. To address these issues, we propose to revise the requirements established in 

Order No. 890 with respect to local and regional transmission planning processes.77 

Specifically, we propose to require each public utility transmission provider to amend its 

OATT such that its local and regional transmission planning processes explicitly provide 

 76 In Order No. 890, the Commission intended the economic planning studies 

principle to be sufficiently broad to identify solutions that could relieve transmission 

congestion or integrate new resources and loads, including upgrades to integrate new 

resources and loads on an aggregated or regional basis. The Commission recognizes that 

its statements with respect to the economic planning studies principle may have 

contributed to confusion as to whether public policy requirements may be considered in 

the transmission planning process. 

77 By “local” transmission planning process, we mean the transmission planning 

process that a pubic utility transmission provider performs for its individual service 

territory or footprint pursuant to the requirements of Order No. 890. 
Docket No. RM10-23-000 - 38 - 

for consideration of public policy requirements established by state or federal laws or 

regulations that may drive transmission needs. After consulting with stakeholders, a 

public utility transmission provider may include in the transmission planning process 

additional public policy objectives not specifically required by state or federal laws or 

regulations. This proposed requirement would be a supplement to, and would not 

replace, any existing requirements with respect to consideration of reliability needs and 

application of the economic studies principle in the transmission planning process. 

65. The Commission does not propose to identify the public policy requirements 

established by state or federal laws or regulations that must be considered in individual 

local and regional transmission planning processes. Instead, we propose to require each 

public utility transmission provider to coordinate with its customers and other 

stakeholders to identify public policy requirements established by state or federal laws or 

regulations that are appropriate to include in its local and regional transmission planning 

processes. 

66. We propose to require each public utility transmission provider to specify in its 

OATT the procedures and mechanisms in its local and regional transmission planning 

processes for evaluating transmission projects proposed to achieve public policy 

requirements established by state or federal laws or regulations. If a public utility 

transmission provider believes that its existing transmission planning processes satisfy 

these requirements, then it must make that demonstration in its compliance filing. 

67. This proposed requirement is intended to clarify the objectives that would be 

considered in local and regional transmission planning processes. As we stated in Order 
Docket No. RM10-23-000 - 39 - 

No. 890, we believe that the transparency provided under open transmission planning 

processes can provide useful information that would help states to coordinate 

transmission and generation siting decisions, allow consideration of regional resource 

adequacy requirements, facilitate consideration of demand response and load 

management programs at the state level, and address other factors states wish to consider. 

68. Another benefit of this proposed requirement to consider public policy 

requirements established by state or federal laws or regulations within the transmission 

planning process is that adherence with this proposed requirement may eventually 

increase the proportion of transmission network investment that is constructed pursuant 

to proactive transmission planning processes, thereby reducing the proportion of network 

upgrades that would otherwise be triggered by individual generator interconnection 

requests, which can be time consuming and inefficient. If more of the transmission 

network were expanded under the type of regional transmission planning process 

described above, then the network upgrades triggered by interconnection requests should 

be less significant in size and cost than they have been in the past and the associated 

differences in cost allocation provisions may become less significant as well. 

69. This proposed requirement is not intended in any way to infringe upon state 

authority with respect to integrated resource planning.78 In addition, to the extent that a 

public utility transmission provider has an obligation to comply with public policy 

requirements established by state or federal laws or regulations, such as the state 

 78 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 479, n.274. 
Docket No. RM10-23-000 - 40 - 

renewable portfolio standard measures discussed above, this proposed requirement is not 

intended to convert a failure to satisfy that obligation into a violation of its OATT. In 

other words, while a public utility transmission provider would be required to identify 

and consider public policy requirements established by state or federal laws or 

regulations in its local and regional transmission planning processes, this proposed 

requirement would not establish an independent obligation to satisfy those requirements. 

70. We seek comment on any issue of interest or concern related to the requirements 

proposed in this section of the Proposed Rule. In particular, we seek comment as to 

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

should be considered in the transmission planning process. Further, we seek comment on 

how planning criteria based on public policy requirements should be formulated, 

including whether it is more appropriate to use flexible criteria instead of “bright line” 

metrics when determining which projects are to be included in the regional transmission 

plan, whether the use of flexible criteria would provide undue discretion as to whether a 

project is included in a regional transmission plan, and whether the use of “bright line” 

metrics may inappropriately result in alternating inclusion and exclusion of a single 

project over successive planning cycles and therefore create inappropriate disruptions in 

long-term transmission planning. 
Docket No. RM10-23-000 - 41 - 

C. Opportunities for Undue Discrimination against Nonincumbent 

Transmission Developers 

1. Nonincumbent Transmission Developer Participation in the 

Transmission Planning Process

71. As discussed above, Order No. 890 sought to reduce opportunities for undue 

discrimination and preference in the provision of transmission service. With regard to the 

transmission planning process, the Commission established nine transmission planning 

principles to prevent undue discrimination. However, Order No. 890 did not specifically 

address the potential for undue preference to incumbent utilities over nonincumbent 

transmission developers through practices applied within transmission planning 

processes. 

72. The October 2009 Notice observed that in some areas, when a nonincumbent 

transmission developer participates in the transmission planning process, it may lose the 

opportunity to construct its proposed project to the incumbent transmission owner if that 

owner has a right of first refusal to construct any transmission facility in its service 

territory. The October 2009 Notice also observed that in some areas, merchant 

transmission developers choose to plan proposed facilities outside of the transmission 

providers’ planning processes.79

73. The October 2009 Notice posed several questions relating to merchant and 

independent transmission developers’ participation in the regional transmission planning 

process. The October 2009 Notice sought comment on how projects proposed by 

 79 October 2009 Notice at 3. 
Docket No. RM10-23-000 - 42 - 

merchant or independent transmission developers should be treated in the regional 

transmission planning process. The October 2009 Notice also asked whether these types 

of developers should be required to participate in the regional transmission planning 

process and, if so, at what point they should be required to engage in that process. In 

addition, the October 2009 Notice asked whether the right of first refusal for incumbent 

transmission owners unreasonably impedes the development of merchant and 

independent transmission and, if so, how that impediment could be addressed. Finally, 

the October 2009 Notice asked whether there are barriers to merchant and independent 

transmission developers’ participation in the regional transmission planning process other 

than rights of first refusal.80 

74. These questions generated extensive comments. For example, many commenters 

argue that a project proposed by a merchant or independent transmission developer 

should be treated on the same basis as all other proposed projects.81 Also, a number of 

commenters assert that merchant and independent developers should be required to 

participate in the transmission planning process.82 For example, Southern Companies 

 

(continued)

80 Id. at 4. 

81 E.g., Allegheny Companies, AEP, CAlifornians for Renewable Energy, 

Delaware Municipal and Southwestern Electric, E.ON Climate & Renewables North 

America, Great River Energy, Sun Flower and Mid-Kansas, National Nuclear Security 

Administration Service Center, Organization of MISO States, and Transmission Agency 

of Northern California. 

82 E.g., APPA, CAlifornians for Renewable Energy, Delaware Municipal and 

Southwestern Electric, Dominion, Exelon, Integrys, Old Dominion, Sun Flower and MidKansas, Large Public Power Council, Midwest ISO, National Nuclear Security 

Administration Service Center, National Rural Electric Coops, New England States’ 
Docket No. RM10-23-000 - 43 - 

asserts that it would be discriminatory if the Commission did not require merchant and 

independent developers to participate in the transmission planning process, as 

jurisdictional and non-jurisdictional transmission providers are required to do. 

75. Other commenters state that merchant and independent developers should not be 

treated similarly or required to participate in the transmission planning process. For 

example, Chinook and Zephyr and ITC Holdings state that because the business model of 

merchant and independent transmission developers is different from that of verticallyintegrated utilities, different transmission planning requirements are appropriate for them. 

Chinook and Zephyr also argue that regional transmission planning requirements should 

apply to a merchant developer only after it is operating under a Commission-approved 

OATT. Dayton Power and Light contends that while any transmission facility that is 

necessary to meet NERC reliability criteria, regardless of ownership, should be required 

to be included in the transmission planning process, merchant and independent projects 

planned for nonreliability reasons can be developed independently of the transmission 

planning process, subject to appropriate interconnection requirements. 

76. Other commenters emphasize the importance of allowing merchant and 

independent developers to participate actively in the transmission planning process.83 

 

Committee on Electricity, New York PSC, Organization of MISO States, Pacific Gas and 

Electric, Ohio Commission, SPP, San Diego Gas & Electric, South Carolina Electric & 

Gas, Transmission Access Policy Study Group, Transmission Agency of Northern 

California, Transmission Dependent Utility Systems, and Xcel. 

83 E.g., Green Energy Express, ITC Holdings, Pattern Transmission, and 

Starwood. 
Docket No. RM10-23-000 - 44 - 

Generally, these commenters argue that merchant and independent transmission 

developers should either participate in the transmission planning process as early as 

practical, at the beginning of the transmission planning cycle, or as soon as they have a 

proposal that is developed well enough to be considered. Pattern Transmission also 

suggests that the Commission should better define the transmission planning process and 

the roles of its participants to ensure a level playing field for independent transmission 

developers. 

77. The questions about whether an incumbent transmission owner’s right of first 

refusal unreasonably impedes merchant or independent transmission development and, if 

so, how this impediment could be addressed, also generated extensive comments. Many 

commenters state that a right of first refusal does not unreasonably impede merchant and 

independent transmission development.84 Various commenters present a range of 

reasons that it is appropriate for an incumbent transmission provider to have a right 

first refusal, including that the incumbent transmission owner: (1) has a legally 

enforceable obligation to maintain reliability on its systems and faces penalties for 

of 

 84 E.g., Allegheny Companies, AEP, Ameren, Baltimore Gas and Electric, 

Dominion, EEI, Great River Energy, Integrys, et al., Sun Flower and Mid-Kansas, Large 

Public Power Council, MidAmerican, Midwest ISO Transmission Owners, National 

Grid, Northern Tier Transmission Group, Old Dominion, PPL, PSEG Companies, Ohio 

Commission, San Diego Gas & Electric, Southern California Edison, Southern 

Companies, WestConnect Planning Parties, and Xcel. However, Old Dominion suggests 

that the Commission could eliminate the right of first refusal if merchant and independent 

transmission developers were subject to the same rules and had the same responsibilities 

as incumbent transmission owners, and could recover their costs through the RTO/ISO 

tariff. 
Docket No. RM10-23-000 - 45 - 

noncompliance; (2) is obligated under state law to provide reliable service at the lowest 

reasonable cost; (3) may be required to build facilities included in an RTO’s or ISO’s 

regional plan, an obligation that merchant and independent transmission developers

(4) is best situated to develop transmission facilities within its service territory, as it is 

most familiar with the design and operation of its system, its customers’ needs, and st

and local permitting and siting processes; and (5) may be able to provide transmission 

services at a lower cost than a merchant or independent transmission developer becau

enjoys economies of scale with respect to the staff and resources necessary to mainta

and operate new transmission faciliti

 lack; 

ate 

se it 

in 

es. 

 

78. Some commenters contend that the right of first refusal should be preserved 

because an incumbent transmission owner that voluntarily joined an RTO or ISO did so 

with the understanding that it would retain the right to invest in and earn a return on new 

facilities within its system.85 According to Midwest ISO Transmission Owners, 

eliminating a right of first refusal could provide a disincentive for RTO membership. 

Similarly, the California ISO asserts that without a right of first refusal, a transmission 

owner may have less incentive to participate in an RTO or ISO. 

79. However, other commenters argue that a right of first refusal impedes transmission 

development and provides an undue advantage to an incumbent transmission owner.86 

(continued)

85 E.g., Ameren, MidAmerican, and Midwest ISO Transmission Owners. 

86 E.g., American Forest and Paper, AWEA, CAlifornians for Renewable Energy, 

EPSA, Indicated Partners, Modesto Irrigation District, NationalWind, NextEra, 

Renewable Energy Systems Americas, Startrans, Starwood, Transmission Access Policy 
Docket No. RM10-23-000 - 46 - 

Such commenters present a number of reasons for eliminating a right of first refusal, 

including the following: (1) a right of first refusal provides a disincentive for a merchant 

or independent developer to propose a project, especially a proposal for a transmission 

facility that spans multiple utilities’ service territories, because any investment that it 

makes in developing a proposal may be lost if an incumbent transmission owner can 

exercise its right of first refusal or otherwise delay the project or prevent construction of 

the project; (2) by discouraging competition and new entry, a right of first refusal likely 

increases costs to ratepayers; and (3) a merchant or independent transmission developer 

may have difficulty obtaining financing if investors perceive that its proposed project 

could be subject to a right of first refusal or is otherwise at a disadvantage compared to a 

project sponsored by an incumbent transmission owner. 

80. Among other comments on this issue, Startrans claims that for an incumbent 

transmission owner, a Commission-approved right of first refusal effectively creates a 

federal franchise for transmission development derived from a state franchise for retail 

electricity. Transmission Agency of Northern California contends that a right of first 

refusal also may “diminish the incentive for the incumbent utilities to conceive projects 

in their own service territory.”87 

81. Responding to arguments in favor of a right of first refusal, some commenters 

argue that concerns about the reliability of a merchant or independent transmission 

 

Study Group, Transmission Agency of Northern California, and Transmission Dependent 

Utility Systems. 

87 Transmission Agency of Northern California at 3. 
Docket No. RM10-23-000 - 47 - 

developer’s project are unfounded, as the merchant or independent transmission 

developer will be subject to NERC reliability standards and to the same penalties for 

noncompliance as an incumbent transmission owner.88 Pattern Transmission states that a 

merchant or independent developer has a financial incentive to construct and operate 

facilities safely and reliably in accordance with all applicable regulatory and industry 

standards, as its investment is at risk if it does otherwise. With regard to an incumbent 

transmission owner’s obligation to build, some commenters assert that it is not a burden, 

but rather a privilege, as the incumbent transmission owner is assured the opportunity to 

recover its costs and earn a return on its investment through the rate base. These 

commenters argue that a merchant or independent developer would be willing to compete 

for such an obligation.89 In response to concerns that a merchant or independent 

developer would submit an inaccurately low bid to construct a proposed transmission 

facility, some commenters claim that such a developer is no more likely to do so than an 

incumbent transmission owner.90 These same commenters argue that, contrary to what 

some commenters assert, an incumbent transmission owner will not leave an RTO or ISO 

if the right of first refusal is eliminated. 

82. While some commenters advocate elimination of all rights of first refusal, other 

commenters support more limited restrictions. For example, Exelon states that “where an 

independent developer bids on transmission expansion that is justified under existing 

 88 E.g., Green Energy Express and Pattern Transmission. 

89 E.g., Indicated Partners and Startrans. 

90 E.g., Indicated Partners. 
Docket No. RM10-23-000 - 48 - 

planning criteria and will be included in rate base, the incumbent transmission owner 

should be required to match the bid to invoke its right of first refusal.”91 Several 

commenters argue that a right of first refusal should be allowed for reliability-based 

projects, but may not be necessary for economic-based or other projects.92 While AWEA 

and LS Power both maintain that the right of first refusal should be eliminated, they 

contend that if the right of first refusal is preserved then those practices should apply only 

to local reliability projects. Moreover, AWEA asserts that a right of first refusal should 

be required to be exercised within ninety days. Similarly, ITC Holdings contends that a 

right of first refusal will continue to impede transmission development if the time for 

exercising it is allowed to continue indefinitely, and Pacific Gas and Electric argues that 

any right of first refusal should be exercised in a timely manner. Transmission Access 

Policy Study Group, however, states that the Commission may need to take other steps in 

addressing this issue in addition to limiting the time in which a right of first refusal may 

be exercised. In addition, several commenters contend that placing restrictions on a right 

of first refusal makes the practice no less discriminatory.93 

83. EEI argues that while “in general, applicability of a right of first refusal does not 

create an impediment to transmission planning or development” and that in many cases, 

“incumbent transmission owners are better situated to build needed transmission within 

their franchised service territories,” if the Commission finds it necessary to address the 

 91 Exelon at 12. 

92 E.g., Allegheny Companies, Dominion, Large Public Power Council, and SPP. 

93 E.g., Indicated Partners. 
Docket No. RM10-23-000 - 49 - 

exercise of a right of first refusal, it should do so on a case-specific basis.94 Similarly, 

the California ISO recommends that the Commission allow the right of first refusal to 

addressed through individual RTO and ISO stakeholder processes, rather than adopting 

generic right of first refusal regulations. Pacific Gas and Electric states that this 

proceeding should not preempt the California ISO’s development of a right of first 

refusal proposal. In contrast, SPP states that additional clarification and a generally 

applicable policy regarding the right of first refusal is necessary. The Organization of 

MISO States argues that, while a right of first refusal may limit competition, any 

modifications must recognize various state regulatory structures and respect state 

jurisdiction and statutes. The Alabama PSC argues that the Commission should adopt 

policies that encourage merchant transmission development only if the state commissions 

in a region support such policies. 

be 

 

84. In response to the question in the October 2009 Notice regarding barriers to 

merchant and independent transmission developers’ participation in the regional 

transmission planning process other than a right of first refusal, several commenters state 

that there are none or that they are unaware of any.95 However, Pattern Transmission 

suggests that the uncertainty of recovering the costs associated with participation in the 

transmission planning process can be a barrier to participation by merchant and 

independent transmission developers, particularly if the planning process is inefficient 

94 EEI at 9-10. 

95 E.g., Allegheny Companies, CAlifornians for Renewable Energy, Integrys, et 

al., Maine PUC and Public Advocate, New York PSC, and Xcel. 
Docket No. RM10-23-000 - 50 - 

and deadlines are not met. Pattern Transmission also asserts that an incumbent 

transmission owner has an advantage in developing proposals as it has priority access to 

data. Green Energy Express states that the Commission should ensure “a level playing 

field with regard to the flow of information, the determination of need, and related 

interactions between an RTO or ISO or other transmission planning region, incumbent 

transmission owners and developers, and independent, nonincumbent developers.”96

85. LS Power states that there are several additional barriers to third party developers’ 

participation in regional transmission planning processes, some of which are unique to 

certain markets. For example, LS Power states that there are regions in which an 

independent developer cannot become a transmission owner until it has completed a 

project and owns the resulting transmission facility. Additionally, LS Power states that it 

is difficult to develop a project in a region where the load-serving entity is also a 

transmission owner, as the incumbent utility is often responsible for both generation and 

transmission planning and resource procurement and may have an incentive to expand its 

rate base by investing in transmission infrastructure rather than support independent 

transmission development. 

86. Northern Tier Transmission Group suggests that some merchant transmission 

developers self-impose a barrier to successful participation in the transmission planning 

process in that they do not submit comparable planning data. As such, Northern Tier 

Transmission Group is unable to include their projects in its analytical studies. 

 96 Green Energy Express at 10. 
Docket No. RM10-23-000 - 51 - 

2. Proposed Reforms Regarding Nonincumbents

87. Based on the comments submitted in response to the October 2009 Notice, there 

appear to be opportunities for undue discrimination and preferential treatment against 

nonincumbent transmission developers within existing regional transmission planning 

processes. Where an incumbent transmission provider has a right of first refusal, a 

nonincumbent transmission developer risks losing its investment in developing a proposal 

for submittal to the regional transmission planning process, even if that proposal is 

selected for inclusion in the regional transmission plan. We are concerned that it may be 

unduly discriminatory or preferential to deny a nonincumbent transmission developer that 

sponsors a project that is included in a regional transmission plan the rights of an 

incumbent transmission provider that are created by a transmission provider’s OATT or 

agreements subject to the Commission jurisdiction. 

88. In addition, under these circumstances, nonincumbent transmission developers 

may be less likely to participate in the regional transmission planning process. If the 

regional transmission planning process does not consider and evaluate projects proposed 

by nonincumbents, it cannot meet the principle of being “open.” Moreover, such a 

planning process may not result in a cost-effective solution to regional transmission needs 

and projects that are included in a transmission plan therefore may be developed at a 

higher cost than necessary. The result may be that regional transmission services may be 

provided at rates, terms and conditions that are not just and reasonable. 

89. To address these issues, we propose a framework that reflects the following 

reforms, including the elimination from a transmission provider’s OATT or agreements 
Docket No. RM10-23-000 - 52 - 

subject to the Commission’s jurisdiction of provisions that establish a federal right of first 

refusal for an incumbent transmission provider with respect to facilities that are included 

in a regional transmission plan. Neither incumbent nor nonincumbent transmission 

facility developers should, as a result of a Commission-approved OATT or agreement, 

receive different treatment in a regional transmission planning process. Further, both 

should share similar benefits and obligations commensurate with that participation, 

including the right, consistent with state or local laws or regulations, to construct and own 

a facility that it sponsors in a regional transmission planning process and that is selected 

for inclusion in the regional transmission plan. The Commission proposes that the tariff 

changes to implement these proposed reforms would be developed through an open and 

transparent process involving the public utility transmission provider, its customers, and 

other stakeholders. 

90. First, we propose to require that each public utility transmission provider must 

revise its OATT to demonstrate that the regional transmission planning process in which 

it participates has established appropriate qualification criteria for determining an entity’s 

eligibility to propose a project in the regional transmission planning process, whether that 

entity is an incumbent transmission owner or a nonincumbent transmission developer. 

These criteria must be included in the public utility transmission provider’s OATT and 

must not be unduly discriminatory or preferential. However, it would not be unduly 

discriminatory or preferential to have appropriate qualification criteria for all potential 

transmission owners. Such criteria should be designed to demonstrate that each potential 

transmission owner has the necessary financial and technical expertise to develop, 
Docket No. RM10-23-000 - 53 - 

construct, own, operate, and maintain transmission facilities. 97 Any such criteria must 

be approved by the Commission. Although we do not propose here to establish a single 

set of qualification criteria that would apply in all regional transmission planning 

processes, we seek comment on whether we should do so and if so, what these criteria 

should be. Instead, we propose that each public utility transmission provider, in 

cooperation with customers and other stakeholders in its transmission planning region, 

must participate in a regional transmission planning process that develops qualification 

criteria that satisfy the requirements of this Proposed Rule. 

91. Second, we propose to require that each public utility transmission provider must 

revise its OATT to include a form by which a prospective project sponsor would provide 

information in sufficient detail to allow the proposed project to be evaluated in the 

regional transmission planning process.98 In connection with the other aspects of the 

framework discussed in this section, we also propose to require that all proposals to be 

considered in a given transmission planning cycle must be submitted by a single, 

specified date, to minimize the opportunity for other entities to propose slight 

modifications to already submitted projects. 

 97 Nothing would preclude the incumbent transmission owner from agreeing to 

operate and maintain the facilities. Additionally, nothing in this Proposed Rule is 

intended to change existing RTO and ISO operational procedures and practices. 

98 The information about its proposed project that a sponsor provides also should 

include, as relevant, engineering studies, cost analyses, and any other detailed reports 

completed by the project sponsor as needed to facilitate evaluation of the project in the 

regional transmission planning process. 
Docket No. RM10-23-000 - 54 - 

92. Third, we propose to require that each public utility transmission provider 

participate in a regional transmission planning process that evaluates the proposals 

submitted to the regional planning process through a transparent and not unduly 

discriminatory or preferential process. Each public utility transmission provider would 

be required to describe in its OATT the process used for evaluating whether to include a 

proposed transmission facility in the regional transmission plan.99

93. Fourth, with respect to facilities that are included in a regional transmission plan, 

we propose to require removal from a transmission provider’s OATT or agreements 

subject to the Commission’s jurisdiction provisions that establish a federal right of first 

refusal for an incumbent transmission provider.100 We also propose to require each 

public utility transmission provider to amend its OATT to describe how the regional 

transmission planning process in which it participates provides for the sponsor (whether 

an incumbent transmission provider or a nonincumbent transmission developer) of a 

facility that is selected through the regional transmission planning process for inclusion in 

 99 The description would need to provide sufficient detail so that an entity that 

proposed a project could determine why the project was included or not included in the 

regional transmission plan. In addition to addressing concerns about undue 

discrimination or preference, the description would facilitate understanding of the relative 

weight placed on various benefits associated with competing proposals (e.g., one 

proposal might address only a reliability-driven transmission need, while another 

proposal might also provide greater benefits in terms of congestion relief or advancement 

of public policy requirement established by state or federal laws or regulations that a 

transmission planning region has identified). 

100 If a Commission-approved tariff or agreement contains a reference to a right 

provided under state or local laws or regulations, such a provision would not be subject to 

this requirement. 
Docket No. RM10-23-000 - 55 - 

the regional transmission plan to have a right, consistent with state or local laws or 

regulations, to construct and own that facility. 

94. Moreover, because a regional transmission planning process may result in 

modifications to proposed projects in order to better meet the needs of the region, the 

public utility transmission provider must ensure that its regional transmission planning 

process has a mechanism to determine which proposal the modified project is most 

similar to, with the sponsor of the most similar project having the right, consistent with 

state or local laws or regulations to construct and own the facilities. 

95. Fifth, we propose to require that if a proposed project is not included in a regional 

transmission plan and if the project’s sponsor resubmits that proposed project in a future 

transmission planning cycle, that sponsor would have the right to develop that project 

under the foregoing rules even if one or more substantially similar projects are proposed 

by others in the future transmission planning cycle. The OATT must state that this 

priority to develop the proposed facility continues for a defined period of time (e.g., for 

resubmission annually in subsequent transmission planning cycles over a 5-year period). 

96. Sixth, we propose to require that, if an incumbent transmission project developer 

may recover the cost of a transmission facility for a selected project through a regional 

cost allocation method, a nonincumbent transmission project developer must enjoy that 

same eligibility. More specifically, each public utility transmission provider must 

participate in a regional planning process that provides that, when a project proposed by a 

nonincumbent transmission developer is included in a regional transmission plan, that 

developer must have an opportunity comparable to that of an incumbent transmission 
Docket No. RM10-23-000 - 56 - 

owner to recover the costs associated with developing the project and constructing the 

transmission facility. Costs associated with a project that is not included in the regional 

transmission plan, whether proposed by an incumbent or by a nonincumbent transmission 

provider, may not be recovered through a transmission planning region’s cost allocation 

process. 

97. We emphasize that these proposed reforms would apply only to facilities that are 

evaluated in a regional transmission planning process and selected for inclusion in a 

regional transmission plan. We do not propose to modify any existing obligation for an 

incumbent transmission owner to build unsponsored projects that are identified as 

necessary in a regional transmission plan.101 In addition, where an incumbent 

transmission owner has the right to build, own, and recover costs for upgrades to its own 

existing transmission facilities (e.g., tower change out and reconductoring), such right 

would not be affected by the reforms proposed here. 

98. We also emphasize that these proposed reforms would affect only a right of first 

refusal established in a transmission provider’s OATT or agreements subject to the 

 101 For example, in some RTO and ISO regions, transmission owners have 

obligations to build certain transmission facilities identified by the RTO or ISO. As new 

transmission owners, including nonincumbent transmission owners, join the RTO or ISO, 

they will incur the obligations accompanying that status in the RTO or ISO’s tariff and 

other governing documents. We note that provisions imposing such obligations may 

need to be modified to reflect how they will apply to nonincumbent transmission project 

developers. We also note that before turning to a transmission owner with such an 

obligation, the RTO or ISO could conduct a competitive bidding process to assign 

construction rights for an unsponsored project in its regional transmission plan. 
Docket No. RM10-23-000 - 57 - 

Commission’s jurisdiction. This Proposed Rule does not address, propose to change, or 

seek to preempt any state or local laws or regulations. 

99. Finally, we do not propose here to require a transmission developer that does not 

seek to use the regional cost allocation process to participate in the regional transmission 

planning process, as some commenters recommend. For example, because a merchant 

transmission developer assumes all financial risk for developing its project and 

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

participate in a regional transmission planning process for purposes of identifying the 

beneficiaries of its project or securing eligibility to use a regional cost allocation method. 

A developer that does not seek to use the regional cost allocation process nevertheless 

would be required to comply with all reliability requirements applicable to facilities in 

the transmission planning region in which its project would be located. In addition, such 

a developer is not prohibited from participating—and, indeed, is encouraged to 

participate—in the regional transmission planning process. 

100. As discussed above, in response to the October 2009 Notice, many commenters 

link the right of first refusal for an incumbent utility to its obligation to construct new 

facilities if called upon to do so. While the Commission acknowledges these comments, 

we preliminarily find that these two practices are not, and should not be, linked within 

regional transmission planning processes. That is, while a public utility transmission 

owner may have accepted an obligation to build in relation to its membership in an RTO 

or ISO, this obligation is not directly dependent on that transmission provider having a 

corresponding right of first refusal with regard to a proposal to construct and own a new 
Docket No. RM10-23-000 - 58 - 

transmission facility located in that region. What is important from the Commission’s 

perspective is that the documents approved by the Commission must not be unduly 

discriminatory. The Commission preliminarily finds that neither incumbent nor 

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

approved OATT or agreement, receive different treatment in the transmission planning 

and selection process, and both should share similar benefits and obligations 

commensurate with that participation. 

101. We seek comment on how the reforms proposed in this section of the Proposed 

Rule would affect the rights, obligations, and responsibilities of incumbent and 

nonincumbent transmission providers. In particular, we seek comment on the 

relationship or lack of relationship between a right of first refusal and an obligation to 

build. We also seek comment on whether it would be appropriate to retain a federal right 

of first refusal in an OATT or other documents subject to the Commission’s jurisdiction. 

If not, why not? If so, would it be appropriate to retain an obligation to build for an 

incumbent transmission provider while removing a federal right of first refusal for that 

incumbent? 

D. Interregional Coordination 

1. The Need for Interregional Planning Reforms

102. As discussed above, the transmission planning principles established in Order Nos. 

890 and 890-A establish a framework for transmission planning at the local and regional 

levels. In Order No. 890-A, the Commission emphasized that effective regional planning 

should include coordination among regions. Further, the Commission stated that regions 
Docket No. RM10-23-000 - 59 - 

and subregions should coordinate as necessary to share data, information and 

assumptions to maintain reliability and allow customers to consider the resource options 

that span the regions.102 In several of the Order No. 890 compliance orders, the 

Commission requested more detailed information regarding compliance with this aspect 

of the regional participation principle.103 

103. Within that Order No. 890 and 890-A framework, transmission providers in 

certain parts of the country have organized subregional transmission planning groups for 

the purpose of collectively developing plans for upgrades on their combined transmission 

systems. These subregional transmission plans are then analyzed at a regional level to 

ensure that, if implemented, they will be simultaneously feasible and meet reliability 

requirements.104 Additionally, some neighboring transmission providers have undertaken 

joint transmission planning pursuant to bilateral agreements.105 However, as observed in 

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

103 See, e.g., Southern Co. Servs., Inc.; 124 FERC ¶ 61,265, at P 70 (2008); United 

States Department of Energy – Bonneville Power Administration, 124 FERC ¶ 61,054, at 

P 65 (2008); Southwest Power Pool, Inc., 124 FERC ¶ 61,028, at P 49 (2008).

104 Such analysis is consistent with one aspect of the Regional Participation 

transmission planning principle that the Commission established in Order No. 890. On 

that issue, the Commission stated: “[I]n addition to preparing a system plan for its own 

control area on an open and nondiscriminatory basis, each transmission provider will be 

required to coordinate with interconnected systems to: (1) share system plans to ensure 

that they are simultaneously feasible and otherwise use consistent assumptions and data, 

and (2) identify system enhancements that could relieve congestion of integrate new 

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

105 See, e.g., Joint Operating Agreement Between the Midwest Independent 

Transmission System Operator, Inc. and PJM Interconnection, L.L.C. (Midwest 

Independent Transmission System Operator, Inc., Second Revised Rate Schedule FERC 

No. 5; PJM Interconnection, L.L.C. Second Revised Rate Schedule FERC No. 38). 
Docket No. RM10-23-000 - 60 - 

the October 2009 Notice, there are few processes in place to analyze whether alternative 

interregional solutions would more efficiently or effectively meet the needs identified in 

individual regional transmission plans.106

104. The October 2009 Notice posed several questions related to this issue, including 

whether existing transmission planning processes are adequate to identify and evaluate 

potential solutions to needs affecting the systems of multiple transmission providers. The 

October 2009 Notice also sought comment as to what processes should govern the 

identification and selection of projects that affect multiple systems.107

105. In response to the October 2009 Notice, some commenters state that the need for 

supplemental interregional transmission planning processes cannot be evaluated until 

stakeholders gain more experience with the regional transmission planning processes 

conducted pursuant to Order No. 890, and thus oppose Commission action on this issue at 

this time.108 Other commenters state that the lack of interregional planning is a 

considerable problem and that transmission planning could be enhanced by increasing the 

amount of coordination that occurs between neighboring transmission planning 

regions.109 

 

(continued)

106 October 2009 Notice at 2. 

107 Id. at 3. 

108 E.g., American Transmission, Consolidated Edison, et al., Dominion, Eastern 

Interconnection Planning Collaborative Analysis Team, Imperial Irrigation District, New 

York ISO, Public Power Council, South Carolina Electric & Gas, and Southern 

Companies. 

109 E.g., Duke, Exelon, NextEra, Ohio Commission, Old Dominion, Organization 

of MISO States, PSEG Companies, Transmission Access Policy Study Group, and 
Docket No. RM10-23-000 - 61 - 

106. More specifically, several commenters advocate expansion of interregional 

transmission planning, but disagree as to the extent to which interregional coordination 

should be institutionalized. Proposals range from requiring regional transmission 

planning entities to comply with Order No. 890 transmission planning principles,110 to 

requiring greater coordination among existing transmission planning regions,111 to 

expanding the authorities of regional transmission planning entities.112 Some 

commenters suggest that the Commission should require interregional transmission 

planning or develop pro forma seams agreements that describe the requirements for 

coordinating transmission planning with a neighboring transmission planning region.113 

107. San Diego Gas & Electric, for example, states that, in the West, transmission 

planning is a hodgepodge of balkanized processes resulting in a flood of proposed 

interstate transmission facilities but with virtually no consideration given to which of the 

proposed facilities would be most effective in meeting the needs of the broadest set of 

constituents. San Diego Gas & Electric also states that little serious consideration is 

 

Transmission Dependent Utility Systems. 

110 E.g., Old Dominion. 

111 E.g., AWEA, Pioneer Transmission, PSEG Companies, Public Interest 

Organizations & Renewable Energy Groups, Transmission Access Policy Study Group, 

and Transmission Dependent Utility Systems. 

112 Regional transmission planning entities would be empowered “to make specific 

project recommendations at the end of the planning process and to enter binding, nearjuridical findings of fact and conclusions related to the need and economic benefits of 

specific projects or solutions.” San Diego Gas & Electric at 6. 

113 E.g., AEP, Energy Future Coalition, Old Dominion, Pioneer Transmission, 

Public Interest Organizations & Renewable Energy Groups, SPP, Transmission Access 

Policy Study Group, and Transmission Dependent Utility Systems. 
Docket No. RM10-23-000 - 62 - 

given to how various project proposals could be modified, combined, or eliminated so as 

to make the best possible use of available transmission corridors, minimize adverse 

environmental impacts, and enhance overarching system efficiencies.114 

108. Pioneer Transmission states that it has a unique perspective on interregional 

transmission planning issues, as it spent the last year and a half working with the 

Midwest ISO and PJM in an effort to develop extra high voltage transmission facilities 

that will be located in both the Midwest ISO and PJM footprints. Pioneer Transmission 

states that although the Midwest ISO and PJM have undertaken various studies and have 

worked cooperatively with Pioneer Transmission, they have been hampered in their 

efforts to assess the Pioneer project for inclusion in their transmission plans because 

neither RTO has in place formal procedures for evaluating interregional projects.115

109. The Ohio Commission states in its comments that “[j]ust as the development of 

RTOs and ISOs was encouraged to better coordinate individual transmission owners’ and 

operators’ plans, the development of inter-regional planning committees to review and 

coordinate individual and RTO and ISO plans should be encouraged.”116 The California 

ISO states that it would be easier to analyze and justify transmission facilities that would 

be located in more than one region if the underlying data were consistent in all of the 

areas that are part of evaluating the transmission project in question.117 Similarly, Public 

 114 San Diego Gas & Electric at 5. 

115 Pioneer Transmission at 1-2. 

116 Ohio Commission Comments at 6. 

117 California ISO at 8. 
Docket No. RM10-23-000 - 63 - 

Interest Organizations & Renewable Energy Groups state that the Commission should 

require coordinated transmission infrastructure plan development by regional or 

interregional transmission planning authorities informed by interconnection-wide 

assessments and broad stakeholder input. 

110. The October 2009 Notice also recognized that proposals to implement 

interconnectionwide transmission planning were being developed in response to the 

above-noted funding opportunities that DOE offered under the American Recovery and 

Reinvestment Act of 2009. The October 2009 Notice observed that it was not clear 

whether those activities would result in a regular process for jointly identifying and 

evaluating alternatives to solutions identified in transmission plans developed through 

existing transmission planning processes conducted in accordance with Order No. 890.118

111. In response to the October 2009 Notice, some commenters state that 

interconnectionwide transmission planning undertaken pursuant to the ARRA should be 

given a chance to mature before the Commission takes additional action with respect to 

transmission planning.119 Other commenters emphasize that funding under the ARRA is 

an important one-time opportunity, but should not be viewed as a prerequisite for 

initiating or expanding upon other transmission planning efforts.120 For example, Exelon 

states that the ARRA-funded transmission planning for the Eastern Interconnection is a 

 118 October 2009 Notice at 2-3. 

119 E.g., ColumbiaGrid, NARUC, New England States’ Committee on Electricity, 

and Organization of MISO States. 

120 E.g., Eastern Interconnection Planning Collaborative Analysis Team, Entergy, 

and Progress Energy. 
Docket No. RM10-23-000 - 64 - 

positive effort, but is aimed at evaluating what would happen under various scenarios 

rather than at evaluating solutions and identifying the best solution for any given 

transmission planning problem. AWEA states that the Commission should not rely on 

interconnectionwide transmission planning undertaken pursuant to the ARRA as the sole 

means for reforming the transmission planning process because the ARRA-funded efforts 

cannot be expected to lead to the near-term changes that need to be implemented in order 

to support development of renewable energy resources. 

112. The Commission supports and encourages the interconnectionwide transmission 

planning efforts being undertaken pursuant to the ARRA. As noted above, broad 

participation in sessions to date related to these efforts suggests that that the availability 

of federal funds to pursue interconnectionwide transmission planning has increased 

awareness of the potential for greater coordination among regions in transmission 

planning. The Commission anticipates that the ARRA-funded efforts will enhance 

transmission planning by, among other actions, building upon local and regional 

transmission planning processes and improving capabilities to model the development of 

transmission enhancements for the various scenarios of interest to state and federal policy 

makers and other stakeholders, as well as Canadian provincial policy makers in the 

Western Interconnection. We emphasize that this Proposed Rule, which does not require 

interconnectionwide planning or cost allocation, is not intended to interfere with the 

efforts already underway in ARRA-funded transmission planning initiatives. 

113. However, even with these important steps toward interconnection-wide scenario 

analysis, the Commission remains concerned that the lack of coordinated transmission 
Docket No. RM10-23-000 - 65 - 

planning processes across the seams of neighboring transmission planning regions could 

be needlessly increasing costs for customers of transmission providers. These 

circumstances may result in transmission rates that are unjust and unreasonable. 

Therefore, the Commission proposes reforms that are intended to improve coordination 

between neighboring transmission planning regions with respect to facilities that are 

proposed to be located in both regions, as well as interregional facilities that could 

address transmission needs more efficiently than separate intraregional facilities. 

2. Proposed Interregional Planning Reforms

114. We propose to require each public utility transmission provider through its 

regional transmission planning process to coordinate with the public utility transmission 

providers in each of its neighboring transmission planning regions within its 

interconnection to address transmission planning issues, as discussed below.121 This 

coordination between transmission planning regions must be reflected in an interregional 

transmission planning agreement to be filed with the Commission. 

115. The interregional transmission planning agreement may be developed on behalf of 

the public utility transmission providers within multiple transmission planning regions. 

For example, two RTOs may set forth the requirements of their interregional transmission 

planning coordination as part of an overall joint operating agreement between them. A 

public utility transmission provider that is not in an RTO or ISO may, for example, work 

 121 This proposal does not require a public utility transmission provider to enter 

into an interregional transmission planning agreement with a neighboring transmission 

planning region in another interconnection. 
Docket No. RM10-23-000 - 66 - 

with other transmission providers that participate in its regional transmission planning 

process to create and enter into a multilateral interregional transmission planning 

agreement with transmission providers in a neighboring transmission planning region. 

Although not required under this proposal, we encourage public utility transmission 

providers to explore possible multilateral interregional transmission planning agreements 

among several, or even all, regions within an interconnection, building on processes 

developed through the ARRA-funded transmission planning initiatives. We note that 

multilateral interregional transmission planning agreements may minimize the growing 

number of planning meetings that some stakeholders suggest pose barriers to their 

meaningful participation in the planning processes, given their limited resources. 

116. The interregional transmission planning agreement must include a detailed 

description of the process for coordination between public utility transmission providers 

in neighboring transmission planning regions with respect to facilities that are proposed 

to be located in both regions, as well as interregional facilities that are not proposed but 

that could address transmission needs more efficiently than separate intraregional 

facilities. 

117. While the Commission encourages every interregional transmission planning 

agreement to be tailored to best fit the needs of the regions entering into the agreement, 

there are certain elements that we propose each public utility transmission provider must 

ensure are included in any interregional transmission planning agreement in which it 

participates. Including these elements will help to ensure a proactive, comprehensive 

process. Specifically, we propose that an interregional transmission planning agreement 
Docket No. RM10-23-000 - 67 - 

must include: (1) a commitment to coordinate and share the results of respective regional 

transmission plans to identify possible interregional facilities that could address 

transmission needs more efficiently than separate intraregional facilities; (2) an 

agreement to exchange at least annually planning data and information; (3) a formal 

procedure to identify and jointly evaluate transmission facilities that are proposed to be 

located in both regions; and (4) a commitment to maintain a website or e-mail list for the 

communication of information related to the coordinated planning process. 

118. With respect to the third proposed requirement for an interregional transmission 

planning agreement, the Commission proposes that the sponsor of a project that would be 

located in both transmission planning regions to which that agreement applies must first 

propose its project in the transmission planning process of each of those transmission 

planning regions. The Commission further proposes that such a submission would 

trigger a procedure established by the interregional transmission planning agreement, 

under which the transmission planning regions would coordinate their reviews of and 

jointly evaluate the proposed project. The Commission proposes that such coordination 

and joint evaluation must be conducted in the same general timeframe as, rather than 

subsequent to, each transmission planning region's individual consideration of the 

proposed project. Finally, the Commission proposes that inclusion of the interregional 

transmission project in each of the relevant regional transmission plans would be a 

prerequisite to application of an interregional cost allocation method that satisfies the cost 

allocation principles proposed below in this NOPR. 
Docket No. RM10-23-000 - 68 - 

119. We seek comment on any issue of interest or concern related to the requirements 

proposed in this section of the Proposed Rule, including the proposed required elements 

of an interregional transmission planning agreement and any other elements that should 

be part of an interregional transmission planning agreement. In particular, we seek 

comment on how such an agreement would be implemented in non-RTO or ISO regions 

and on the impact that an interregional transmission planning agreement would likely 

have on the development of interregional transmission facilities. 

120. We recognize that development of interregional transmission planning agreements 

would take time and would necessarily depend on progress at the regional level. 

Accordingly, the Commission proposes to require the interregional transmission planning 

agreements to be submitted to the Commission no later than one year after the effective 

date of the final rule issued in this proceeding. 

V. Proposed Reforms: Cost Allocation

A. Introduction

1. Order No. 890’s Transmission Planning Principle on Cost 

Allocation for New Transmission Facilities 

121. In Order No. 890, the Commission found that there is a close relationship between 

transmission planning, which identifies needed transmission facilities, and the allocation 

of costs of the transmission facilities in the plan. The Commission stated that knowing 

how the costs of new transmission facilities would be allocated is critical to the 

development of new infrastructure, because transmission providers and customers cannot 
Docket No. RM10-23-000 - 69 - 

be expected to support the construction of new transmission unless they understand who 

will pay the associated costs.122 

122. In light of this close relationship, the Commission included a principle entitled 

“Cost Allocation for New Projects” among the Order No. 890 transmission planning 

principles. The Commission stated that the Order No. 890 Cost Allocation principle was 

intended to apply to projects that did not fit under existing cost allocation methods. As 

examples of such projects, the Commission cited regional projects involving several 

transmission owners and economic projects that are identified pursuant to the Order 

No. 890 economic planning studies principle for transmission planning, rather than 

through individual requests for transmission service.123 

123. The Commission did not impose a particular cost allocation method in Order 

No. 890, but instead permitted public utility transmission providers, customers, and other 

stakeholders to determine a method that would be appropriate given the needs of the 

region. While allowing this flexibility among regions, the Commission also stated that 

providing some overall guidance on the issue was appropriate. The Commission stated 

that when considering a dispute over cost allocation, it would exercise its judgment by 

weighing several factors. First, the Commission stated that it would consider whether a 

cost allocation proposal fairly assigns costs among participants, including those who 

cause the costs to be incurred and those that otherwise benefit from them. Second, the 

 122 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 557. 

123 Id. P 558. 
Docket No. RM10-23-000 - 70 - 

Commission stated that it would consider whether a cost allocation proposal provides 

adequate incentives to construct new transmission. Third, the Commission stated that it 

would consider whether the proposal is generally supported by state authorities and 

participants across the region.124

124. The Commission also stated that these factors are particularly important as applied 

to economic projects that are identified pursuant to the Order No. 890 economic planning 

studies principle for transmission planning, such as upgrades to reduce congestion or 

enable groups of customers to access new generation. The Commission stated that, as a 

general matter, the beneficiaries of any such project should agree to support its costs. 

The Commission recognized, however, that there are free rider problems associated with 

new transmission investment, such that customers who do not agree to support a 

particular project may nonetheless receive substantial benefit from it. The Commission 

also stated that a range of solutions to free rider problems is available, noting that 

different regions have attempted to address those problems in a variety of ways.125 

125. To comply with the cost allocation principle, the Commission directed each public 

utility transmission provider to clearly define the details of its cost allocation method as 

part of a new attachment to its OATT. The Commission stated that each proposal should 

identify the types of new projects that are not covered under previously existing cost 

 124 Id. P 559. 

125 Id. P 561 (“[D]ifferent regions have attempted to address such issues in a 

variety of ways, such as by assigning transmission rights only to those who financially 

support a project or spreading a portion of the cost of certain high-voltage projects more 

broadly than the immediate beneficiary/supporters of the project.”). 
Docket No. RM10-23-000 - 71 - 

allocation methods and, therefore, would be affected by the Order No. 890 cost allocation 

principle.126 The Commission also stated that it is important that each region address 

these cost allocation issues up front, at least in principle, rather than having them 

relitigated each time a project is proposed.127 The Commission explained that up-front 

identification of how the cost of a facility will be allocated will allow transmission 

providers, customers, and potential investors to make the decision whether or not to build 

that facility on an informed basis.128 

126. After several rounds of compliance filings, the Commission approved various 

public utility transmission providers’ proposals pursuant to the cost allocation principle. 

The Commission found that the proposals adequately identified both the types of new 

projects that were not covered under previously existing cost allocation methods and new 

methods for allocating the cost of those projects. 

127. Particularly in transmission planning regions outside of the RTO and ISO 

footprints, many of the cost allocation methods that the Commission accepted in the 

Order No. 890 compliance proceedings rely exclusively on a “participant funding” 

approach to cost allocation. Under a participant funding approach to cost allocation, the 

 126 Id. P 558. 

127 Id. P 561. 

128 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 251. The Commission 

also stated that neither adoption of a cost allocation method nor identification of an 

upgrade (whether driven by reliability or economics) in a transmission plan triggers an 

obligation to build. Id. 
Docket No. RM10-23-000 - 72 - 

costs of a new transmission facility are allocated only to entities that volunteer to bear 

those costs. 

128. For example, El Paso Electric proposed in its Order No. 890 compliance filing to 

use a cost allocation method in which such entities would share the costs proportionally 

based on each participant’s desired use of the facility to be constructed.129 Other 

members of WestConnect, such as Public Service Company of Colorado, filed and now 

use similar participant funding cost allocation methods.130 South Carolina Electric & Gas 

included in its Order No. 890 compliance filing the Southeast Inter-Regional 

Participation Process (SIRPP) provisions stating that costs for economics-driven 

upgrades will be born entirely by the transmission owner that builds the facilities.131 

Similarly, Entergy filed and had approved a method where the costs for projects 

developed under its Regional Planning Process and its interregional transmission 

planning process would be born by the party that constructs the facilities.132 

ColumbiaGrid and the Northern Tier Transmission Group both utilize a study committee 

process whereby alternative cost allocation methods can be proposed for projects within 

their respective regions.133 However, both ColumbiaGrid and Northern Tier 

 129 El Paso Electric Company, 124 FERC ¶ 61,051, at P 44 (2008). 

130 Xcel Energy Services, Inc. - Public Service Company of Colorado, 124 FERC 

¶ 61,052 (2008). 

131 South Carolina Electric & Gas Company, 127 FERC ¶ 61,275, at P 50 (2009). 

132 Entergy Services, Inc., 127 FERC ¶ 61,272 (2009). 

133 See Avista Corporation, 128 FERC ¶ 61,065 (2009) and Idaho Power 

Company, 128 FERC ¶ 61,064 (2009). 
Docket No. RM10-23-000 - 73 - 

Transmission Group use a process where, if no agreement on cost allocation among the 

study team participants or the project proponents is obtained, the entities requesting the 

project will bear the costs. 

2. October 2009 Notice and Subsequent Comments

129. As discussed above, in the October 2009 Notice, the Commission posed a number 

of questions with respect to allocating the cost of transmission facilities. Those questions 

drew wide-ranging responses as to whether further Commission action on cost allocation 

is needed at this time and, if so, what that action should be. 

130. Among the commenters, there is general agreement that the Commission should 

not supersede existing, ongoing processes in various parts of the country that are 

attempting to address regional and interregional cost allocation issues. 

131. Nonetheless, commenters supporting further Commission action on cost allocation 

at this time generally assert that the Commission should provide more detailed guidelines 

or principles for allocating the costs of new transmission facilities.134 Many commenters 

argue that a clear path to cost recovery is necessary for a new transmission project to 

move beyond the evaluation stage and to be included in any regional transmission 

planning process and ultimately to proceed to construction.135 Such commenters indicate 

that risks associated with cost recovery—together with the risks associated with 

 134 E.g., APPA, National Rural Electric Coops, Transmission Access Policy Study 

Group, Transmission Dependent Utility Systems, and California ISO. 

135 E.g., American Transmission, AWEA, E.ON Climate & Renewables North 

America, Energy Future Coalition, and NextEra.
Docket No. RM10-23-000 - 74 - 

permitting and siting—are among the most significant obstacles to the construction of a 

new transmission facility, especially if customers that are allocated costs do not perceive 

that they will benefit from the proposed facility.136 Old Dominion emphasizes that many 

of the obstacles inhibiting transmission development are interrelated, but that greater 

certainty on cost allocation would likely ease access to capital for proposed facilities.137

132. Several commenters specifically address cost allocation as an impediment to the 

development of generation to satisfy renewable portfolio standards implemented by the 

states.138 AWEA, for example, states that cost allocation policies are the biggest 

impediment to construction of new transmission facilities, regardless of location, and that 

costs should be assigned to all entities that benefit from a new facility. AWEA further 

comments that a participant funding cost allocation method does not achieve that goal.139 

These commenters also state that uncertainty over cost allocation imposes significant 

costs on customers attempting to export energy from renewable resources and inhibit 

planning for the integration of the most economic generation resources into the 

transmission grid. Maine PUC and Public Advocate state that the existing ISO-NE cost 

 136 E.g., AWEA, Transmission Dependent Utility Systems, Xcel, Transmission 

Access Policy Study Group, and National Rural Electric Coops. 

137 Old Dominion at 26. 

138 E.g., AWEA at 9-10, American Transmission and Exelon. 

139 AWEA at 4. See also Transmission Access Policy Study Group at 25-27. 
Docket No. RM10-23-000 - 75 - 

allocation methods are not optimal when considering large amounts of wind 

integration.140

133. Similarly, the majority of commenters that address cost allocation for large, 

interregional transmission facilities agree that the Commission should provide more 

guidance on cost allocation.141 Some commenters complain that as a general matter, the 

Commission has addressed cost allocation methods only for facilities within the footprint 

of a single transmission provider or a single RTO or ISO, and not for interregional 

projects. For example, AEP states that it has experienced delays in developing 

transmission facilities that cross RTO boundaries as a result of uncertainty over cost 

allocation, as well as difficulties with how the facilities are to be planned. 

134. Some of these commenters assert that the expansion of regional power markets 

and the increasing adoption by state governments of renewable energy requirements have 

led to a growing need for new transmission facilities that cross several utility and/or RTO 

or ISO regions. These commenters generally support, or state that they do not oppose, 

the Commission establishing a process to help stakeholders address cost allocation 

matters over larger geographic areas. For example, California ISO and the California 

Commission comment that, although cost allocation within the California ISO works 

well, they support the Commission creating a process to consider cost allocation over a 

larger region in the West. 

 140 Maine PUC and Public Advocate at 7-8. 

141 E.g., AEP, ITC Holdings, and Exelon. 
Docket No. RM10-23-000 - 76 - 

135. In addition, the comments in response to the October 2009 Notice reflect a general 

consensus that those who share in the benefits of transmission projects should also share 

in their costs. However, there is no consensus on what types of benefits should be 

considered or how such benefits should be calculated. Certain commenters, for example, 

support recognition of a broad spectrum of benefits that may stem from transmission 

development, such as environmental impacts, land conservation and energy security.142 

Other commenters urge the Commission to avoid a uniform approach to determining the 

benefits of transmission projects.143 

136. Several commenters suggest that if the Commission decides to establish a default 

cost allocation method for new transmission facilities, such a method should be employed 

and enforced only when stakeholders are unable to agree upon their own regional cost 

allocation method or methods.144 For example, American Transmission, National Grid, 

Northern Tier Transmission Group, and NEPOOL Participants state that the Commission 

could create a generic cost allocation method as a backstop, which would apply when 

parties or regions could not come to their own agreement. Other commenters express the 

 142 E.g., AEP, AWEA, Baltimore Gas and Electric, Energy Future Coalition, 

Green Energy Express, ITC Holdings, MidAmerican, National Audubon Society, 

NextEra, and Public Interest Organizations & Renewable Energy Groups. 

143 E.g., ColumbiaGrid, ConEd, Delaware Municipal and Southwestern Electric, 

and Northeast Utilities. 

144 E.g., American Transmission, National Grid, Northern Tier Transmission 

Group, and NEPOOL Participants. 
Docket No. RM10-23-000 - 77 - 

view that the Commission should create one or more rebuttable presumptions about who 

benefits from various types of facilities in order to make cost allocation easier.145 

137. Finally, many commenters state that no further generic Commission action on cost 

allocation is needed at this time because the processes in their own regions already 

address, or are now working to address, cost allocation. For example, in the Southeast, 

some commenters state that their processes for cost allocation are working well and argue 

that the Commission should continue to allow regional flexibility on cost allocation 

processes.146 Similarly, in the West, some commenters state that cost allocation in their 

region is not a problem.147 

B. Legal Authority and Need for Reform 

138. Based on the comments received in response to the October 2009 Notice, the 

Commission believes that further reform with respect to transmission cost allocation 

methods may be necessary in order to ensure that the rates, terms and conditions of 

transmission service in interstate commerce are just and reasonable and not unduly 

discriminatory or preferential. 

1. The Cost Causation Principle

139. Under sections 205 and 206 of the FPA, the Commission is responsible for 

ensuring that the rates, terms, and conditions for transmission of electricity in interstate 

 145 E.g., ITC Holdings, MidAmerican, PJM, Solar Energy Industries, and WIRES. 

146 E.g., Entergy, Southern Companies, and Florida Transmission Providers. 

147 E.g., ColumbiaGrid, Northern Tier Transmission Group, Transmission Agency 

of Northern California, Salt River Project and WestConnect Planning Parties. 
Docket No. RM10-23-000 - 78 - 

commerce are just, reasonable, and not unduly discriminatory or preferential.148 With 

respect to this responsibility, the Commission and the courts have found that the costs of 

jurisdictional transmission facilities must be allocated in a manner that satisfies the “cost 

causation” principle. 

140. The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) has 

defined the cost causation principle as follows: “[I]t has been traditionally required that 

all approved rates reflect to some degree the costs actually caused by the customer who 

must pay them.”149 The U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit) 

recently quoted and elaborated on that definition, stating, “All approved rates must reflect 

to some degree the costs actually caused by the customer who must pay them. Not 

surprisingly, we evaluate compliance with this unremarkable principle by comparing the 

costs assessed against a party to the burdens imposed or benefits drawn by that party. To 

the extent that a utility benefits from the costs of new facilities, it may be said to have 

‘caused’ a part of those costs to be incurred, as without the expectation of its 

contributions the facilities might not have been built, or might have been delayed.”150 

 148 16 U.S.C. 824d, 824e. 

149 K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) (K N Energy). 

150 Illinois Commerce Comm’n v. FERC, 576 F.3d 470, 476 (7th Cir. 2009) (Illinois 

Commerce Commission) (citing K N Energy, 968 F.2d at 1300; Transmission Access 

Policy Study Group v. FERC, 225 F.3d 667, 708 (D.C. Cir. 2000); Pacific Gas & Elec. 

Co. v. FERC, 373 F.3d 1315, 1320-21 (D.C. Cir. 2004); Midwest ISO Transmission 

Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) (Midwest ISO Transmission 

Owners); Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009); Sithe/Independence 

Power Partners, L.P. v. FERC, 285 F.3d 1, 4-5 (D.C. Cir. 2002) (Sithe); 16 U.S.C. 

824d). 
Docket No. RM10-23-000 - 79 - 

The Commission has frequently made similar statements with respect to the cost 

causation principle. For example, as noted above, the Commission stated in Order 

No. 890 that one factor it weighs when considering a dispute over cost allocation is 

whether a cost allocation proposal fairly assigns costs among participants, including those 

who cause the costs to be incurred and those that otherwise benefit from them.151 

141. In applying the cost causation principle, the Commission has generally allocated 

costs to beneficiaries that have entered a voluntary arrangement with the public utility 

that is seeking to recover those costs. One example of a voluntary cost recovery 

arrangement with a public utility is voluntary membership in an RTO or ISO that makes 

an entity subject to the cost allocation provisions of the RTO’s or ISO’s tariff.152 The 

Commission also has permitted joint-ownership agreements where the owners share the 

costs of the new transmission facilities. 

142. The cost causation principle, however, is not limited to voluntary arrangements. 

Indeed, if the Commission were limited to allocating costs only to beneficiaries that 

voluntarily accept those costs, then the Commission could not fulfill its responsibilities 

under the FPA. If the Commission could not address free rider problems associated with 

new transmission investment, then it could not ensure that transmission rates are just and 

reasonable and not unduly discriminatory. The cost causation principle provides that 

costs should be allocated to those who cause them to be incurred and those that otherwise 

 151 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 559. 

152 The Commission notes that RTO or ISO membership does not eliminate the 

need to satisfy the other aspects of the cost causation principle that are discussed above. 
Docket No. RM10-23-000 - 80 - 

benefit from them, as the Commission also recognized in Order No. 890. In other words, 

the Commission may determine that an entity’s status as a beneficiary of a transmission 

facility identified through an appropriate process is relevant for purposes of applying the 

cost causation principle, even if that beneficiary has not entered a voluntary arrangement 

with (e.g., as a customer of) the public utility that is seeking to recover the costs of that 

facility. 

143. The Commission has expressed a willingness to make such a determination. For 

example, when presented with concerns about parallel path flow,153 the Commission has 

offered repeatedly that if a public utility can demonstrate that a transaction is a burden on 

its system, then that utility can propose a transmission service rate for Commission 

consideration that would account for the unauthorized use of its system.154 The 

Commission has cautioned against the hasty submittal of such unilateral filings, 

describing its general policy as expecting owners and controllers of transmission facilities 

 153 The Commission has described the phenomenon of parallel path flow as 

follows: “In general, utilities transact with one another based on a contract path concept. 

For pricing purposes, parties assume that power flows are confined to a specified 

sequence of interconnected utilities that are located on a designated contract path. 

However, in reality power flows are rarely confined to a designated contract path. 

Rather, power flows over multiple parallel paths that may be owned by several utilities 

that are not on the contract path. The actual power flow is controlled by the laws of 

physics which cause power being transmitted from one utility to another to travel along 

multiple parallel paths and divide itself along the lines of least resistance. This parallel 

path flow is sometimes called ‘loop flow.’” Indiana Michigan Power Co. and Ohio 

Power Co., 64 FERC ¶ 61,184, at 62,545 (1993). 

154 See, e.g., Amer. Elec. Power Svc. Corp., 49 FERC ¶ 61,377, at 62,381 (1989). 
Docket No. RM10-23-000 - 81 - 

to attempt to resolve parallel path flow issues on a consensual, regional basis.155 

Nonetheless, if approved by the Commission, such a proposal to address parallel path 

flow would allow a public utility to recover costs from a beneficiary of its system in the 

absence of a voluntary arrangement between the utility and that beneficiary. 

144. The Commission also affirmatively required costs of transmission facilities to be 

allocated to beneficiaries in the absence of a voluntary arrangement in a series of orders 

involving the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) 

and PJM Interconnection, L.L.C. (PJM). Specifically, the Commission directed Midwest 

ISO and PJM to develop cost allocation methods for new facilities in one of their 

footprints that benefit entities in the other’s footprint.156 Echoing precedent applying the 

cost causation principle, the Commission later conditionally accepted a proposal that 

Midwest ISO and PJM submitted in compliance with that directive on the grounds that it 

“more accurately identifies the beneficiaries and allocates the associated costs” than did 

the cost allocation methods that were previously in place.157

 

(continued)

155 Id. See also Southern California Edison Co., 70 FERC ¶ 61,087, at 61,241-42 

(1995). 

156 Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ¶ 61,168, at P 60 

(2004) (citing Midwest Indep. Transmission Sys. Operator, Inc., 106 FERC ¶ 61,251, at 

P 56-57 (2004)). The Commission noted that Midwest ISO and PJM had committed in a 

Joint Operating Agreement to develop such a method for allocating the costs of certain 

facilities through their joint regional planning committee. Id. The Commission did not 

base the above-noted directive on the existence of the Joint Operating Agreement, which 

Midwest ISO and PJM developed in order to comply with a previous Commission 

directive. See Alliance Cos., 100 FERC ¶ 61,137, at P 48, 53 (2002). 

157 Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC ¶ 61,194, at P 10 

(2005). See also Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,084 
Docket No. RM10-23-000 - 82 - 

145. These examples show that the Commission has asserted its authority to allocate 

the costs of jurisdictional facilities to beneficiaries whether or not those beneficiaries 

have entered into a voluntary agreement with the public utility that is seeking to recover 

those costs. 

146. In addition, courts have affirmed that the cost causation principle allows the 

Commission to allocate at least some types of costs to beneficiaries that are not customers 

of the public utility that is seeking to recover the costs in question. For example, the D.C. 

Circuit addressed this issue in a case that involved a proposal for Midwest ISO to recover 

administrative costs through a charge that would apply to transmission loads subject to 

the Midwest ISO’s tariff rates: i.e., new wholesale loads and unbundled retail loads, but 

not bundled retail loads and loads served pursuant to grandfathered contracts.158 

Describing the core issue as whether the Commission’s orders comported with the cost 

causation principle, the D.C. Circuit found that the Commission reasonably allocated the 

administrative costs more broadly than Midwest ISO proposed.159 After stating that the 

subject costs were the administrative costs of having an ISO, the D.C. Circuit found that 

 

(2008); Midwest Indep. Transmission Sys. Operator, Inc., 129 FERC ¶ 61,102 (2009). 

158 Midwest ISO Transmission Owners, 373 F.3d 1361. The D.C. Circuit stated 

that the subject costs “are primarily MISO’s startup expenses – particularly those 

pertaining to the MISO Security Center – and certain expenses pertaining to the creation 

and administration of MISO’s open access tariff.” Id. at 1369. 

159 Id. at 1370. 
Docket No. RM10-23-000 - 83 - 

the Commission correctly determined that bundled and grandfathered loads should share 

the cost of having an ISO because they drew benefits from Midwest ISO.160

147. Thus, in applying the cost causation principle, the Commission may allocate costs 

of a transmission facility to a beneficiary identified through an appropriate process, such 

as a Commission-approved transmission planning process, even if that beneficiary has 

not entered a voluntary arrangement with the public utility that is seeking to recover the 

costs of that facility. After satisfying this standard with respect to beneficiary 

identification, the cost causation principle also requires the Commission to ensure that the 

costs allocated to a beneficiary under a cost allocation method are at least roughly 

commensurate with the benefits that are expected to accrue to that entity.161 On this 

point, the D.C. Circuit has explained that “the cost causation principle does not require 

exacting precision in a ratemaking agency’s allocation decisions.”162 

2. Need for Reform

148. The Commission’s responsibility under FPA sections 205 and 206 to ensure that 

transmission rates are just and reasonable and not unduly discriminatory or preferential is 

not new, nor is the Commission’s recognition of the cost causation principle. However, 

 160 Id. at 1370-71. 

161 Illinois Commerce Commission, 576 F.3d at 476-77 (“We do not suggest that 

the Commission has to calculate benefits to the last penny, or for that matter to the last 

million or ten million or perhaps hundred million dollars.”). See also Midwest ISO 

Transmission Owners, 373 F.3d 1361 at 1369 (“we have never required a ratemaking 

agency to allocate costs with exacting precision.”); Sithe, 285 F.3d 1 at 5. 

162 Midwest ISO Transmission Owners, 373 F.3d 1361 at 1371 (citing Sithe, 285 

F.3d 1 at 5). 
Docket No. RM10-23-000 - 84 - 

the circumstances in which the Commission must fulfill its statutory responsibilities 

change with developments in the electric industry, such as changes with respect to the 

demands placed on the transmission grid. 

149. The Commission has previously recognized changes in circumstances that 

warranted changes in the manner by which public utilities recover transmission costs. In 

the early 1990s, the Commission identified “dramatic changes which the electric industry 

has faced, and will face in the near term,” such as “increased reliance on market forces to 

meet power supply needs; new market entrants such as exempt wholesale generators; a 

significant number of utility mergers and combinations; more highly integrated operation 

of various power pools; and substantial bulk power trading among electric systems,” as 

well as the initial filing of open access transmission tariffs.163 To account for those 

developments and the industry’s changing needs, the Commission issued a policy 

statement that increased flexibility with respect to transmission pricing.164

150. Many of those changes have not only continued but also accelerated in recent 

years. For example, as commenters stated in response to the October 2009 Notice, the 

further expansion of regional power markets has led to a growing need for new 

transmission facilities that cross several utility, RTO, ISO or other regions. The 

 163 See Notice of Technical Conference and Request for Comments in Inquiry 

Concerning the Commission’s Pricing Policy for Transmission Services Provided by 

Public Utilities under the Federal Power Act, 58 FR 36400, at 36401 (1993). 

164 Policy Statement in Inquiry Concerning the Commission’s Pricing Policy for 

Transmission Services Provided by Public Utilities under the Federal Power Act, FERC 

Stats. & Regs., Regulations Preambles January 1991 – June 1996 ¶ 31,005 (1994). 
Docket No. RM10-23-000 - 85 - 

industry’s continuing transition from relatively localized trading to larger regional power 

markets also results, among other effects, in broader diffusion of the benefits associated 

with transmission upgrades and new transmission facilities. 

151. Similarly, the increasing adoption of state resource policies, such as renewable 

portfolio standard measures, has contributed to rapid growth of location-constrained 

renewable energy resources that are frequently remote from load centers, as well as a 

growing need for new transmission facilities that cross several utility and/or RTO or ISO 

regions. Transmission facilities that are needed to comply with state renewable portfolio 

standard measures illustrate the increasing potential for benefits associated with meeting 

public policy-driven transmission needs. 

152. More generally, as stated above, challenges associated with allocating the cost of 

transmission appear to have become more acute as the need for transmission 

infrastructure has grown. As noted above, constructing new transmission facilities 

requires a significant amount of capital. Therefore, a threshold consideration for any 

company considering investing in transmission is whether it will have a reasonable 

opportunity to recover its costs. However, there are few rate structures in place today 

that provide both for analysis of the beneficiaries of a transmission facility that is 

proposed to be located within a transmission planning region that is outside of an RTO or 

ISO, or in more than one transmission planning region, and for corresponding allocation 

and recovery of the facility’s costs. The lack of such rate structures creates significant 

risk for transmission developers that they will have no identified group of customers from 

which to recover the cost of their investment. In addition, cost allocation within RTO or 
Docket No. RM10-23-000 - 86 - 

ISO regions, particularly those that encompass several states, is often contentious and 

prone to litigation because it is difficult to reach an allocation of costs that is perceived as 

fair. Some comments filed in response to the October 2009 Notice present these types of 

concerns and state the resultant uncertainty regarding cost allocation remains an 

impediment to development of needed transmission facilities. 

153. The risk of the free rider problems associated with new transmission investment 

that the Commission described in Order No. 890 is also particularly high for projects that 

affect multiple utilities’ transmission systems and therefore may have multiple 

beneficiaries. With respect to such projects, any individual beneficiary has an incentive 

to defer investment in the hopes that other beneficiaries will value the project enough to 

fund its development. On one hand, a cost allocation method that relies exclusively on a 

participant funding approach, without respect to other beneficiaries of a transmission 

facility, increases this incentive and, in turn, the likelihood that needed transmission 

facilities will not be constructed in a timely manner. On the other hand, if costs are 

allocated to entities that will receive no benefit from a transmission facility, then those 

entities are more likely to oppose inclusion of the facility in a regional transmission plan 

or to otherwise impose obstacles that delay or prevent the facility’s construction. 

154. In light of these challenges and recent developments affecting the industry, the 

Commission is concerned that existing cost allocation methods may not appropriately 

account for benefits associated with new transmission facilities and, thus, may result in 

rates that are not just and reasonable or are unduly discriminatory or preferential. 
Docket No. RM10-23-000 - 87 - 

C. Proposed Reforms

155. The Commission proposes to amend its regulations to address the concerns 

discussed above. 

156. First, we propose to more closely align transmission planning and cost allocation 

processes. A transmission planning process includes a facility in a transmission plan in 

order to achieve a specific purpose or purposes, such as to avoid an impending violation 

of a Reliability Standard, reduce congestion and thereby increase access to lower-cost 

resources, or enable compliance with public policy requirements established by state or 

federal laws or regulations. Because such purposes involve the identification of expected 

beneficiaries—either explicitly or implicitly—establishing a closer link between 

transmission planning and cost allocation will address in part the Commission’s concern 

that existing cost allocation methods may not appropriately account for benefits 

associated with new transmission facilities. 

157. The Commission has previously suggested that transmission planning at least on a 

regional basis is closely related to cost allocation. As noted above, this premise underlies 

the Commission’s establishment in Order No. 890 of a transmission planning principle on 

cost allocation for new transmission facilities. In addition, the Commission has explained 

that it may be appropriate to have different cost allocation methods for facilities that are 

planned for different purposes or pursuant to different transmission planning processes. 

For example, the Commission distinguished between existing facilities in Midwest ISO 

and PJM for which it found that license plate rates are appropriate, and new facilities in 
Docket No. RM10-23-000 - 88 - 

those regions for which it approved broader cost allocation methods.165 The Commission 

found it significant that Midwest ISO and PJM plan the construction of new facilities 

based on each RTO’s independent transmission planning process, which helps to ensure 

that new projects are necessary to meet the reliability and economic needs of each RTO’s 

system as a whole. The Commission also noted that Midwest ISO and PJM plan certain 

new facilities pursuant to a joint RTO planning process under a Joint Operating 

Agreement. By contrast, the Commission stated that decisions to build existing facilities 

within Midwest ISO and PJM were not made as part of any regional planning process.166

158. The Commission recognizes that identifying which types of benefits are relevant 

for cost allocation purposes, which entities are receiving those benefits, and the relative 

benefits that accrue to various beneficiaries can be difficult and controversial. The 

Commission believes that a transparent transmission planning process is the appropriate 

forum to address these issues. In addition, addressing these issues through the 

transmission planning process would increase the likelihood that facilities included in 

transmission plans are actually constructed, rather than being included in a transmission 

plan only to later encounter cost allocation disputes that prevent their construction. 

159. Accordingly, the Commission proposes to require that every public utility 

transmission provider have in place a method, or set of methods, for allocating the costs 

of new transmission facilities that are included in the transmission plan produced by the 

 165 Amer. Elec. Power Serv. Corp. v. Midwest Indep. Transmission Sys. Operator, 

Inc., 122 FERC ¶ 61,083, at P 13-24 (2008). 

166 Id. P 96. 
Docket No. RM10-23-000 - 89 - 

transmission planning process in which it participates. If the public utility transmission 

provider is an RTO or ISO, then the method or methods would be required to be set forth 

in the RTO or ISO tariff. In other transmission planning regions, each public utility 

transmission provider located within the region would be required to set forth in its tariff 

the method or methods for cost allocation used in its transmission planning region. 

160. An RTO or ISO or the public utility transmission providers in a transmission 

planning region may have a single cost allocation method for all new transmission 

facilities or different methods for different types of facilities. For example, cost 

allocation methods may distinguish among facilities that are driven by needs associated 

with maintaining reliability, relieving congestion, and achieving public policy 

requirements established by state or federal laws or regulations, all of which would be 

required to be considered in the regional transmission planning process as explained 

elsewhere in this Proposed Rule. The Commission recognizes that several transmission 

planning regions that have different cost allocation methods by type of project currently 

have transmission planning procedures and cost allocation methods that refer only to the 

first two categories of transmission projects. The Proposed Rule would permit a public 

utility transmission provider or transmission planning region to distinguish or not 

distinguish among these three types of transmission facilities, as long as each of the three 

is considered in the transmission planning process and there is a means for allocating the 

costs of each type of facility to beneficiaries. 

161. Second, we propose to require that each public utility transmission provider within 

a transmission planning region develop a method for allocating the costs of a new 
Docket No. RM10-23-000 - 90 - 

interregional transmission facility between the two neighboring transmission planning 

regions in which the facility is located or among the beneficiaries in the two neighboring 

transmission planning regions. 

162. Third, to ensure that the cost allocation method or methods are just and reasonable 

and not unduly discriminatory or preferential, we propose to assess each cost allocation 

method based upon the cost allocation principles set out in the following sections, one set 

of principles for intraregional facilities and another for interregional facilities. To 

reiterate, we propose that the cost allocation method or methods be applied to new 

transmission facilities included in the transmission plan produced by the transmission 

planning process in which the public utility transmission provider participates. 

163. Finally, we note that under our proposals, public utility transmission providers will 

have the first opportunity to develop cost allocation methods for intraregional and 

interregional transmission facilities in consultation with customers and other 

stakeholders. In the event that no agreement can be reached, the Commission would use 

the record in the relevant compliance filing proceeding as a basis to develop a cost 

allocation method or methods that meets the Commission’s proposed requirements. 

1. Intraregional Cost Allocation 

164. An intraregional transmission facility is defined as a transmission facility located 

entirely within the geographic boundaries of one transmission planning region. As 

proposed here, each RTO or ISO on behalf of its transmission owning members, or the 

individual public utility transmission providers in a non-RTO or ISO transmission 

planning region, would be required to demonstrate through a compliance filing that it has 
Docket No. RM10-23-000 - 91 - 

a cost allocation method or methods that address cost recovery for each new transmission 

facility included in its regional transmission plan and that satisfy the following principles: 

(1) The cost of transmission facilities must be allocated to those within the 

transmission planning region that benefit from those facilities in a manner that 

is at least roughly commensurate with estimated benefits.167 In determining 

the beneficiaries of transmission facilities, a regional transmission planni

process may consider benefits including, but not limited to the extent to which 

transmission facilities, individually or in the aggregate, provide for maintaining 

reliability and sharing reserves, production cost savings and congestion relief, 

and/or meeting public policy requirements established by state or federal laws 

or regulations that may drive transmission needs.

ng 

 

168

(2) Those that receive no benefit from transmission facilities, either at present or 

in a likely future scenario, must not be involuntarily allocated the costs of those 

facilities. 

(3) If a benefit to cost threshold is used to determine which facilities have 

sufficient net benefits to be included in a regional transmission plan for the 

167 Illinois Commerce Commission, 576 F.3d at 476-77 (“We do not suggest that 

the Commission has to calculate benefits to the last penny, or for that matter to the last 

million or ten million or perhaps hundred million dollars.”). See also Midwest ISO 

Transmission Owners, 373 F.3d 1361 at 1369 (“we have never required a ratemaking 

agency to allocate costs with exacting precision.”); Sithe, 285 F.3d 1 at 5. 

168 As discussed above, the Commission proposes to require each public utility 

transmission provider to amend its OATT such that its local and regional transmission 

planning processes explicitly provide for consideration of public policy requirements 

established by state or federal laws or regulations that may drive transmission needs. 
Docket No. RM10-23-000 - 92 - 

purpose of cost allocation, it must not be so high that facilities with significant 

positive net benefits are excluded from cost allocation. A transmission 

planning region or public utility transmission provider may want to choose 

such a threshold to account for uncertainty in the calculation of benefits and 

costs. If adopted, such a threshold may not include a ratio of benefits to costs 

that exceeds 1.25 unless the transmission planning region or public utility 

transmission provider justifies and the Commission approves a greater ratio. 

(4) The allocation method for the cost of an intraregional facility must allocate 

costs solely within that transmission planning region unless another entity 

outside the region or another transmission planning region voluntarily agrees to 

assume a portion of those costs.169 However, the transmission planning 

process in the original region must identify consequences for other 

transmission planning regions, such as upgrades that may be required in 

another region and, if there is an agreement for the original region to bear costs 

associated with such upgrades, then the original region’s cost allocation 

method or methods must include provisions for allocating the costs of the 

upgrades among the entities in the original region. 

 169 In addition, the Commission preliminarily finds that this principle does not 

affect the cross-border cost allocation methods developed by PJM and the Midwest ISO 

in response to Commission directives related to their intertwined configuration. Midwest 

Indep. Transmission Sys. Operator, Inc., 113 FERC ¶ 61,194, at P 10 (2005); Midwest 

Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,084 (2008); Midwest Indep. 

Transmission Sys. Operator, Inc., 129 FERC ¶ 61,102 (2009). 
Docket No. RM10-23-000 - 93 - 

(5) The cost allocation method and data requirements for determining benefits and 

identifying beneficiaries for a transmission facility must be transparent with 

adequate documentation to allow a stakeholder to determine how they were 

applied to a proposed transmission facility. 

(6) A transmission planning region may choose to use a different cost allocation 

method for different types of transmission facilities in the regional plan, such 

as transmission facilities needed for reliability, congestion relief, or to achieve 

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

Each cost allocation method must be set out clearly and explained in detail in 

the compliance filing for this rule. 

165. In proposing these principles, the Commission does not intend to prescribe a 

uniform approach to cost allocation for new intraregional transmission facilities. To the 

contrary, we recognize that regional differences may warrant distinctions in cost 

allocation methods among transmission planning regions. Therefore, this Proposed Rule 

would allow the public utility transmission providers in each transmission planning 

region to develop a transmission cost allocation method that best suits the needs of that 

transmission planning region. 

166. However, the Commission proposes that, if the public utility transmission 

providers in a transmission planning region, in consultation with customers and other 

stakeholders, cannot agree on a cost allocation method for new intraregional transmission 

facilities that satisfies these principles, the Commission would use the record in the 

relevant compliance filing proceeding as a basis for applying these principles to develop 
Docket No. RM10-23-000 - 94 - 

a cost allocation method that meets the Commission’s requirements. Consistent with the 

Commission’s intention not to prescribe a uniform approach, this cost allocation method 

would not necessarily be the same for every transmission planning region where the 

public utility transmission providers are unable to agree on a cost allocation method that 

satisfies the principles. 

167. The Commission recognizes that several approaches to cost allocation may satisfy 

the proposed principles. For example, a postage stamp cost allocation method may be 

appropriate where all customers within a specified transmission planning region are 

found to benefit from the use or availability of a facility or class or group of facilities 

(e.g., all transmission facilities at 345 kV or higher), especially if the distribution of 

benefits associated with a class or group of facilities is likely to vary considerably over 

the long depreciation life of the facilities amid changing power flows, fuel prices, 

population patterns, and local economic developments. Similarly, other methods that 

propose cost allocation to a narrower class of beneficiaries may be appropriate, provided 

that the method reflects an evaluation of beneficiaries and is adequately defined and 

supported by the transmission planning region. 

168. In addition, the principles proposed in this rulemaking do not foreclose the 

opportunity for a transmission developer or individual customer to voluntarily assume the 

costs of a new transmission facility. In other words, the proposed principles would not 

prohibit voluntary participant funding. However, if a transmission developer believes 

that others in the transmission planning region may benefit from a new transmission 

facility and want to seek broader cost allocation, then that developer must be permitted to 
Docket No. RM10-23-000 - 95 - 

propose its project in the regional transmission planning process that will evaluate the 

project’s beneficiaries. If the facility is included in the regional transmission plan, the 

costs of that facility must be eligible for allocation pursuant to the Commission-approved 

method for allocating the cost of a new transmission facility in that plan.170 As stated 

above, a cost allocation method that relies exclusively on a participant funding approach, 

without respect to other beneficiaries of a transmission facility, exacerbates the free rider 

problem that the Commission described in Order No. 890. Such a cost allocation method 

would not satisfy the proposed principles. 

169. With regard to a new transmission facility that is located entirely within one 

transmission owner’s service territory, a transmission owner may not unilaterally invoke 

the regional cost allocation method to require the allocation of the costs of a new 

transmission facility to other entities in its transmission planning region. However, if the 

regional transmission planning process determines that a new facility located solely 

within a transmission owner’s service territory would provide benefits to others in the 

region, allocating the facility’s costs according to that region’s intraregional cost 

allocation method would be permitted. 

2. Interregional Cost Allocation

170. An interregional transmission facility is one that in located within two or more 

transmission planning regions. In the past, most transmission upgrades were planned and 

 170 However, certain transmission developers may seek to participate in the 

regional transmission planning process only for coordination purposes (e.g., to perform a 

reliability check for a participant-funded or merchant transmission project), in which case 

the transmission plan would not include a cost allocation for such projects. 
Docket No. RM10-23-000 - 96 - 

constructed to meet the needs of customers within a given transmission planning region. 

However, new transmission facilities located within multiple transmission planning 

regions are now being considered by transmission providers in various parts of the nation. 

For example, as discussed above, development of renewable energy resources is 

increasing rapidly, in part in response to state renewable portfolio standard requirements. 

However, many of these resources are located far from load centers. New transmission 

facilities located within multiple transmission planning regions may be necessary to 

deliver the output of these renewable energy resources. 

171. There are few rate structures in place today that provide for the allocation and 

recovery of costs of interregional transmission facilities. We are concerned that the 

absence of clear cost allocation rules for interregional transmission facilities could 

impede the development of such facilities, because of uncertainty regarding recovery of 

associated costs. In addition, the combined size of the multiple transmission planning 

regions in which an interregional facility would be located may increase the potential for 

both free ridership and the allocation of costs to those that receive no benefit from a 

facility. 

172. Therefore, we propose to require that the public utility transmission providers 

located in each pair of neighboring transmission planning regions develop a mutually 

agreeable method for allocating between the two transmission planning regions the costs 

of a new transmission facility that is located within both regions and that is eligible for 

interregional cost recovery pursuant to the region’s interregional transmission planning 

agreement developed in accordance with the requirement proposed above. In an RTO or 
Docket No. RM10-23-000 - 97 - 

ISO region, we propose that the method must be filed to become a part of the relevant 

tariffs. In other transmission planning regions, we propose that the cost allocation 

method be filed as part of the OATT of each public utility transmission provider in the 

region. 

173. A group of three or more transmission planning regions within an interconnection 

—or all of the transmission planning regions within an interconnection—may agree on 

and file a common method for allocating the costs of a new interregional transmission 

facility. However, the Commission does not propose to require such agreements among 

more than two neighboring transmission planning regions. 

174. Each cost allocation method filed in accordance with this proposal would be 

required to comply with the following principles: 

(1) The costs of a new interregional facility must be allocated to each transmission 

planning region in which that facility is located in a manner that is at least 

roughly commensurate with the estimated benefits of that facility in each of the 

transmission planning regions. In determining the beneficiaries of 

interregional transmission facilities, transmission planning regions may 

consider benefits including, but not limited to, those associated with 

maintaining reliability and sharing reserves, production cost savings and 

congestion relief, and meeting public policy requirements established by state 

or federal laws or regulations that may drive transmission needs.171

 

(continued)

171 As discussed above, the Commission proposes to require each public utility 
Docket No. RM10-23-000 - 98 - 

(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 

facility.172 

(3) If a benefit-cost threshold ratio is used to determine whether an interregional 

transmission facility has sufficient net benefits to qualify for interregional cost 

allocation, this ratio must not be so large as to exclude a facility with 

significant positive net benefits from cost allocation. The public utility 

transmission providers located in the neighboring transmission planning 

regions may choose to use such a threshold to account for uncertainty in the 

calculation of benefits and costs. If adopted, such a threshold, may not include 

a ratio of benefits to costs that exceeds 1.25 unless the pair of regions justifies 

and the Commission approves a higher ratio. 

(4) Costs allocated for an interregional facility must be assigned only to 

transmission planning regions in which the facility is located. Costs cannot be 

assigned involuntarily under this rule to a transmission planning region in 

which that facility is not located. However, the interregional planning process 

 

transmission provider to amend its OATT such that its local and regional transmission 

planning processes explicitly provide for consideration of public policy requirements 

established by state or federal laws or regulations that may drive transmission needs. 

172 For example, a DC line that runs from a first transmission planning region, 

through a second transmission planning region, and into a third transmission planning 

region, with no tap in the second region, may not provide any benefits to the second 

region. 
Docket No. RM10-23-000 - 99 - 

must identify consequences for other transmission planning regions, such as 

upgrades that may be required in a third transmission planning region and, if 

there is an agreement among the transmission providers in the regions in which 

the facility is located to bear costs associated with such upgrades, then the 

interregional cost allocation method must include provisions for allocating the 

costs of the upgrades within the transmission planning regions in which the 

facility is located. 

(5) The cost allocation method and data requirements for determining benefits and 

identifying beneficiaries for an interregional facility must be transparent with 

adequate documentation to allow a stakeholder to determine how they were 

applied to a proposed transmission facility. 

(6) The public utility transmission providers located in neighboring transmission 

planning regions may choose to use a different cost allocation method for 

different types of interregional facilities, such as transmission facilities needed 

for reliability, congestion relief, or to achieve public policy requirements 

established by state or federal laws or regulations. Each cost allocation method 

must be set out and explained in detail in the compliance filing for this rule. 

175. As with intraregional cost allocation, we are not proposing to require a uniform 

method of cost allocation for interregional transmission facilities. There may be 

legitimate reasons for the public utility transmission providers located in neighboring 

transmission planning regions to adopt different cost allocation methods. The 
Docket No. RM10-23-000 - 100 - 

Commission recognizes that several approaches to cost allocation may satisfy the 

proposed principles.173

176. Therefore, we propose to allow methods for allocating the costs of new 

interregional facilities to differ among pairs of transmission planning regions, as long as 

each method satisfies the proposed interregional cost allocation principles listed above. 

Moreover, the method used for allocating interregional transmission facility costs 

between any two transmission planning regions may be different from the method used 

by the public utility transmission providers located in either of those transmission 

planning regions to allocate the costs of new intraregional facilities. In addition, the cost 

allocation method used by the public utility transmission providers located in a 

transmission planning region to allocate the costs of new intraregional facilities could be 

different from the cost allocation method by which the public utility transmission 

providers in the same transmission planning region further allocate costs to be borne by 

that transmission planning region pursuant to an agreed-upon method for allocating the 

costs of interregional facilities. 

177. Similar to our proposal for intraregional transmission facilities, we propose that if 

the public utility transmission providers in coordination with their customers and other 

stakeholders in a pair of neighboring transmission planning regions cannot agree on a 

 173 For the reasons discussed above with respect to cost allocation for intraregional 

transmission facilities, a cost allocation method that relies exclusively on a participant 

funding approach, without respect to other beneficiaries of a transmission facility, would 

not satisfy the proposed principles for interregional cost allocation. 
Docket No. RM10-23-000 - 101 - 

cost allocation method for new interregional transmission facilities that satisfies these 

principles, then the Commission would use the record in the relevant compliance filing 

proceedings as a basis for applying the principles to develop an interregional cost 

allocation method that meets the Commission’s requirements. Such a cost allocation 

method would not necessarily be the same for every pair of neighboring transmission 

planning regions that is unable to agree on a cost allocation method that satisfies the 

principles. 

178. We seek comment on any issue of interest or concern related to the requirements 

proposed in this section of the Proposed Rule. In particular, we seek comment on the 

appropriateness and application of the proposed cost allocation principles with respect to 

new intraregional and interregional transmission facilities. If commenters believe that 

additional principles should apply to cost allocation for either intraregional or 

interregional transmission facilities, the Commission asks commenters to submit and 

explain the need for those principles. 

VI. Compliance Filings

179. The Commission proposes that each public utility transmission provider must 

comply with the requirements of this Proposed Rule. With the exception of the proposed 

requirements with respect to interregional transmission planning agreements and an 

interregional cost allocation method or methods, the Commission proposes to require 

each public utility transmission provider to submit a compliance filing within six months 

of the effective date of the final rule in this proceeding revising its OATT or other 

document(s) subject to the Commission’s jurisdiction as necessary to demonstrate that it 
Docket No. RM10-23-000 - 102 - 

meets the proposed requirements set forth in this Proposed Rule.174 The Commission 

proposes to require each public utility transmission provider to submit a compliance 

filing within one year of the effective date of the final rule in this proceeding to 

demonstrate that it meets the proposed requirements set forth in the Proposed Rule with 

respect to interregional transmission planning agreements. The Commission proposes to 

require each public utility transmission provider to submit a compliance filing within one 

year of the effective date of the final rule in this proceeding revising its OATT as 

necessary to demonstrate that it meets the proposed requirements set forth in this 

Proposed Rule with respect to an interregional cost allocation method or methods. 

180. The Commission would assess whether each compliance filing satisfies the 

proposed requirements and principles stated above and issue additional orders as 

necessary to ensure that each public utility transmission provider meets the requirements 

of this Proposed Rule. 

181. The Commission proposes that transmission providers that are not public utilities 

would have to adopt the requirements of this Proposed Rule as a condition of maintaining 

the status of their safe harbor tariff or otherwise satisfying the reciprocity requirement of 

Order No. 888.175 

 174 See Appendix B for the proposed pro forma Attachment K consistent with this 

NOPR. 

175 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,760-63. 
Docket No. RM10-23-000 - 103 - 

VII. Information Collection Statement

182. The following collection of information contained in this Proposed Rule is subject 

to review by the Office of Management and Budget (OMB) under section 3507(d) of the 

Paperwork Reduction Act of 1995.176 OMB’s regulations require approval of certain 

information collection requirements imposed by agency rules.177 The Commission 

solicits comments on the Commission’s need for this information, whether the 

information will have practical utility, the accuracy of the burden estimates, ways to 

enhance the quality, utility and clarity of the information to be collected or retained, and 

any suggested methods for minimizing respondents’ burden, including the use of 

automated information techniques. 

Burden Estimate: The estimated public reporting burdens for the proposed reporting 

requirements are as follows. 

FERC-917 - Proposed Reporting 

Requirements in RM10-23 

Annual 

Number of 

Respondent

s (Filers) 

Annual 

Number 

of 

Responses

Hours per 

Response 

Total 

Annual 

Hours 

in Year 

1 

Total 

Annual 

Hours in 

Subsequen

t Years 

participation in a transparent and open 

intraregional transmission planning 

process that meets transmission 

planning principles, includes 

consideration of public policy 

requirements, identifies and evaluates 

facilities to meet needs, develops cost 

allocation method, and produces an 

intraregional transmission plan that 134 134

100 hrs in 

Year 1; 

50 hrs. in 

subseque

nt years 13400 6700

 176 44 U.S.C. 3507(d). 

177 5 CFR 1320.11. 
Docket No. RM10-23-000 - 104 - 

describes and incorporates a cost 

allocation method that meets the 

Commission's principles. 

coordination, development, and filing 

with the Commission of interregional 

planning agreements that meet the 

Commission’s requirements, that 

include consideration of public policy 

requirements, and that incorporate cost 

allocation methods that meets the 

Commission's principles; provide or 

post ongoing communications, and 

provide annual data exchange. 134 134

125 hrs. 

in Year 1; 

50 hrs. in 

subseque

nt years 16750 6700

conforming tariff changes for local 

transmission planning, including those 

related to consideration of public 

policy requirements; and conforming 

tariff changes for intraregional and 

interregional planning. 134 134

50 hrs. in 

Year 1; 

25 hours 

in 

subseque

nt years 6700 3350

Total Estimated Additional Burden 

Hours, Proposed for FERC-917 in 

NOPR in RM10-23 36850 16750

Cost to Comply: The Commission has projected costs of compliance for the reporting 

requirements as follows: 

Year 1: $4,200,900 [36,850 hours X $114 per hour178] 

Subsequent Years: $1,909,500 [or 16,750 hours X $114 per hour] 

OMB’s regulations require it to approve certain information collection requirements 

 178 The estimated cost of $114 an hour is the average of the hourly costs of: 

attorney ($200), consultant ($150), technical ($80), and administrative support ($25). 
Docket No. RM10-23-000 - 105 - 

imposed by an agency rule. The Commission is submitting notification of this Proposed 

Rule to OMB. The Commission proposes to make the reporting requirements mandatory. 

Title: FERC-917 

Action: Proposed Collection. 

OMB Control No. 1902-0233 

Respondents: Electric Utility Transmission Providers. RTOs and ISOs also may file 

some materials on behalf of their members. 

Frequency of responses: Initial filing and subsequent filings. 

Necessity of the Information: 

183. Building on the reforms in Order No. 890, the Federal Energy Regulatory 

Commission is proposing amendments to the pro forma OATT to correct certain 

deficiencies in transmission planning and cost allocation requirements for public utility 

transmission providers. The purpose of this proposed rulemaking is to strengthen the pro 

forma OATT, so that the transmission grid can better support wholesale power markets 

and ensure that Commission-jurisdictional services are provided at rates, terms and 

conditions that are just and reasonable and not unduly discriminatory or preferential. We 

propose to achieve this goal by reforming electric transmission planning requirements 

and establishing a closer link between cost allocation and regional transmission planning 

processes. 

184. Internal Review: The Commission has reviewed the proposed changes and has 

determined that the changes are necessary. These requirements conform to the 

Commission’s need for efficient information collection, communication, and 
Docket No. RM10-23-000 - 106 - 

management within the energy industry. The Commission has assured itself, by means of 

internal review, that there is specific, objective support associated with the information 

requirements. 

185. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 

For submitting comments concerning the collection of information and the associated 

burden estimate(s), please send your comments to the contact listed above and to the 

Office of Information and Regulatory Affairs, Office of Management and Budget, 

725 17th Street, NW, Washington, DC 20503 [Attention: Desk Officer for the Federal 

Energy Regulatory Commission, phone: (202) 395-4638, fax: (202) 395-7285]. Due to 

security concerns, comments should be sent electronically to the following e-mail 

address: oira_submission@omb.eop.gov. Please reference OMB Control No. 1902-0233 

and the docket number of this proposed rulemaking in your submission. 

VIII. Environmental Analysis

186. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.179 The Commission concludes that neither an Environmental 

 179 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 

1986-1990 ¶ 30,783 (1987). 
Docket No. RM10-23-000 - 107 - 

Assessment nor an Environmental Impact Statement is required for this Proposed Rule 

under section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale of electric 

energy subject to the Commission’s jurisdiction, plus the classification, practices, 

contracts and regulations that affect rates, charges, classifications, and services.180

IX. Regulatory Flexibility Act Analysis

187. The Regulatory Flexibility Act of 1980 (RFA)181 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. This Proposed Rule applies to public utilities that own, control 

or operate interstate transmission facilities other than those that have received waiver of 

the obligation to comply with Order Nos. 888, 889 and 890. The total estimated number 

of public utility transmission providers that, absent waiver, would have to modify their 

current OATTs by filing the revised pro forma OATT is 134. Of these public utility 

transmission providers, an estimated 10 filers, or 7.3% percent, have output of four 

million MWh or less per year.182 The Commission does not consider this a substantial 

 180 18 CFR 380.4(a)(15). 

181 5 U.S.C. 601-612. 

182 A firm is “small” if, including its affiliates, it is primarily engaged in the 

generation, transmission, and/or distribution of electric energy for sale and its total 

electric output for the preceding fiscal year did not exceed 4 million megawatt hours. 

Based on the filers of the annual FERC Form 1 and Form 1-F, as well as the number of 

companies that have obtained waivers, we estimate that 7.3% of the filers are “small.” 
Docket No. RM10-23-000 - 108 - 

number and, in any event, each of these entities retains its rights to waiver of these 

requirements. The criteria for waiver that would be applied under this rulemaking for 

small entities is unchanged from that used to evaluate requests for waiver under Order 

Nos. 888, 889 and 890. Accordingly, the Commission certifies that the proposed rule 

will not have a significant economic impact on a substantial number of small entities. 

X. Comment Procedures

188. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due 60 days from 

publication in the FEDERAL REGISTER. Comments must refer to Docket No. RM10-

23-000, and must include the commenter's name, the organization they represent, if 

applicable, and their address in their comments. 

189. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 

190. Commenters that are not able to file comments electronically must send an 

original and 14 copies of their comments to: Federal Energy Regulatory Commission, 

Office of the Secretary, 888 First Street, NE, Washington, DC 20426. 
Docket No. RM10-23-000 - 109 - 

191. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 

XI. Document Availability

192. 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 FERC's Home Page 

(http://www.ferc.gov) and in FERC'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. 

193. From FERC'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. 

194. User assistance is available for eLibrary and the FERC’s web site during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at 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. 
Docket No. RM10-23-000 - 110 - 

List of subjects in 18 CFR Part 35 

Electric power rates 

Electric utilities 

Reporting and recordkeeping requirements 

By direction of the Commission. Commissioner Moeller is concurring with a separate 

 statement attached. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

 
Docket No. RM10-23-000 - 111 - 

In consideration of the foregoing, the Commission proposes to amend Part 35, 

Chapter I, Title 18, Code of Federal Regulations, as follows: 

PART 35—FILING OF RATE SCHEDULES AND TARIFFS 

1. The authority citation for part 35 continues to read as follows: 

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 71-7352. 

2. Amend § 35.28 as follows: 

a. Paragraph (c)(1) through (c)(1)(iii) are revised. 

b. Paragraph (c)(1)(vi) is revised. 

c. Paragraphs (c)(3), (c)(3)(i), and (c)(3)(ii) are revised. 

d. Paragraphs (c)(4) through (c)(4)(ii) are revised. 

e. Paragraph (d) (1) is revised. 

f. Paragraph (e)(1) is revised. 

§ 35.28 Non-discriminatory open access transmission tariff. 

* * * * * 

(c) Non-discriminatory open access transmission tariffs. 

(1) Every public utility that owns, controls, or operates facilities used for the 

transmission of electric energy in interstate commerce must have on file with the 

Commission a tariff of general applicability for transmission services, including ancillary 

services, over such facilities. Such tariff must be the open access pro forma tariff 

contained in Order No. 888, FERC Stats. & Regs. ¶ 31,036 (Final Rule on Open Access 

and Stranded Costs), as revised by the open access pro forma tariff contained in Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 (Final Rule on Open Access Reforms) and 
Docket No. RM10-23-000 - 112 - 

further revised in Order No. ______, FERC Stats. & Regs. ¶ ______ (Final Rule on 

Transmission Planning and Cost Allocation by Transmission Owning and Operating 

Public Utilities), or such other open access tariff as may be approved by the Commission 

consistent with Order No. 888, FERC Stats. & Regs ¶ 31,306, Order No. 890, FERC 

Stats. & Regs. ¶ 32,241, and Order No. ______, FERC Stats. & Regs. ¶ ______. 

(i) Subject to the exceptions in paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv) and 

(c)(1)(v) of this section, the pro forma tariff contained in Order No. 888, FERC Stats. & 

Regs. ¶ 31,036, as revised by the open access pro forma tariff contained in Order No. 

890, FERC Stats. & Regs. ¶ 31,241 and further revised in Order No. ______, FERC 

Stats. & Regs. ¶ ______, and accompanying rates, must be filed no later than 60 days 

prior to the date on which a public utility would engage in a sale of electric energy at 

wholesale in interstate commerce or in the transmission of electric energy in interstate 

commerce. 

(ii) If a public utility owns, controls, or operates facilities used for the 

transmission of electric energy in interstate commerce as of [insert date that is 60 days 

after date of publication of the Final Rule in the FEDERAL REGISTER], it must file 

the revisions to the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ 

31,241, as amended by Order No.______, FERC Stats. & Regs. ¶ ____, pursuant to 

section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA in 

accordance with the procedures set forth in Order No. 890, FERC Stats. & Regs. ¶ 31,241 

and Order No. ______, FERC Stats. & Regs ¶ ____. 

(iii) If a public utility owns, controls, or operates transmission facilities used for 
Docket No. RM10-23-000 - 113 - 

the transmission of electric energy in interstate commerce as of [insert date that is 60 

days after date of publication of the Final Rule in the FEDERAL REGISTER], such 

facilities are jointly owned with a non-public utility, and the joint ownership contract 

prohibits transmission service over the facilities to third parties, the public utility with 

respect to access over the public utility's share of the jointly owned facilities must file the 

revisions to the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ 

31,241 as amended by Order No. ______, FERC Stats. & Regs. ¶ ____, pursuant to 

section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA. 

* * * * * 

(vi) Any public utility that seeks a deviation from the pro forma tariff contained in 

Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised in Order No. 890, FERC Stats. 

& Regs. ¶ 31,241 and Order No. ______, FERC Stats. & Regs. ¶ ______, must 

demonstrate that the deviation is consistent with the principles of Order No. 888, FERC 

Stats. & Regs ¶ 31,036, Order No. 890, FERC Stats. & Regs. ¶ 31,241, and Order No. 

______, FERC Stats. & Regs. ¶ ______. 

* * * * * 

 (3) Every public utility that owns, controls, or operates facilities used for the 

transmission of electric energy in interstate commerce, and that is a member of a power 

pool, public utility holding company, or other multi-lateral trading arrangement or 

agreement that contains transmission rates, terms or conditions, must have on file a joint 

pool-wide or system-wide open access transmission tariff, which tariff must be the pro 

forma tariff contained in Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised by the 
Docket No. RM10-23-000 - 114 - 

pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ 31,241 and further 

revised in Order No. ______, FERC Stats. & Regs. ¶ ______, or such other open access 

tariff as may be approved by the Commission consistent with Order No. 888, FERC 

Stats. & Regs. ¶ 31,036, Order No. 890, FERC Stats. & Regs. ¶ 31,241, and Order No. 

______, FERC Stats. & Regs. ¶ ______. 

 (i) For any power pool, public utility holding company or other multi-lateral 

arrangement or agreement that contains transmission rates, terms or conditions and that is 

executed after [insert date that is 60 days after date of publication of the Final Rule in the 

FEDERAL REGISTER], this requirement is effective on the date that transactions begin 

under the arrangement or agreement. 

 (ii) For any power pool, public utility holding company or other multi-lateral 

arrangement or agreement that contains transmission rates, terms or conditions and that is 

executed on or before [insert date that is 60 days after date of publication of the Final 

Rule in the FEDERAL REGISTER], a public utility member of such power pool, public 

utility holding company or other multi-lateral arrangement or agreement that owns, 

controls, or operates facilities used for the transmission of electric energy in interstate 

commerce must file the revisions to its joint pool-wide or system-wide open access 

transmission tariff consistent with Order No. 890, FERC Stats. & Regs. ¶ 31,241 as 

amended by Order No.______, FERC Stats. & Regs. ¶ ____, pursuant to section 206 of 

the FPA and accompanying rates pursuant to section 205 of the FPA in accordance with 

the procedures set forth in Order No. 890, FERC Stats. & Regs. ¶ 31,241 and Order No. 

_____, FERC Stats. & Regs ¶ ____. 
Docket No. RM10-23-000 - 115 - 

* * * * * 

 (4) Consistent with paragraph (c)(1) of this section, every Commissionapproved ISO or RTO must have on file with the Commission a tariff of general 

applicability for transmission services, including ancillary services, over such facilities. 

Such tariff must be the pro forma tariff contained in Order No. 888, FERC Stats. & Regs. 

¶ 31,036, as revised by the pro forma tariff contained in Order No. 890, FERC Stats. & 

Regs. ¶ 31,241 and further revised in Order No. ______, FERC Stats. & Regs. ¶ ______, 

or such other open access tariff as may be approved by the Commission consistent with 

Order No. 888, FERC Stats. & Reg. ¶ 31,036, Order No. 890, FERC Stats. & Regs. ¶ 

31,241, and Order No. ______, FERC Stats. & Regs. ¶ ______ . 

(i) Subject to paragraph (c)(4)(ii) of this section, a Commission-approved ISO 

or RTO must file the revisions to the pro forma tariff contained in Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 as amended by Order No. ______, FERC Stats. & Regs. ¶ ____, 

pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the 

FPA in accordance with the procedures set forth in Order No. 890, FERC Stats. & Regs. 

¶ 31,241 and Order No. ______, FERC Stats. & Regs ¶ ____. 

(ii) If a Commission-approved ISO or RTO can demonstrate that its existing 

open access tariff is consistent with or superior to the revisions to the pro forma tariff 

contained in Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised by the pro forma 

tariff in Order No. 890, FERC Stats. & Regs. ¶ 31,241 and further revised in Order No. 

______, FERC Stats. & Regs. ¶ ______, or any portions thereof, the Commissionapproved ISO or RTO may instead set forth such demonstration in its filing pursuant to 
Docket No. RM10-23-000 - 116 - 

section 206 in accordance with the procedures set forth in Order No., FERC Stats. & 

Regs ¶ ____. 

(d) Waivers. * * * 

(1) No later than [insert date that is 60 days after date of publication of the 

Final Rule in the FEDERAL REGISTER], or 

* * * * * 

(e) Non-public utility procedures for tariff reciprocity compliance. 

(1) A non-public utility may submit a transmission tariff and a request for 

declaratory order that its voluntary transmission tariff meets the requirements of Order 

No. 888, FERC Stats. & Regs. ¶ 31,036, Order No. 890, FERC Stats. & Regs. ¶ 31,241, 

and Order No. ______, FERC Stats. & Regs. ¶ ______ . 

* * * * * 
Docket No. RM10-23-000 - 117 - 

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

Appendix A: List of Short Names of Commenters on the Federal Energy 

Regulatory Commission’s Notice of Request for Comments on Transmission 

Planning Processes under Order No. 890—Docket No. AD09-8-000, October 2009 

Short Name or Acronym Commenter

3M 3M Company, High Capacity 

 Conductors 

AEP American Electric Power Service 

 Corporation 

Alabama PSC Alabama Public Service Commission 

 

Allegheny Companies Allegheny Power and Trans-Allegheny 

Interstate Line Company 

Ameren Ameren Services Company 

American Antitrust Institute American Antitrust Institute 

American Forest and Paper American Forest & Paper Association 

American Transmission American Transmission Company LLC 

APPA American Public Power Association 

AREVA T&D AREVA T&D Inc. 

AWEA American Wind Energy Association 

Baltimore Gas and Electric Baltimore Gas and Electric Company 

Barbara Luchsinger Barbara Luchsinger 

Bay Area Municipal Transmission City of Santa Clara, California; the 

Group City of Palo Alto, California; and the 

 City of Alameda, California 

Bonneville Bonneville Power Administration 
Docket No. RM10-23-000 - 118 - 

BP Energy BP Energy Company 

The Brattle Group Peter Fox-Penner, Johannes Pfeifenberger, and 

Delphine Hou 

California ISO California Independent System Operator 

Corporation 

CAlifornians for Renewable Energy CAlifornians for Renewable Energy, Inc. 

California PUC California Public Utilities Commission 

California State Water Project California Department of Water Resources 

State Water Project 

Calvin Daniels Calvin Daniels 

Chinook and Zephyr Chinook Power Transmission, LLC and Zephyr 

Power Transmission, LLC 

Clean Line Clean Line Energy Partners, LLC 

Coalition to Advance Renewable Coalition to Advance Renewable Energy 

Energy Through Bulk Energy Through Bulk Energy Storage 

Storage

ColumbiaGrid ColumbiaGrid 

Consolidated Edison, et al. Consolidated Edison Company of New York, 

Inc. and Orange and Rockland Utilities, Inc. 

Dayton Power and Light Dayton Power and Light Company 

Delaware Municipal and Delaware Municipal Electric 

Southwestern Electric Corporation, Inc. and Southwestern Electric 

Cooperative, Inc. 

Dominion Dominion Resources Services, Inc. 

Duke Duke Energy Corporation 

Eastern Interconnection Planning Eastern Interconnection Planning 
Docket No. RM10-23-000 - 119 - 

Collaborative Analysis Team Collaborative Analysis Team 

Eastern PJM Governors Governors of New Jersey, Delaware, Maryland, 

and Virginia 

EEI Edison Electric Institute 

Electricity Consumers Resource Electricity Consumers Resource Council 

Council 

ENE (Environment Northeast) ENE Environment Northeast 

Energy Future Coalition Energy Future Coalition 

Entergy Entergy Services, Inc. 

E.ON E.ON U.S. LLC 

E.ON Climate & Renewables E.ON Climate & Renewables North 

North America America 

EPSA Electric Power Supply Association 

Exelon Exelon Corporation 

Federal Trade Commission Federal Trade Commission 

FirstEnergy FirstEnergy Affiliates 

Florida Transmission Providers Florida Power & Light, Progress Energy 

Florida, Tampa Electric Company, and JEA 

Georgia Transmission Corporation Georgia Transmission Corporation 

Great River Energy Great River Energy 

Green Energy Express Green Energy Express, LLC 

Illinois Commission Illinois Commerce Commission 

Imperial Irrigation District Imperial Irrigation District (CA) 

Independent Power Producers Independent Power Producers Coalition- 
Docket No. RM10-23-000 - 120 - 

Coalition-West West 

Indicated Partners Green Energy Express LLC; Transmission 

Technology Solutions LLC; SouthWestern 

Power Group II, LLC; Nevada Hydro 

Company; LS Power Transmission, LLC; and 

Pattern Transmission LP 

Integrys, et al. Wisconsin Public Service Corporation, Upper 

Peninsula Power Company, and Integrys 

Energy Services, Inc. 

ISO New England ISO New England Inc. 

ITC Holdings ITC Holdings Corp. 

Kelson Companies Cottonwood Energy Company LP; Dogwood 

Energy LLC; and Magnolia Energy LP 

Large Public Power Council Austin Energy; Chelan County Public Utility 

District No. 1; Clark Public Utilities; Colorado 

Springs 

 Utilities; CPS Energy (San Antonio); IID 

Energy, JEA (Jacksonville, FL), Long Island

 Power Authority; Lower Colorado River 

Authority; MEAG Power; Nebraska Public 

Power District, New York Power Authority; 

Omaha Public Power District; Orlando Utilities 

Commission; Platte River Power Authority; 

Puerto Rico Electric Power Authority; 

Sacramento Municipal Utility District; Salt 

River Project; Santee Cooper; Seattle City 

Light; Snohomish County Public Utility District 

No. 1; and Tacoma Public Utilities 

Long Island Power Authority, et al. Long Island Power Authority, Consolidated 

Edison Company of New York, Inc., and 

Orange and Rockland Utilities, Inc. 

Lorraine Fleming Lorraine Fleming 

LS Power LS Power Transmission, LLC 
Docket No. RM10-23-000 - 121 - 

Maine PUC and Public Advocate Maine Public Utilities Commission and the 

Maine Office of the Public Advocate 

Massachusetts Attorney General Massachusetts Attorney General 

Massachusetts Departments Massachusetts Department of Public Utilities 

and Massachusetts Department of Energy 

Resources

MEAG Power MEAG Power

MidAmerican MidAmerican Energy Holdings Company 

Midwest ISO Midwest Independent Transmission System 

Operator, Inc. 

Midwest ISO Transmission Owners Ameren Services Company (as agent for Union 

Electric Company, Central Illinois Public 

Service Company; Central Illinois Light Co., 

and Illinois Power Company); City of Columbia 

Water and Light Department (Columbia, MO); 

City Water, Light & Power (Springfield, IL); 

Great River Energy; Hoosier Energy Rural 

Electric Cooperative, Inc.; Indiana Municipal 

Power Agency; Indianapolis Power & Light 

Company; (Minnesota Power (and its subsidiary 

Superior Water, L&P); Montana-Dakota 

Utilities Co.; Northern Indiana Public Service 

Company; Northern States Power Company 

(Minnesota and Wisconsin corporations); 

Northwestern Wisconsin Electric Company; 

Otter Tail Power Company; Southern Illinois 

Power Cooperative; Southern Indiana Gas & 

Electric Company; Southern Minnesota 

Municipal Power Agency; Wabash Valley 

Power Association, Inc.; and Wolverine Power 

Supply Cooperative, Inc. 

Modesto Irrigation District Modesto Irrigation District 

NARUC National Association of Regulatory Utility 

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

National Audubon Society, et al. National Audubon Society; Conservation Law 

Foundation; Energy Future Coalition; ENE 

(Environment Northeast); Environmental 

Defense Fund; Natural Resources Defense 

Council; Piedmont Environmental Council; 

Sierra Club; Sustainable FERC Project; and 

Union of Concerned Scientists 

National Grid National Grid USA 

National Nuclear Security National Nuclear Security 

Administration Service Center Administration Service Center in Albuquerque, 

New Mexico 

National Rural Electric Coops National Rural Electric Cooperative Association 

NationalWind NationalWind 

NEPOOL Participants New England Power Pool Participants 

Committee 

Nevada Hydro Nevada Hydro Company, Inc. 

New England Clean Energy Council New England Clean Energy Council 

New England States’ Committee on New England States’ Committee on 

Electricity Electricity 

New Jersey Board New Jersey Board of Public Utilities 

New York ISO New York Independent System Operator, Inc. 

New York PSC New York State Public Service Commission 

NextEra NextEra Energy Resources, LLC 

Northeast Utilities Northeast Utilities Service Company 

Northern Tier Transmission Group Northern Tier Transmission Group 

Northwest State Commissions and Idaho Public Utilities Commission, 

Consumer Counsel Montana Consumer Counsel, Montana Public 

Service Commission, Public Utility 
Docket No. RM10-23-000 - 123 - 

Commission of Oregon, Utah Public Service 

Commission, and Wyoming Public Service 

Commission

NRG NRG Energy, Inc. 

Ohio Commission Public Utilities Commission of Ohio 

Old Dominion Old Dominion Electric Cooperative 

Organization of MISO States Organization of MISO States 

Pacific Gas and Electric Pacific Gas and Electric Company 

Pattern Transmission Pattern Transmission LP 

Peter C. Luchsinger M.D. Peter C. Luchsinger M.D. 

PHI Companies Pepco Holdings, Inc.; Potomac Electric and 

Power Company; Delmarva Power & Light 

Company; and Atlantic City Electric Company 

Pioneer Transmission Pioneer Transmission, LLC 

PJM PJM Interconnection, LLC 

PPL PPL Electric Utilities Corporation 

Progress Energy Progress Energy, Inc. 

PSEG Companies Public Service Electric and Gas Company; 

PSEG Power LLC; PSEG Energy Resources & 

Trade LLC 

Public Interest Organizations & Alliance for Clean Energy New York; 

Renewable Energy Groups American Wind Energy Association; Center for 

Energy Efficiency & Renewable Technologies; 

Citizens Utility Board of Wisconsin; 

Conservation Law Foundation; 

 Environmental Defense Fund; Environmental 

Law & Policy Center; Fresh Energy; National 

Audubon Society; Natural Resources Defense 

Council; Northeast Energy Efficiency 
Docket No. RM10-23-000 - 124 - 

Partnerships; Northwest Energy Coalition; 

Office of the Ohio Consumers’ Counsel; Pace 

Energy and Climate Center; Piedmont 

Environmental Council; Project for Sustainable 

FERC Energy Policy; Sierra Club; Southern 

Alliance for Clean Energy; Union of Concerned 

Scientists; Western Grid Group; and Wind on 

the Wires 

Public Power Council Public Power Council 

Renewable Energy Systems Americas Renewable Energy Systems Americas Inc. 

RRI Energy RRI Energy, Inc. 

Salt River Project Salt River Project Agricultural Improvement 

and Power District 

San Diego Gas & Electric San Diego Gas & Electric Company 

Solar Energy Industries Solar Energy Industries Association 

South Carolina Electric & Gas South Carolina Electric & Gas Company 

Southern California Edison Southern California Edison Company 

Southern Companies Southern Company Services, Inc. 

SPP Southwest Power Pool, Inc. 

Startrans Startrans IO, LLC 

Starwood Starwood Energy Group Global, LLC 

State Representative Sloan State Representative Tom Sloan 

Sunflower and Mid-Kansas Sunflower Electric Power Corporation and MidKansas Electric Company, LLC 

Trans-Elect Trans-Elect Development Company, LLC 

Transmission Access Policy Study Transmission Access Policy Study 

Group Group 
Docket No. RM10-23-000 - 125 - 

Transmission Agency of Northern Transmission Agency of Northern 

California California 

Transmission Dependent Utility Arkansas Electric Cooperative 

Systems Corporation, Golden Spread Electric 

Cooperative, Inc., Kansas Electric 

 Power Cooperative, Inc., North Carolina 

Electric Membership Corporation, 

 Old Dominion Electric Cooperative, and 

Seminole Electric Cooperative, Inc. 

Upper Great Plains Transmission Upper Great Plains Transmission 

Coalition Coalition 

WECC Western Electricity Coordinating Council

WestConnect Planning Parties Arizona Public Service Company, Basin 

Electric Power Cooperative, Black Hills 

Corporation, El Paso Electric Company, 

 Imperial Irrigation District, NV Energy, 

 Public Service Company of Colorado, 

 Public Service Company of New Mexico, 

Sacramento Municipal Utility District, Salt 

River Project Agricultural Improvement and 

Power District, Southwest Transmission 

Cooperative, Inc., Transmission Agency of 

Northern California, Tri-State Generation and 

Transmission Association, Inc., Tucson Electric 

Power Company 

WIRES Working Group for Investment in Reliable and 

Economic Electric Systems 

Xcel Xcel Energy Services Inc. 
Docket No. RM10-23-000 - 126 - 

Appendix B: Pro Forma Open Access Transmission Tariff 

ATTACHMENT K 

Transmission Planning Process 

Local Transmission Planning 

The Transmission Provider shall establish a coordinated, open and transparent planning 

process with its Network and Firm Point-to-Point Transmission Customers and other 

interested parties to ensure that the Transmission System is planned to meet the needs of 

both the Transmission Provider and its Network and Firm Point-to-Point Transmission 

Customers on a comparable and not unduly discriminatory basis. The Transmission 

Provider’s coordinated, open and transparent planning process shall be provided as an 

attachment to the Transmission Provider’s Tariff. 

The Transmission Provider’s planning process shall satisfy the following nine principles, 

as defined in the Final Rule in Docket No. RM05-25-000: coordination, openness, 

transparency, information exchange, comparability, dispute resolution, regional 

participation, economic planning studies, and cost allocation for new projects. The 

planning process shall also include the procedures and mechanisms for evaluating 

transmission projects proposed to achieve public policy requirements established by state 

or federal laws or regulations consistent with the Final Rule in Docket No. RM10-23-

000. The planning process shall also provide a mechanism for the recovery and 

allocation of planning costs consistent with the Final Rule in Docket No. RM05-25-000.
Docket No. RM10-23-000 - 127 - 

The description of the Transmission Provider’s planning process must include sufficient 

detail to enable Transmission Customers to understand: 

(i) The process for consulting with customers and neighboring transmission providers; 

(ii) The notice procedures and anticipated frequency of meetings; 

(iii) The methodology, criteria, and processes used to develop a transmission plan; 

(iv) The method of disclosure of criteria, assumptions and data underlying a 

transmission plan; 

(v) The obligations of and methods for Transmission Customers to submit data to the 

Transmission Provider; 

(vi) The dispute resolution process; 

(vii) The Transmission Provider’s study procedures for economic upgrades to address 

congestion or the integration of new resources; 

(viii) The Transmission Provider’s procedures and mechanisms for evaluating 

transmission projects proposed to achieve public policy requirements established 

by state or federal laws or regulations; and 

(ix) The relevant cost allocation method or methods. 

Intraregional Transmission Planning

The Transmission Provider shall participate in a regional transmission planning process 
Docket No. RM10-23-000 - 128 - 

through which transmission facilities and non-transmission solutions may be proposed 

and evaluated. The regional transmission planning process also shall develop a regional 

transmission plan that identifies the transmission facilities necessary to meet the needs of 

transmission providers and transmission customers in the transmission planning region. 

The regional transmission planning process must not be unduly discriminatory and must 

be consistent with the provision of Commission-jurisdictional services at rates, terms and 

conditions that are just and reasonable, as described in the Final Rule in Docket No. 

RM10-23-000. The regional transmission planning process shall be described in an 

attachment to the Transmission Provider’s Tariff. 

The Transmission Provider’s regional transmission planning process shall satisfy the 

following seven principles, as set out and explained in the Final Rule in Docket No. 

RM05-25-000: coordination, openness, transparency, information exchange, 

comparability, dispute resolution, and economic planning studies. The regional 

transmission planning process shall also include the procedures and mechanisms for 

evaluating transmission projects proposed to achieve public policy requirements 

established by state or federal laws or regulations consistent with the Final Rule in 

Docket No. RM10-23-000. The regional transmission planning process shall provide a 

mechanism for the recovery and allocation of planning costs consistent with the Final 

Rule in Docket No. RM05-25-000. 

Nothing in the regional transmission planning process shall include an unduly 
Docket No. RM10-23-000 - 129 - 

discriminatory process for transmission project submission and selection. The regional 

transmission planning process shall provide on a not unduly discriminatory basis for the 

sponsor of a facility that is selected through the regional transmission planning process 

for inclusion in the regional transmission plan to have a right, consistent with state or 

local laws or regulations, to construct and own that facility and to recover the cost of that 

facility through the applicable regional cost allocation method. 

The description of the regional transmission planning process must include sufficient 

detail to enable Transmission Customers to understand: 

(i) The process for consulting with customers; 

(ii) The notice procedures and anticipated frequency of meetings; 

(iii) The methodology, criteria, and processes used to develop a transmission plan; 

(iv) The method of disclosure of criteria, assumptions and data underlying transmission 

plan; 

(v) The obligations of and methods for transmission customers to submit data; 

(vi) The dispute resolution process; 

(vii) The study procedures for economic upgrades to address congestion or the 

integration of new resources; 

(viii) The procedures and mechanisms for evaluating transmission projects proposed to 

achieve public policy requirements established by state or federal laws or 

regulations; and 
Docket No. RM10-23-000 - 130 - 

(ix) The relevant cost allocation method or methods. 

The regional transmission planning process must include a cost allocation method or 

methods that satisfy the six principles set forth in the final rule in Docket No. RM10-23-

000. 

Interregional Transmission Planning

The Transmission Provider, through its regional transmission planning process, must 

coordinate with the public utility transmission providers in each neighboring transmission 

planning region within its interconnection to address transmission planning issues related 

to interregional transmission facilities. This coordination between each pair of 

transmission planning regions must be reflected in an interregional transmission planning 

agreement filed with the Commission. The interregional transmission planning 

agreement must include a detailed description of the process for coordination between 

public utility transmission providers in neighboring transmission planning regions (i) 

with respect to each interregional transmission facility that is proposed to be located in 

both transmission planning regions and (ii) to identify possible interregional transmission 

facilities that could address transmission needs more efficiently than separate 

intraregional transmission facilities. 

The Transmission Provider must ensure that the following elements are included in any 

interregional transmission planning agreement in which it participates: 
Docket No. RM10-23-000 - 131 - 

(1) A commitment to coordinate and share the results of each transmission 

planning region’s regional transmission plans to identify possible interregional facilities 

that could address transmission needs more efficiently than separate intraregional 

facilities; 

(2) An agreement to exchange at least annually planning data and information; 

(3) A formal procedure to identify and jointly evaluate transmission facilities that 

are proposed to be located in both transmission planning regions; and 

(4) A commitment to maintain a website or e-mail list for the communication of 

information related to the coordinated planning process. 

The Transmission Provider must work with transmission providers located in neighboring 

transmission planning regions to develop a mutually agreeable method or methods for 

allocating between the two transmission planning regions the costs of a new interregional 

transmission facility that is located within both transmission planning regions. Such cost 

allocation method or methods must satisfy the six principles set forth in the final rule in 

Docket No. RM10-23-000. 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

 

 

Transmission Planning and Cost Allocation by Docket No. RM10-23-000 

Transmission Owning and Operating Public Utilities 

(Issued June 17, 2010) 

MOELLER, Commissioner, concurring: 

As I have repeatedly stressed in my years on this Commission, promoting 

investment in our nation’s transmission infrastructure has been my top policy priority.1

 

Robust electric transmission infrastructure is the ultimate “enabling” energy technology, 

as it can provide a more efficient electric system, enhanced reliability, increased access to 

less expensive and often cleaner resources, and the ability to harness location-constrained 

renewable resources. Conversely, the lack of adequate transmission investments often 

disproportionately raises consumer rates due to congestion, threatens the reliability of the 

nation’s bulk power system, and increases reliance on older and dirtier generating 

resources. 

While I am not certain that every policy in this proposed rule will ultimately be 

adopted, I am certain that building needed transmission lines is often the lowest-cost way 

to improve the delivery of electricity service. Although the Commission could have 

addressed regional cost allocation several years ago when it first became apparent that the 

organized markets were not reaching consensus on the issue, that wait is over and the 

Commission is now considering specific proposals to resolve cost allocation. 

 1 NSTAR Elec. Co., 125 FERC ¶ 61,313 (2008) (Moeller, Comm’r, dissenting in 

part) (“... the Commission should do what it can to encourage capital investment in 

needed transmission infrastructure projects.”); Commonwealth Edison Co. and 

Commonwealth Edison Co. of Indiana, 125 FERC ¶ 61,250 (2008) (Moeller, Comm’r, 

dissenting) (“... now is not the time for this Commission to discourage investment in 

needed transmission infrastructure.”); New York Indep. Sys. Operator, Inc., 129 FERC ¶ 

61,045 (2009) (Moeller, Comm’r, dissenting) (“The main issue here is whether needed 

transmission is being built ... I have encouraged investment in transmission infrastructure 

...”); Southern California Edison Co., 129 FERC ¶ 61,013 (2009) (Moeller, Comm’r, 

dissenting in part) (“The transmission that is needed in this nation will not be built unless 

the companies that build it can attract adequate investment dollars.”)
Docket No. RM10-23-000 - 2 - 

 

Given that the U.S. Congress is examining cost allocation at this time, our 

issuance of this proposed rule comes at a potentially sensitive time. While Congress is 

now considering several measures that deal directly with issues addressed in this 

proposed rule, I expect that this Commission will defer to the legislative branch as we 

move forward in our deliberations. This proposed rule, and the comments to follow, will 

provide the Congress with the framework of the issues that we consider relevant and the 

opportunity for Congress to provide further guidance to us. Thus, our action today is not 

intended to interfere with that process, but rather to add helpful information and evidence 

that will be useful in the formation of federal legislation. 

Also controversial will be the question of whether incumbent utilities should retain 

rights of first refusal that were created under the Commission’s jurisdiction. Alas, the 

question of whether transmission developers can compete on par with an incumbent 

transmission-owning utility is no longer theoretical. In recent cases, the Commission has 

been confronted with particular situations where competitors could be discouraged (or 

altogether blocked) from building a transmission project if the incumbent utility retains 

the right of first refusal.2

 While initial rulings have been rendered in these cases, the 

generic issue is ready for further discussion in this rulemaking. 

 Resolving controversial issues is rarely easy and I expect today’s proposed rule to 

be both lauded and criticized. The changes proposed here are significant, but the future 

success of the organized markets and the nation’s electric transmission system depend on 

resolving these long-debated and controversial issues. 

Staff’s efforts here have resulted in a proposal that will lead to a much needed 

conversation on how to best encourage needed capital investment. This will not be an 

easy matter to address when it comes before the Commission for a vote on the final rule, 

and for that reason this Commission should carefully consider the comments that we will 

receive. I will do my part to ensure that this Commission does not lose sight of the 

ultimate goal: a final rule that results in needed capital investment. 

 _______________________ 

 Philip D. Moeller 

 Commissioner 

2 Primary Power, LLC, 131 FERC ¶ 61,015 (2010) (reh’g pending) and Cent. 

Transmission, LLC v. PJM Interconnection L.L.C., 131 FERC ¶ 61,243 (2010).