Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection

Federal RegisterJul 27, 2021

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM21-17-000]

Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Advance notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is issuing an Advance Notice of Proposed Rulemaking (ANOPR) presenting potential reforms to improve the electric regional transmission planning and cost allocation and generator interconnection processes. The Commission invites all interested persons to submit comments on the potential reforms and in response to specific questions.

DATES:

Comments are due October 12, 2021 and Reply Comments are due November 9, 2021.

ADDRESSES:

Comments, identified by docket number, may be filed in the following ways. Electronic filing through

https://www.ferc.gov,

is preferred.

•

Electronic Filing:

Documents must be filed in acceptable native applications and print-to-PDF, but not in scanned or picture format.

• For those unable to file electronically, comments may be filed by U.S. Postal Service mail or by hand (including courier) delivery.

○

Mail via U.S. Postal Service only:

Addressed to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street NE, Washington, DC 20426.

○

For delivery via any other carrier (including courier):

Deliver to: Federal Energy Regulatory Commission, Office of the Secretary, 12225 Wilkins Avenue, Rockville, MD 20852.

The Comment Procedures Section of this document contains more detailed filing procedures.

FOR FURTHER INFORMATION CONTACT:

David Borden (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734,

david.borden@ferc.gov

Christopher Gore (Technical Information), Office of Energy Market Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8507,

christopher.gore@ferc.gov

Lina Naik (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8882,

lina.naik@ferc.gov

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.

I. Introduction

II. Background

A. Regional Transmission Planning and Cost Allocation Process

1. Regional Transmission Planning Requirements

2. Nonincumbent Transmission Developer Reforms

3. Regional Transmission Cost Allocation

4. Interregional Transmission Coordination

B. Overview of Transmission Planning

1. Reliability Needs

2. Economic Needs

3. Public Policy Requirement Needs

4. Local Transmission Facilities in the Regional Transmission Planning Process

C. Overview of Generator Interconnection

D. Interaction Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes

E. Current Funding Paradigm

1. Regional Transmission Cost Allocation

2. Local Transmission Facilities

3. Interconnection-Related Network Upgrades

III. The Potential Need for Reform

A. The Existing Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes May Be Inadequate To Ensure Just and Reasonable Rates

1. Considering Anticipated Future Generation

2. Results of Existing Local and Regional Transmission Planning Processes

3. Cost Responsibility for Transmission Facilities and Interconnection-Related Network Upgrades

IV. Consideration of Potential Reforms and Request for Comment

A. Regional Transmission Planning and Cost Allocation Processes

1. Potential Reforms and Request for Comment

a. Planning for the Transmission Needs of Anticipated Future Generation

i. Future Scenarios and Modeling Anticipated Future Generation

ii. Identifying Geographic Zones That Have Potential for High Amounts of Renewable Resource Development to Meet Increased Demand

iii. Incentivizing Regional Transmission Facilities

iv. Enhanced Interregional or State-to-State Coordination

b. Coordinating Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes

B. Identification of Cost and Responsibility for Regional Transmission Facilities and Interconnection-Related Network Upgrades

1. Relevant Cost Causation Precedent

2. Cost Allocation for Transmission Facilities Planned through the Regional Transmission Planning Process

a. Background

b. Potential Need for Reform

c. Potential Reforms and Request for Comment

3. Participant Funding and Crediting Policy for Funding Interconnection-Related Network Upgrades

100

a. Background

101

i. Original Rationale for the Order No. 2003 Interconnection-Related Network Upgrade Funding Requirements

101

(a) Crediting Policy

102

(b) Participant Funding

105

b. Potential Need for Reform

111

i. Participant Funding

111

ii. Crediting Policy

120

c. Potential Reforms and Request for Comment

121

i. Eliminate Participant Funding for Interconnection-Related Network Upgrades

123

ii. Revisions to the Existing Crediting Policy

131

(a) Transmission Providers Provide Upfront Funding for All Interconnection-Related Network Upgrades

132

(b) Interconnection Customers Contribute to the Upfront Funding of Interconnection-Related Network Upgrades Through a Fee

135

139

(d) Allocate the Upfront Cost of Interconnection-Related Network Upgrades on a Percentage Basis

146

iii. Additional Considerations

150

(a) Interconnection-Related Network Upgrade Cost Sharing

150

(b) Option To Build

151

153

(d) Fast-Track for Interconnection of Generating Facilities Committed to Regional Transmission Facilities

154

(e) Fast-Track for Interconnection of “Ready” Generating Facilities

157

(f) Grid-Enhancing Technologies

158

C. Enhanced Transmission Oversight

159

1. Potential Need for Reform

160

2. Potential Reforms and Request for Comment

163

a. State Oversight

176

b. Limitation on Recovery of Costs for Abandoned Projects

178

c. Additional Oversight Approaches

180

D. Transition

181

V. Comment Procedures

183

VI. Document Availability

186

I. Introduction

1. Pursuant to its authority under section 206 of the Federal Power Act (FPA),

the Federal Energy Regulatory Commission (Commission) is considering the potential need for reforms or revisions to existing regulations to improve the electric regional transmission planning and cost allocation and generator interconnection processes.

16 U.S.C. 824e. Section 206 requires that transmission rates be just and reasonable, and not unduly discriminatory or preferential.

2. Approximately 10 years ago, the Commission issued Order No. 1000.

That order stated its purpose generally in its introduction:

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

Order No. 1000, 136 FERC ¶ 61,051 (2011),

order on reh'g,

Order No. 1000-A, 139 FERC ¶ 61,132,

order on reh'g and clarification,

Order No. 1000-B, 141 FERC ¶ 61,044 (2012),

aff'd sub nom. S.C. Pub. Serv. Auth.

FERC,

762 F.3d 41 (D.C. Cir. 2014).

The reforms herein are intended to improve transmission planning processes and cost allocation mechanisms under the

pro forma

Open Access Transmission Tariff (OATT) to ensure that the rates, terms and conditions of service provided by public utility transmission providers are just and reasonable and not unduly discriminatory or preferential. This Final Rule builds on Order No. 890,

in which the Commission, among other things, reformed the

pro forma

OATT to require each public utility transmission provider to have a coordinated, open, and transparent regional transmission planning process. After careful review of the voluminous record in this proceeding, the Commission concludes that the additional reforms adopted herein are necessary at this time to ensure that rates for Commission-jurisdictional service are just and reasonable in light of changing conditions in the industry. In addition, the Commission believes that these reforms address opportunities for undue discrimination by public utility transmission providers.

Preventing Undue Discrimination and Preference in Transmission Service,

Order No. 890, 118 FERC ¶ 61,119,

order on reh'g,

Order No. 890-A, 121 FERC ¶ 61,297 (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,

order on clarification,

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

Order No. 1000, 136 FERC ¶ 61,051 at P 1.

3. More than a decade after Order No. 1000, we believe it appropriate to review the issues addressed by that order and other transmission-related regulations and determine whether additional reforms to the regional transmission planning and cost allocation and generator interconnection processes or revisions to existing regulations are needed to ensure rates for Commission-jurisdictional service remain just and reasonable, and not unduly discriminatory or preferential. The electricity sector is transforming as the generation fleet shifts from resources located close to population centers toward resources, including renewables, that may often be located far from load centers. The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources are creating new demands on the transmission system. Ensuring just and reasonable rates as the resource mix changes, while maintaining grid reliability, remains the priority in the regional transmission planning and cost allocation and generator interconnection processes.

4. In light of these evolving conditions, we believe it timely and appropriate to consider whether there should be changes in the regional transmission planning and cost allocation and generator interconnection processes and, if so, which changes are necessary to ensure that transmission rates remain just and reasonable and not unduly discriminatory or preferential and that reliability is maintained.

Accordingly, we will consider herein whether and which reforms and revisions are necessary to the Commission's regulations on these topics. This Advanced Notice of Proposed Rulemaking (ANOPR) discusses proposals or concepts for changes to existing processes in several broad categories: Regional transmission planning, regional cost allocation, generator interconnection funding, generator interconnection queueing processes and consumer protection, and in several instances the ANOPR also offers a potential rationale or argument for potential proposals. We note that the Commission has not predetermined that any specific proposal discussed herein shall or should be made or in what final form; rather, we seek comment from the public on these proposals and welcome commenters to offer additional or alternative proposals for consideration.

16 U.S.C. 824e.

5. We believe it appropriate to review whether there are questions that should be explored and possible solutions proposed regarding any potential shortcomings in the existing regional transmission planning and cost allocation and generator interconnection processes, which may have become evident since the Commission issued Order No. 2003,

Order No. 890, and Order No. 1000. We seek comment on several topics across transmission planning and cost allocation and interconnection queue processes, as well as oversight of transmission infrastructure development. Examples

of such questions for which we will seek comment in this ANOPR include, among others: (1) Whether the existing regional transmission planning and cost allocation processes appropriately considers the transmission needs of anticipated future generation to drive study assumptions, or instead relies on less comprehensive information, such as existing interconnection requests with completed facilities studies, and whether such current planning criteria are appropriate or should be revised; (2) whether the regional transmission planning and cost allocation processes' consideration of transmission needs driven by reliability, economic considerations, and Public Policy Requirements

are inappropriately siloed from one another, and, if so, whether this influences the consideration of potential benefits of a regional transmission facility (and the associated beneficiaries for purposes of allocating the costs of such a facility);

(3) whether criteria in addition to those related to reliability, economic, and Public Policy Requirements needs should be planned for and considered in the evaluation of benefits, and used to determine cost allocation in the regional transmission planning process, and these needs should be clear, credibly quantifiable and not speculative; (4) how to appropriately identify and allocate the costs of new transmission infrastructure in a manner that satisfies the Commission's cost-causation principle that costs are allocated to beneficiaries in a manner that is at least roughly commensurate with estimated benefits; (5) whether or not it is appropriate for the costs of state or local public policy-driven transmission facilities to be shifted through regional cost allocation to consumers in non-participating states, or whether changes to current interconnection cost allocation mechanisms may unjustly and unreasonably shift costs to customers of load serving entities;

(6) whether and which reforms are necessary to the generator interconnection process to ensure a more purposeful integration with the regional transmission planning and cost allocation processes, a more efficient queueing process, and a more efficient and cost-effective allocation of interconnection costs; (7) whether the regional transmission planning and cost allocation processes may have resulted in transmission facilities addressing an unduly narrow set of transmission needs, including needs located in a single transmission owner's footprint, and having limited region-wide benefits, but that, collectively, may impose significant costs on customers; (8) whether and how to better coordinate between regional and local transmission planning processes to identify more efficient or cost-effective solutions; and (9) whether it is necessary, and how, to more clearly identify the lines of regulatory authority and oversight between states and federal authorities with regard to regional and local transmission facilities to ensure appropriate vetting of transmission infrastructure. In addition, we seek comment regarding whether the current approach to oversight of transmission investment adequately protects customers, particularly given the potentially significant and very costly investments proposed to meet the transmission needs driven by a changing resource mix, and, if customers are not adequately protected from excessive costs, which potential reforms may be required and are legally permissible to ensure just and reasonable rates.

Standardization of Generator Interconnection Agreements and Procedures,

Order No. 2003, 104 FERC ¶ 61,103 (2003),

order on reh'g,

Order No. 2003-A, 106 FERC ¶ 61,220,

order on reh'g,

Order No. 2003-B, 109 FERC ¶ 61,287 (2004),

order on reh'g,

Order No. 2003-C, 111 FERC ¶ 61,401 (2005),

aff'd sub nom. Nat'l Ass'n of Regul. Util. Comm'rs

FERC,

475 F.3d 1277 (D.C. Cir. 2007) (

NARUC

FERC

Public Policy Requirements are requirements established by local, state, or federal laws or regulations (

i.e.,

enacted statutes passed by the legislature and signed by the executive and regulations promulgated by a relevant jurisdiction, whether within a state or at the federal level). Order No. 1000, 136 FERC ¶ 61,051 at P 2. The Commission clarified that Public Policy Requirements established by state or federal laws or regulations include duly enacted laws or regulations passed by a local governmental agency, such as a municipal or county government. Order No. 1000-A, 139 FERC ¶ 61,132 at P 319. Order No. 1000 left planning and cost allocation for Public Policy Requirements largely to the discretion of transmission providers.

see also

Order No. 2003, 104 FERC ¶ 61,103 at P 679 (pursuant to a “policy of participant funding . . . those [that] benefit from a particular project pay for it”).

III. The Potential Need for Reform

A. The Existing Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes May Be Inadequate To Ensure Just and Reasonable Rates

30. As a result of changing circumstances since the Commission issued Order Nos. 890, 1000, and 2003, we believe it is now appropriate to examine whether the existing regional transmission planning and cost allocation and generator interconnection processes adequately account for the transmission needs of the changing resource mix, or whether reforms may be necessary to ensure that transmission rates remain just and reasonable and not unduly discriminatory or preferential.

1. Considering Anticipated Future Generation

31. Expansion of the transmission system generally occurs by design through a transmission provider's transmission planning processes, or ad hoc through its generator interconnection process. At present, it appears that regional transmission planning processes may not adequately model future scenarios to ensure that those scenarios incorporate sufficiently long-term and comprehensive forecasts of future transmission needs, including considering the needs of anticipated future generation in identifying needed transmission facilities. Although regional transmission planning processes may include some level of generation development in different future scenarios analyses, it appears that they tend to include in their baseline reliability models only those generators that have completed facilities studies, and thus are far along in the generator interconnection process. These baseline reliability models, by relying only on generators that have completed facilities studies, may only account for generation that will come online in the short term.

32. As a result, the generator interconnection process appears to be the principal means by which infrastructure is built to accommodate new generators. That process, however, focuses on a single interconnection request (or cluster of requests). In other words, the generator interconnection process is not designed to consider how to address anything beyond the reliability interconnection-related network upgrades required for a specific interconnection request or group of interconnection requests.

33. New transmission facilities often have a development lead time that exceeds the interconnection timing needs of those interconnection customers already in the queue. It appears that these types of transmission facilities may not currently be planned and built in advance to meet the needs of anticipated future generation and as a result, interconnection customers are assigned the costs to construct large, high-voltage transmission facilities.

34. In addition, because transmission planning processes generally do not plan for the needs of anticipated future generation, transmission infrastructure that is being developed in order to facilitate new generation is constructed largely through the generator interconnection process, which is unlikely to result in the economies of scale that could more efficiently or cost-effectively meet the needs of the changing resource mix.

35. Likewise, the existing generator interconnection process appears to focus on the limited set of facilities needed to reliably interconnect a single interconnection customer (or cluster of requests) at the interconnection service level that the interconnection customer requests. The generator interconnection process may not adequately consider whether it may be more efficient or cost-effective to consider the interconnection-related network upgrades needed for multiple anticipated future generators that are not in the same cluster or are not yet in the interconnection queue in areas that have abundant wind or solar attributes that could support multiple future generators.

We note that certain regions do have the ability to share costs of network upgrades with future generation, but this is generally limited to the short term. For example, Midcontinent Independent System Operator, Inc.'s (MISO's) Shared Network Upgrade construct allows interconnection customers to be repaid for portions of an interconnection-related network upgrade's cost if another interconnection customer uses that network upgrade within five years.

36. In addition, there may be a need for coordination between the regional transmission planning process and the generator interconnection process, the absence of which may result in inefficient investment in transmission infrastructure and ultimately unjust and unreasonable or unduly discriminatory or preferential rates. By considering the transmission needs of anticipated future generation in its regional transmission planning and cost allocation processes, a transmission provider may identify transmission facilities that could facilitate both the interconnection of new generation as well as address other identified transmission system needs—such as mitigating a reliability violation or reducing congestion—at a lower total cost than pursuing two separate transmission projects through the

generator interconnection and regional transmission planning and cost allocation processes. Without co-optimization of the two processes, however, there appears to be no system in place to jointly assess the benefits and allocate the costs of transmission facilities that yield benefits to both system loads and new generation.

2. Results of Existing Local and Regional Transmission Planning Processes

37. We seek to better understand whether the current transmission planning processes may be resulting increasingly in transmission facilities addressing a narrow set of transmission needs, often located in a single transmission owner's footprint. To the extent that the requirements of the regional transmission planning process result in transmission providers expanding predominately local transmission facilities, that process may fail to identify more efficient or cost-effective transmission facilities needed to accommodate anticipated future generation. We seek to better understand how the reforms of the federal right of first refusal in Order No. 1000 have shaped the type and characteristics of transmission facilities developed through regional and local transmission planning processes, such as a relative increase in investment in local transmission facilities or the diversity of projects resulting from competitive bidding processes.

3. Cost Responsibility for Transmission Facilities and Interconnection-Related Network Upgrades

38. The Commission cannot ensure just and reasonable rates without considering how to allocate the costs of transmission facilities and interconnection-related network upgrades that result from the regional transmission planning and cost allocation and generator interconnection processes to the entities that benefit from those facilities. As the Commission explained in Order No. 1000, the costs of transmission infrastructure must be allocated to its beneficiaries in a manner that is at least roughly commensurate with the benefits that they draw from those facilities.

We seek to better understand whether the current approach to allocating the costs of transmission infrastructure, including transmission facilities developed through the regional transmission planning and cost allocation processes and interconnection-related network upgrades planned through the generator interconnection process, continues to appropriately allocate the costs of those transmission facilities to the entities that ultimately benefit from them.

Order No. 1000, 136 FERC ¶ 61,051 at P 10.

39. The current regional transmission planning process considers transmission needs driven by reliability, economics, and Public Policy Requirements. We seek comment whether, by separating transmission facilities into types, transmission planning processes may fail to take into account the benefits of multi-faceted projects for the purposes of cost allocation.

40. The current approach to allocating the costs of interconnection-related network upgrades may fail to allocate costs in a manner that is roughly commensurate with benefits. As discussed above, the generator interconnection process identifies the interconnection facilities and interconnection-related network upgrades needed to interconnect a single interconnection request (or cluster of requests). Under the participant funding approach to financing the cost of interconnection-related network upgrades, the interconnection customer pays for the costs of such upgrades, even where they would provide benefits to other customers such as resolving congestion on the transmission system. At the time that the Commission issued Order No. 2003, it was less likely that interconnection customers would be assigned significant interconnection-related network upgrades through the interconnection study process. Now, however, there is little remaining existing interconnection capacity on the transmission system, particularly in areas with high degrees of renewable resources that may require new resources to fund interconnection-related network upgrades that are more extensive and, as a result, more expensive. The more significant the interconnection-related network upgrades needed to accommodate a new resource, the greater the potential that such upgrades may benefit more than just the interconnection customer. Where an interconnection customer elects not to pursue a generating facility with system-wide benefits that exceeds such facility's cost, net beneficial infrastructure would not be developed, potentially leaving a wide range of customers worse off as a result.

41. We also note that the cost of interconnection-related network upgrades can depend entirely on both the timing of when and the specific site where the interconnection customer enters the interconnection queue that may result in interconnection customers submitting multiple speculative interconnection requests in an effort to receive a favorable queue position and reduce their interconnection-related network upgrade costs.

When interconnection customers “test the waters” in this manner, it may lead to late-stage withdrawals of the excess interconnection requests that can then impede the transmission provider's ability to process its interconnection queue in an efficient manner. Because of the changing interconnection landscape since Order No. 2003, the Commission's interconnection pricing policy, and in particular participant funding, now may result in a situation where interconnection customers have a financial incentive to submit multiple speculative projects. As a result, we believe it may be time to reexamine the rationale behind the Commission's pricing policy established for interconnection-related network upgrades and to consider reforms to generator interconnection processes that would make such processes more efficient, less costly, and ensure that generation projects that are more “ready” than others are not unduly delayed in the queue. In consideration of generator interconnection process reforms, we remain mindful of the need to ensure that interconnection costs are not unjustly and unreasonably shifted to customers of load-serving entities.

See, e.g., Review of Generator Interconnection Agreements and Procedures,

Technical Conference Transcript, Docket No. RM16-12-000, at Tr. 211:10-21 (May 13, 2016) (Steve Naumann, Exelon Corporation) (filed Aug. 23, 2016) (“We would look at putting let's say new gas fired generation in PJM, it may have four queue positions. And we only intend to go through with one, that's not speculation, that's trying to get information on which is the most viable.”).

42. While a reassessment of Order No. 2003's assumptions pertaining to the Commission's interconnection pricing policy may be necessary, our focus is in line with Order No. 2003's finding that “relatively unencumbered entry into the market is necessary for competitive markets.”

Furthermore, the purpose of this examination is also consistent with the original objectives of Order No. 2003, namely to “limit opportunities for Transmission Providers to favor their owner generation” and to “facilitate market entry for generation competitors by reducing interconnection costs and time.”

At the same time, there is reason to question the contention in Order No. 2003 that participant funding provides more “efficient price signals and a more equitable allocation of costs than the crediting approach.”

Also, while the crediting policy “recognizes the reliability benefits of a stronger

transmission infrastructure and more competitive power markets that result from a policy that facilitates the interconnection of new generating facilities,”

we raise questions on whether there are improvements that can be made to the crediting policy or whether a different pricing policy may be more efficient.

Order No. 2003, 104 FERC ¶ 61,103 at P 11.

Id.

P 12.

Id.

P 695.

Order No. 2003-A, 106 FERC ¶ 61,220 at P 584.

43. We note that ensuring just and reasonable rates, while maintaining grid reliability, remain the priorities for regional transmission planning, and cost allocation processes, and generator interconnection processes, and any comments proposing revisions to existing regulations should address their impact on reliability and costs to customers. All proposed reforms or revisions to regulations proposed in this proceeding must be consistent with the Commission's authority under section 206 of the FPA.

IV. Consideration of Potential Reforms and Request for Comment

A. Regional Transmission Planning and Cost Allocation Processes

1. Potential Reforms and Request for Comment

a. Planning for the Transmission Needs of Anticipated Future Generation

44. We seek comment regarding whether transmission providers in each transmission planning region should amend the regional transmission planning and cost allocation processes to plan for the transmission needs of anticipated future generation to meet a changing resource mix, including generation that is not yet in the interconnection queue. We seek comment on whether the existing regional transmission planning and cost allocation processes fail to adequately account for anticipated future generation. We also seek comment on whether the possible failure to account for anticipated future generation results in inefficient investment in transmission infrastructure and causes customers to pay unjust and unreasonable rates for transmission service. We also seek comment on whether, and, if so, how the Commission could structure and implement a framework for considering the transmission needs of anticipated future generation in the regional transmission planning and cost allocation processes. Commenters should address how each suggested reform or revision to existing rules is consistent with the Commission's authority under the FPA.

45. Below, we describe potential changes to the regional transmission planning and cost allocation processes that may be components of a process that plans for transmission needs associated with anticipated future generation. We seek comment on each of these potential changes, including whether and, if so, how the potential changes may lead to identification of more efficient or cost-effective transmission solutions to meet the needs of anticipated future generation. We also seek comment on whether there exist other potential revisions that could improve regional transmission planning and cost allocation for anticipated future generation, either as alternatives to potential reforms discussed herein or as supplementary reforms.

i. Future Scenarios and Modeling Anticipated Future Generation

46. We seek comment on whether reforms are needed regarding how the regional transmission planning and cost allocation processes model future scenarios to ensure that those scenarios incorporate sufficiently long-term and comprehensive forecasts of future transmission needs. We seek comment on what factors shaping the generation mix are appropriate to use for transmission planning purposes, such as, for example: (1) Federal, state, and local climate and clean energy laws and regulations; (2) federal, state, and local climate and clean energy goals that have not been enshrined into law; (3) utility and corporate energy and climate goals; (4) trends in technology costs within and outside of the electricity supply industry, including shifts toward electrification of buildings and transportation; and (5) resource retirements. With regard to each factor that may be considered for inclusion in scenario modeling, we seek comment on the source of the Commission's authority to incorporate that factor in the regional transmission planning and cost allocation processes. In addition, we seek comment on whether the Commission should establish minimum requirements regarding future scenarios for transmission providers to use in their regional transmission planning, including modeling anticipated future generation in those scenarios. Commenters should also address whether and how any reforms or revisions to existing rules could unjustly and unreasonably shift additional costs to customers of load serving entities. Commenters should also address whether the status quo does or does not allocate costs in a manner roughly commensurate with benefits, and whether the status quo leads to rates that are unjust or unreasonable.

47. The current regional transmission planning and cost allocation processes vary regarding how far into the future transmission providers look when evaluating transmission needs driven by reliability, economic considerations, or Public Policy Requirements. In general, however, the extent to which regional transmission planning processes plan for anticipated future generation is often limited to generation in the generator interconnection queue with a completed facilities study, which represents a relatively short-term outlook, and therefore may under-forecast anticipated future generation on a longer-term basis (and the associated transmission needs of that anticipated future generation). As noted, planning and developing the transmission facilities needed to address more efficiently or cost-effectively the transmission needs of a changing resource mix will often take considerably longer than the typical development timeline of a generating facility that has completed a facilities study and by considering such a limited subset of generation resources, more cost-effective transmission facilities that address longer-term needs may never be developed.

48. In light of the above, we seek comment on whether, and if so, how the regional transmission planning process should be restructured to consider a longer-term outlook. We seek comment on whether developing plausible long-term scenarios would lead to the identification of more efficient or cost-effective transmission solutions in regional transmission plans, whether building transmission facilities to accommodate anticipated future generation is required to render rates just and reasonable, and whether there are deficiencies in existing regional transmission planning and cost allocation processes that would be cured by conducting such future scenarios planning. Specifically, we seek comment on whether the development of longer-term scenarios for planning purposes should be pursued and, if so: (1) The number of years into the future the scenarios should consider (including an explanation of how far ahead it is reasonable to forecast anticipated future generation and system requirements); (2) the inputs that should be considered in modeling anticipated future generation; (3) different transmission planning methods, including whether consideration should be given to multiple future scenarios, as well as how the planning process should consider the probabilities of future

scenarios; (4) whether and how transmission providers should account for an array of different future scenarios when identifying more efficient or cost-effective transmission solutions in regional transmission plans; (5) whether and how transmission providers should account for federal, state, local, and individual utility energy and climate goals (including federal, state and local laws and regulations, as well as other policies or goals), and the source of the Commission's authority to account for such laws, regulations, policies and goals; (6) whether and how transmission providers should plan for expected future generator retirements; (7) whether and how Grid-Enhancing Technologies

should be accounted for in determining what transmission is needed under such scenarios; (8) how benefits and costs of transmission infrastructure should be accounted for in such models, including how adjusted production costs should be calculated; (9) any other aspects of future scenarios modeling, including planning for anticipated future generation and associated transmission needs that would be useful for the Commission to consider.

Grid Enhancing Technologies increase the capacity, efficiency, or reliability of transmission facilities. These technologies include, but are not limited to: (1) Power flow control and transmission switching equipment; (2) storage technologies, and (3) advanced line rating management technologies. FERC,

Grid Enhancing Technologies,

Notice of Workshop, Docket No. AD19-9-000 (Sept. 9, 2019).

49. In addition, we seek comment on whether greater use of probabilistic transmission planning approaches may better assess the benefits of regional transmission facilities. While some transmission providers consider a small number of future scenarios as part of their transmission planning process, more advanced approaches, such as stochastic

techniques, may provide an opportunity to consider a broader array of potential future conditions. Accordingly, we seek comment on potential benefits and drawbacks of such techniques in regional transmission planning assessments, including whether these or other new approaches may facilitate the co-optimization of generation siting and transmission development, whether such methods capture savings in generation capital costs as well as production expenses that can be realized from transmission additions, and whether implementing such methods is required to render rates just and reasonable.

Stochastic models are frameworks for addressing optimization problems that involve uncertainty.

50. We also seek comment on which inputs and assumptions transmission providers would need to model to represent new generation sources, such as renewable resources, in order to reflect their actual performance, such as active power-frequency control, reactive power-voltage control, and fault ride-through capabilities, in the planning study cases and any additional studies in order to ensure that transmission planning solutions result in operating reliability for the future.

51. We seek comment on the extent to which anticipated generation and transmission facility retirements are reflected in future scenarios modeled by transmission providers, and whether modifications to regional market rules and coordination processes between local and regional plans could facilitate more accurate regional transmission plans that reflect such anticipated retirements.

52. In addition, should the use of certain long-term scenarios be shown appropriate as part of ensuring just and reasonable rates, we seek comment on whether and how the Commission should ensure that the regional transmission planning and cost allocation processes develop a sufficiently wide range of future scenarios. We seek comment on whether the Commission should consider principles or minimum requirements as a basis for establishing such scenarios. Given that states or other local governing bodies may be uniquely situated in determining how much anticipated future generation is needed, or in providing information related to infrastructure siting or resource mix as influenced by state and local policies, we seek comment on how their input should be reflected by transmission providers in developing a sufficiently wide range of future scenarios, including those for anticipated future generation, and the more efficient or cost-effective transmission facilities that may be necessary to facilitate those future scenarios. We seek comment on whether it is necessary to require transmission providers to modify the regional transmission planning and cost allocation processes, such as requiring additional stakeholder input, to develop future scenarios, including those for anticipated future generation, such that there are sufficient opportunities for stakeholders to assess the reasonableness of the results, as well as for future modifications to the planning process.

53. Finally, we seek comment on whether and how such long-term scenarios should be used in identifying and selecting solutions to meet future transmission needs. For example, as discussed below, should transmission providers focus on a broader set of benefits for transmission facilities and a portfolio of transmission facilities in identifying the more efficient or cost-effective transmission solutions? If so, how should regional planning processes determine the right set of benefits to factor into such an evaluation? Is maximizing net benefits an appropriate criterion to use to identify efficient and cost-effective transmission solutions? Should the willingness of some beneficiaries to pay for certain transmission infrastructure, for example utilities or corporations with renewable resource or zero carbon goals, be considered in determining whether to include the benefits within a broader set of benefits from transmission facilities, and if so then how? Is there a need to establish a minimum set of transmission facility benefits that transmission providers must incorporate into regional transmission planning decisions, and if so, is there also a need to regularly update the minimum set of transmission facility benefits?

ii. Identifying Geographic Zones That Have Potential for High Amounts of Renewable Resource Development To Meet Increased Demand

54. We seek comment on whether the Commission should require transmission providers in each transmission planning region to establish, as part of their regional transmission planning and cost allocation processes, a process to identify geographic zones that have the potential for the development of large amounts of renewable generation and plan transmission to facilitate the integration of renewable resources in those zones.

55. Examples of transmission planning and development initiatives that have identified geographic zones with the potential for the development of significant amounts of renewable resources and transmission to facilitate the integration of renewable resources in those zones include the Public Utility Commission of Texas's (Texas Commission) Competitive Renewable Energy Zones (CREZ) initiative

and MISO's Multi-Value Projects (MVP).

http://www.ercot.com/committee/crez

https://www.misoenergy.org/planning/planning/multi-value-projects-mvps/

56. California Independent System Operator Corporation (CAISO) offers another example of a regional transmission planning process identifying transmission facilities to accommodate renewable resources in

geographic zones that have the potential for high amounts of renewable resources. In a petition for declaratory order, the Commission approved a mechanism to facilitate the financing and development of transmission facilities to interconnect multiple resources that met CAISO's eligibility requirements, including a high voltage level and providing access to areas rich in renewable energy.

Cal. Indep. Sys. Operator Corp.,

119 FERC ¶ 61,061 (2007).

57. We seek comment on whether the Commission should require transmission providers in each transmission planning region to establish, as part of their regional transmission planning and cost allocation processes, a process that identifies geographic zones that have the potential for the development of large amounts of new generation, particularly renewable resources. We seek comment on whether and how such a process might interrelate with existing regional transmission planning and cost allocation processes within each region, and how long-term scenario planning discussed above may be used in this process or other relevant regional transmission planning and cost allocation processes. In addition, we seek comment on whether reforms to the current interregional transmission coordination process are needed or appropriate for making an approach along these lines effective. We also seek comment on: (1) How the Commission should structure this potential requirement; and (2) any potential best practices, analyses, models, and metrics that could be used to identify such zones, including the amount and type of potential generation that could be located there. As with the future scenarios transmission planning discussed above, we seek comment on whether and how states and local entities may provide input into the identification of such zones. We seek comment on whether, and, if so, how transmission providers can assess whether there is sufficient commercial interest in developing generation in any potential zones and transmission to interconnect the potential generation (for example, through studies or formal declarations of interest). We also seek comment on whether and, if so, what safeguards or incentives might be necessary to ensure that transmission infrastructure is built only to satisfy expected transmission needs and not overly speculative commercial interests. We also seek comment on whether any such requirement is consistent with the FPA's prohibition of unduly discriminatory or preferential rates.

58. We seek comment on whether the Commission should require transmission providers to account for trends in the resource mix in developing energy zones for anticipated future generation as part of planning for transmission needs related to such resources and if so, what would be the best way to do so? We seek comment whether it would be appropriate, as the resource mix further develops, to develop similar zones for the transmission needs driven by the development and interconnection of energy storage resources and how to do so.

59. In order to ensure that the more efficient or cost-effective transmission facilities are selected and that rates are just and reasonable, we also seek comment on whether: (1) Eligibility thresholds or criteria (

e.g.,

voltage levels, amount of new generation located within a given geographic area or load zone, etc.) may be appropriate to determine whether a proposed regional transmission facility should be considered as part of the regional transmission planning and cost allocation process for transmission facilities built for anticipated future generation; (2) whether the CREZ, MISO MVP, CAISO approaches, or other processes for identifying and planning for the needs of anticipated future generation are models for any potential requirements and, if so, which aspects of those initiatives the Commission should consider requiring transmission providers to implement, for example, the CREZ model of requiring future generation to financially commit in advance of construction; (3) whether there is a need for mechanisms to limit the risk to customers from planning for anticipated future generation, for example, we note CAISO's use of an

ex ante

cap on the total cost exposure to transmission customers in addressing generation resource interconnection, as one potential approach;

and (4) whether specific proposals are consistent with the Commission's FPA section 206 authority.

Id.

P 6.

60. We also seek comment on whether the regional transmission planning process could be structured in such a way that is more collaborative, relying on the knowledge and experience that transmission providers, project developers, state commissions, and other stakeholders have regarding optimal locations, the topography of the transmission network, and Public Policy Requirements, among other factors that will influence the location and amount of future renewable resources. We note that the CREZ process was highly collaborative, with the Electric Reliability Council of Texas (ERCOT) conducting workshops with stakeholders over a six-month period to consider and evaluate multiple transmission scenarios.

In addition to seeking comment on technical and collaborative approaches to identify geographic zones for future renewable resources, we seek comment on potential alternative proposals from stakeholders on how to identify where transmission facilities may be needed to accommodate anticipated future generation. Commenters should address whether, if implemented, such a scenario planning process should be the same or different in non-RTO/ISO versus RTO/ISO regions, and if different, what those differences should be. Commenters should address how any proposed changes to the regional planning and cost allocation processes increase the efficiency, or lower the costs, of such processes and whether such changes will help ensure a reliable power supply and/or will reduce or control the costs of transmission and generation services that are ultimately passed on to customers of load serving entities. Commenters should also address proposed cost allocation.

See

Texas Commission, Order on Rehearing, Docket No. 33672, at 3 (Oct. 7, 2008).

iii. Incentivizing Regional Transmission Facilities

61. To prioritize regional transmission facilities that may have greater benefit-to-cost ratios than local alternatives, we seek comment on whether and, if so, how to expand or improve any incentives to incent the development of regional transmission facilities that demonstrably may offer a more efficient or cost-effective solution to an identified need than local alternatives. As an example of a possible regional transmission incentive, we seek comment on whether or not any available return on equity adder incentive that may be available for RTO/ISO participation should be limited in applicability only to regional, and not local, transmission facilities, when those regional transmission facilities are selected as the more efficient or cost-effective solution to an identified transmission need.

iv. Enhanced Interregional or State-to-State Coordination

62. We recognize that potential reforms discussed for comment above may require greater interregional or

state-regional coordination to be fully realized in a just, reasonable and not unduly discriminatory or preferential manner. As a result, we seek comment on whether reforms to the current interregional transmission coordination process, including potentially requiring interregional transmission planning, are needed or appropriate for making the potential approaches discussed above effective, and whether such reforms are consistent with the Commission's authority under section 206 of the FPA.

63. We seek comment on whether, because an interregional project must first be selected in each of the neighboring regions' regional planning processes before being selected in the interregional process, this challenge to the current interregional coordination process is impeding the selection and development of efficient, cost-effective interregional projects and, if so, what revisions are necessary to address that barrier. Should the Commission require joint planning processes, rather than simply joint coordination, for neighboring regions? In light of the potential reforms to regional planning and cost allocation and generator interconnection processes being considered in this ANOPR, are there core principles or approaches that the Commission should also consider when reviewing the existing approach to interregional planning? For example, should the Commission establish interregional reliability planning criteria or consider renewable resource geographic zones during interregional planning? Beyond interregional planning, can and should the Commission provide alternate pathways for transmission facilities that benefit multiple regions to be assigned cost allocation to customers across multiple regions? For example, should the Commission allow for identification of benefits, and allocation of commensurate costs, to one region of a project selected in a neighboring region's regional transmission planning process? Finally, comments should address whether taking any proposed action is consistent with the Commission's authority under section 206 of the FPA.

64. In addition, we seek comment on whether and, if so, how a regional states committee or other organized body of state officials should participate in the development and evaluation of assumptions or criteria used for regional transmission planning and cost allocation and interregional coordination and cost allocation for transmission needs related to future scenarios, including for anticipated future generation or geographic generation zones.

b. Coordinating Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes

65. We seek comment on whether reforms are needed to improve the coordination between the regional transmission planning and cost allocation and generator interconnection processes. We seek comment on whether the Commission should require transmission providers to operate their regional transmission planning and cost allocation and generator interconnection processes on concurrent, coordinated timeframes, with the same or similar assumptions and methods, and whether such a potential requirement may identify more efficient or cost-effective transmission solutions that could address needs shared between the two processes.

66. We seek comment on how the regional transmission planning and cost allocation and generator interconnection processes could be better coordinated or integrated. For example, would use of similar timeframes and assumptions facilitate more efficient or cost-effective transmission solutions? How could these processes most effectively be co-optimized? We seek comment on whether and, if so, how interconnection requests that trigger the need for interconnection-related network upgrades that may provide regional transmission benefits could be studied in a way that accounts for the potential broader transmission benefits associated with, for example, resource adequacy, operating reliability, and similar needs, and in coordination with the regional transmission planning process? We seek comment on whether and how relevant information from the generator interconnection process could be integrated into regional transmission planning in a timely manner, and whether and how transmission providers could move beyond using the outputs of each process as a deterministic input into the other rather than optimizing together across approaches. We also seek comment on whether it may be possible and beneficial to combine certain aspects of the transmission planning and generator interconnection processes, and if so, how?

67. We also seek comment on whether and how the Commission could revise transmission planning criteria that transmission providers use in the generator interconnection process so that they could better identify more efficient or cost-effective interconnection-related network upgrades. As indicated earlier, we also seek comment on whether and how transmission providers could incorporate anticipated future generation, including resources in the interconnection queue, in the regional transmission planning and cost allocation processes. In particular, we encourage commenters to discuss how to address concerns regarding uncertainty, including speculative projects, in planning for anticipated future generation.

68. Further, we seek comment on whether and how more effectively accounting for anticipated future generation in transmission planning may reduce the costs of interconnection-related network upgrades. To the extent this is the case, how should such benefits be identified, and should they factor into the regional transmission planning and cost allocation process?

B. Identification of Cost and Responsibility for Regional Transmission Facilities and Interconnection-Related Network Upgrades

69. The Commission has repeatedly recognized that, where cost allocation methods do not appropriately account for benefits associated with new transmission facilities, they may result in rates that are not just and reasonable or are unduly discriminatory or preferential.

See

Order No. 890, 118 FERC ¶ 61,119 at P 557 (finding that how “the costs of new transmission facilities are allocated is critical to the development of new infrastructure” because “[t]ransmission providers and customers cannot be expected to support the construction of new transmission unless they understand who will pay the associated cost”); Order No. 1000, 136 FERC ¶ 61,051 at PP 484-487;

see also Ill. Commerce Comm'n

FERC,

576 F.3d 470, 476 (7th Cir. 2009) (

ICC

FERC

70. We seek comment on whether the existing approach to cost allocation in regional transmission planning processes fails to consider the full suite of benefits—and the associated beneficiaries—produced by transmission facilities developed to meet the transmission needs of the changing resource mix. We seek comment on whether the current approach omits relevant benefits of new transmission infrastructure and, if so, thereby fails to consider the entities that receive those benefits in the cost allocation process. What, specifically, are those other benefits that should be considered? In addition, while the regional transmission planning process considers transmission needs driven by reliability, economic considerations, and Public Policy Requirements, these types of transmission needs are, in

many cases, considered in isolation from one another and the cost allocation methods for transmission facilities developed in response to these needs are generally separated by type. We seek comment as to whether the existing regional transmission planning and cost allocation processes may not fully account for the full suite of benefits, including hard-to-quantify benefits, and may impede the allocation of the costs of transmission facilities needed to meet the transmission needs of the changing resource mix in a manner that is at least roughly commensurate with the actual benefits of those facilities. Getting that balance right is important not only to comply with the cost causation principle, but also because efforts to plan the transmission system to meet the needs of the changing resource mix will succeed only if the associated cost allocation methods are transparent, equitable, and practicable.

Cf. BNP Paribas Energy Trading GP

FERC,

743 F.3d 264, 268-269 (D.C. Cir. 2014) (

BNP Paribas Energy

) (“[T]he cost causation principle itself manifests a kind of equity. This is most obvious when we frame the principle (as we and the Commission often do) as a matter of making sure that burden is matched with benefit.” (citing

Midwest ISO Transmission Owners

FERC,

373 F.3d 1361, 1368 (D.C. Cir. 2004)

and Se. Mich. Gas Co.

FERC,

133 F.3d 34, 41 (D.C. Cir. 1998))); Order No. 1000, 136 FERC ¶ 61,051 at P 669 (explaining that requiring cost allocation methods be open and transparent ensures that such methods are just and reasonable and not unduly discriminatory or preferential, aids in development and construction of new transmission, and may avoid contentious litigation or prolonged stakeholder debate);

KN Energy, Inc.

FERC,

968 F.2d 1295, 1300-01 (D.C. Cir. 1992) (describing properly designed rates as producing revenues “ `

which match, as closely as practicable, the costs to serve each class or individual customer' ”

(emphasis in original)) (quoting

Ala. Elec. Coop., Inc.

FERC,

684 F.2d 20, 27 (D.C. Cir. 1982));

Pub. Serv. Co. of Colo.,

163 FERC ¶ 61,204, at P 14 (2018) (recognizing that “feasibility” is part of ratemaking, such that the Commission may appropriately “balance maximally reflecting cost causation with other competing policy goals,” such as promoting more efficient or cost-effective regional transmission planning).

71. With respect to cost allocation in the generator interconnection process, we seek comment as to whether the participant funding approach for interconnection-related network upgrades required for an interconnection request in RTOs/ISOs may no longer be just and reasonable. Participant funding may result in costly interconnection-related network upgrades being allocated entirely to interconnection customers while failing to account for the significant benefits that these interconnection-related network upgrades may provide to other anticipated future generators seeking to interconnect and/or existing or future transmission customers. We further seek comment on whether the narrow focus of the generator interconnection process results in only a subset of beneficiaries paying for transmission infrastructure that, in practice, may benefit many.

72. We seek comment on whether separating the regional transmission planning and cost allocation and generator interconnection processes may increasingly result in an only partial-accounting of the benefits of new transmission infrastructure, leaving some transmission and interconnection customers potentially bearing a disproportionate cost burden. We seek comment on whether any changes to the criteria used for considering which transmission facilities are selected in the regional transmission plan for purposes of regional cost allocation, as well as the formula for the regional allocation of costs of regional transmission facilities and for the cost of interconnection-related network upgrades, including changes to the definition of beneficiary, hold the potential to unjustly and unreasonably shift costs to customers of load serving entities. We seek comment on how any contemplated reforms or revisions to existing regulations are consistent with the FPA and its requirement for just and reasonable and not unduly discriminatory or preferential rates.

73. In the following sections, we address the relevant court and Commission precedent governing cost allocation and seek comment on a number of potential reforms to address these concerns and ensure that transmission rates remain just and reasonable and not unduly discriminatory or preferential.

1. Relevant Cost Causation Precedent

74. Pursuant to FPA sections 205 and 206, the Commission is responsible for ensuring that the rates, terms, and conditions for transmission of electricity in interstate commerce are just, reasonable, and not unduly discriminatory or preferential.

For a cost allocation approach to satisfy this standard, it must satisfy the cost causation principle. The cost causation principle requires that “all approved rates reflect to some degree the costs actually caused by the customer who must pay them”

and that costs “be allocated to those who cause the costs to be incurred and reap the resulting benefits.”

As the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit) further explained, 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.”

Courts “evaluate compliance with this . . . principle by comparing the costs assessed against a party to the burdens imposed or benefits drawn by that party.”

ICC

FERC,

the Seventh Circuit also stated that a cost allocation method can satisfy the cost causation principle if the Commission “has an articulable and plausible reason to believe that the benefits are at least roughly commensurate with” the allocation of the costs.

The Seventh Circuit stated, however, that satisfying this requirement does not require exacting precision, and the Commission need not “calculate benefits to the last penny, or for that matter to the last million or ten million or perhaps hundred million dollars.”

16 U.S.C. 824d, 824e.

KN Energy, Inc.

FERC,

968 F.2d at 1300.

S.C. Pub. Serv. Auth.,

762 F.3d at 87 (quoting

NARUC

FERC,

475 F.3d at 1285).

ICC

FERC,

576 F.3d at 476.

Midwest ISO Transmission Owners

FERC,

373 F.3d at 1368.

576 F.3d at 477.

Id.

(citing

Midwest ISO Transmission Owners

FERC,

373 F.3d at 1369).

2. Cost Allocation for Transmission Facilities Planned Through the Regional Transmission Planning Process

75. Potential reforms for which we seek comment in this ANOPR contemplate a more forward-looking approach to the regional transmission planning process that plans for anticipated future generation, potentially producing a different and broader set of benefits and beneficiaries. The following sections seek comment on potential reforms that may be necessary to ensure that the costs of transmission facilities developed to meet the transmission needs of the changing resource mix are allocated in a manner that is roughly commensurate with those benefits, while ensuring that any potential reforms or revisions to existing cost-allocation rules do not unjustly or unreasonably shift costs to any type of market participant or customers of load serving entities. We seek comment on whether certain benefits are not appropriate to account for under the FPA, and whether allocation of costs based on such benefits may be inconsistent with the Commission's statutory mandate.

a. Background

76. In Order No. 1000, the Commission determined that the lack of clear

ex ante

cost allocation methods that identify beneficiaries of proposed regional transmission facilities was

impairing the ability of transmission providers to implement more efficient or cost-effective transmission solutions identified in the regional transmission planning process. According to the Commission, the failure to address cost allocation in a way that aligns with the benefits of new transmission facilities could lead to needed transmission facilities not being built, adversely impacting ratepayers.

The Commission therefore required transmission providers to have in place a method, or set of methods, for allocating the costs of new transmission facilities selected in a regional transmission plan for purposes of cost allocation. To guide transmission providers, the Commission established a set of cost allocation principles that transmission providers' cost allocation methods must satisfy, with the goal of ensuring that the costs of transmission solutions chosen to meet regional transmission needs would be allocated to those that received benefits from them.

The Commission determined that this principles-based approach would result in the allocation of the costs of new transmission facilities in a manner that is at least roughly commensurate with the benefits received by those that pay those costs while allowing for regional flexibility.

Order No. 1000, 136 FERC ¶ 61,051 at P 499.

Id.

PP 9, 482-83.

Id.

P 10; Order No. 1000-A, 139 FERC ¶ 61,132 at P 647.

77. The six regional cost allocation principles that the Commission adopted in Order No. 1000 are: (1) Costs 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; (2) those that receive no benefit from transmission facilities, either at present or in a likely future scenario, must not be involuntarily allocated any of the costs of those transmission facilities;

(3) a benefit to cost threshold ratio, if adopted, cannot exceed 1.25 to 1;

(4) costs must be allocated solely within the transmission planning region unless another entity outside the region voluntarily assumes a portion of those costs;

(5) the method for determining benefits and identifying beneficiaries must be transparent;

and (6) there may be different methods for different types of transmission facilities, such as those needed for reliability, congestion relief, or to achieve Public Policy Requirements.

Although the Commission required the regional cost allocation methods to determine benefits and identify beneficiaries in a transparent manner, the Commission also recognized that “identifying which types of benefits are relevant for cost allocation purposes, which beneficiaries are receiving those benefits, and the relative benefits that accrue to various beneficiaries can be difficult and controversial.”

Consistent with this notion, the Commission declined to require transmission providers to adopt a universal or comprehensive definition of “benefits” and “beneficiaries”

of regional transmission facilities, instead allowing for regional flexibility and examining each region's definitions on compliance.

Order No. 1000, 136 FERC ¶ 61,051 at P 637.

Id.

P 646.

Id.

P 657.

Id.

P 668.

Id.

P 685.

Id.

P 501.

Order No. 1000-A, 139 FERC ¶ 61,132 at P 679 (explaining that Order No. 1000 does not define benefits and beneficiaries but rather requires transmission providers to be definite about benefits and beneficiaries for purposes of their cost allocation methods).

78. The result is that transmission providers in each transmission planning region have implemented varying regional transmission cost allocation methods to comply with the cost allocation principles of Order No. 1000, the majority of which allocate the costs of regional transmission facilities that address reliability needs separately from those that address economic needs and separately from those that address Public Policy Requirements. In other words, most regional transmission cost allocation methods do not consider whether a regional transmission facility addresses more than one category of needs, and therefore provides more than one category of transmission benefits.

79. That said, some transmission providers' Order No. 1000-compliant regional transmission cost allocation methods may recognize a broader number of benefits than others and identify the broader benefits across a portfolio of transmission facilities rather than on a facility-by-facility basis, whereas others may be more constrained. For example, MISO's MVP process is designed to identify a portfolio of regional transmission facilities that: (1) Reliably and economically enable regional public policy needs; (2) provide multiple types of regional economic value; and/or (3) provide a combination of regional reliability and economic value. Specifically, MISO MVPs must be above 100 kV, have a project cost of $20 million or more, and have a combined benefit-to-cost ratio greater than 1.0 and must be evaluated as part of a portfolio of transmission projects.

The costs of this MVP portfolio are allocated on a postage stamp basis across the MISO region.

MISO, FERC Electric Tariff, Attachment FF, Section II.C (85.0.0).

Id.

Section III.A.2.g.

80. Southwest Power Pool's (SPP) Balanced Portfolio process similarly considers broader transmission benefits.

SPP evaluates economic benefits of a portfolio of transmission facilities to achieve a balance where the benefits of the portfolio to each zone (as measured by adjusted production cost savings) equal or exceed the costs allocated to each zone over a 10-year period. By allocating costs such that the benefits to each zone will equal or exceed those costs, the Balanced Portfolio process ensures that SPP allocates costs in a manner that is least roughly commensurate with benefits by design. In addition, SPP may reallocate costs to ensure that the portfolio is balanced and, under certain conditions, including cancellation of a transmission facility or unanticipated decreases in benefits or increases in costs, may review a previously approved Balanced Portfolio and recommend reconfiguring the portfolio.

SPP's Balanced Portfolio was an initiative to develop a group of economic transmission projects that benefit the entire SPP region and to allocate those transmission project costs regionally. The SPP Board of Directors approved the Balanced Portfolio transmission projects in April 2009.

SPP OATT, attach. J (Recovery of Costs Associated With New Facilities), Section III.D.

81. As for allocating the costs of regional transmission facilities to generators, in Order No. 1000, while commenters requested that the Commission allow such costs to be allocated to generators as beneficiaries, the Commission determined that generator interconnection was outside the scope of the rulemaking.

However, the Commission also stated that transmission providers could propose a regional transmission cost allocation method that allocates costs directly to generators as beneficiaries, but any effort to do so must not be inconsistent with the Order No. 2003 generator interconnection process. The Commission noted that in not addressing these issues, it was neither minimizing the importance of evaluating the impact of generator interconnection requests during transmission planning, nor limiting the ability of transmission providers to use requests for generator interconnections in developing assumptions to be used in

the regional transmission planning process.

Order No. 1000, 136 FERC ¶ 61,051 at P 760.

Id.

P 760.

82. Nevertheless, at least one transmission provider considers interconnection customers as beneficiaries of new transmission facilities. The Commission approved CAISO's proposal whereby transmission customers initially fund the transmission expansion needed to facilitate interconnection through the transmission revenue requirement of the constructing transmission provider, and interconnection customers are assigned their pro rata share of the going-forward costs of using the transmission facility as their generators interconnect to the transmission system. Under CAISO's proposal, all transmission system users pay the costs of the unsubscribed portion of a new transmission facility until the line is fully subscribed.

100

The CAISO approach also includes an

ex ante

cap on the total cost exposure to transmission customers, which was set at 15% of the sum total of the net high-voltage transmission plant of all transmission providers, as reflected in their transmission revenue requirements and in the CAISO transmission access charge.

101

100

Cal. Indep. Sys. Operator Corp.,

119 FERC ¶ 61,061.

101

Cal. Indep. Sys. Operator Corp.,

119 FERC ¶ 61,061, at P 6.

b. Potential Need for Reform

83. This statement in Order No. 1000 rings as true today as it did then—“identifying which types of benefits are relevant for cost allocation purposes, which beneficiaries are receiving those benefits, and the relative benefits that accrue to various beneficiaries can be difficult and controversial.”

102

This is especially true for larger, regional transmission facilities that are both costly and could have potentially broad benefits. As the Commission recognized in Order No. 890, the manner in which the costs of new transmission facilities are allocated is “critical” to developing those facilities as is identifying the types of benefits and the associated beneficiaries of those facilities.

103

102

Order No. 1000, 136 FERC ¶ 61,051 at P 501.

103

Order No. 890, 118 FERC ¶ 61,119 at P 557.

84. The possible reforms for which we seek comment in this ANOPR seek to ensure the development of regional transmission facilities needed to meet the transmission needs of the changing resource mix occurs in a more efficient or cost-effective manner, at just and reasonable rates. Commenters should also address whether and how any reforms or revisions to existing rules could unjustly and unreasonably shift additional costs to customers of load serving entities. These reforms cannot be successful without ensuring that transmission providers and customers alike are able to identify the types of benefits of these transmission facilities can provide and also identify the beneficiaries that would receive those benefits, along with the relative proportion of benefits that accrue to each of those beneficiaries. The failure to account for all the benefits of a transmission facility while taking into account all the costs of the transmission facility does not allow for a fair examination of whether the costs are allocated roughly commensurate with the benefits. We seek comment on whether ignoring benefits of these transmission facilities may impair more efficient or cost-effective transmission development by limiting the number of facilities that overcome the cost-benefit threshold needed to justify the cost of new transmission, and if so, what the appropriate standard should be for identifying such benefits. This potential concern goes to the need to not only identify the types of benefits of these new transmission facilities, and to quantify those benefits where possible, but likewise to the need for transparent methods to calculate benefits and ascertain beneficiaries without being so burdensome that the methods hinder transmission development. We seek comment on whether customers of load serving entities should be required to pay the costs of regional transmission facilities that provide them only with unquantifiable or purported benefits, or be required to pay for costs driven by the public policies of state and local governments in states other than their own.

104

See, e.g.,

PJM's State Agreement Approach.

PJM Interconnection, L.L.C.,

142 FERC ¶ 61,214, at PP 142-143 (2013),

order on reh'g and compliance,

147 FERC ¶ 61,128, at P 92 (2014);

85. Currently, most regional cost allocation methods do not consider whether a regional transmission facility addresses more than one category of needs, thereby providing more than one category of transmission benefits. Specifically, although the regional transmission planning process considers transmission needs driven by reliability, economic considerations, and Public Policy Requirements,

105

these types of transmission needs are generally considered in a silo from one another; the cost allocation methods for regional transmission facilities developed in response to these needs are similarly for the most part separated by type. We seek comment on whether the result is a paradigm that may potentially fail to consider the suite of benefits that transmission facilities provide and therefore fails to allocate the costs of such facilities roughly commensurate with the benefits.

105

Order No. 1000 left planning and cost allocation for Public Policy Requirements largely to the discretion of transmission providers.

See supra

P 16. Moreover, under PJM's State Agreement Approach (see supra n.104), the costs of transmission facilities required to meet the public policy requirements of an individual state or group of states may not be shifted to customers in other, non-participating states.

86. We seek comment as to whether a shift to a more integrated and holistic process for regional transmission planning and cost allocation is appropriate. Such a shift may raise novel questions around which customers should pay for new transmission facilities and concerns about free riders benefitting from the transmission expansion without paying for their fair share. Under the potential reforms for which we seek comment in this ANOPR, the regional transmission planning process would identify transmission facilities that support future scenarios, including anticipated future generation, and improve pricing and cost allocation for interconnection-related network upgrades. In that scenario, interconnection customers themselves could be considered beneficiaries of transmission facilities that facilitate their interconnection, even if those transmission facilities were built prior to the generators entering the interconnection queue. We seek comment on whether merely making interconnection customers the beneficiaries fails to capture all of the relevant types of benefits for purposes of cost allocation of a regional transmission facility built to accommodate anticipated future generation. We also seek comment on whether it may therefore be preferable to consider developing new regional transmission cost allocation methods that measure all of the benefits of regional transmission facilities that are being assessed for potential selection in the regional transmission plan for purposes of cost allocation and that accrue to both transmission and interconnection customers.

87. We cannot ignore, of course, that it may be difficult to precisely quantify some of the benefits of transmission facilities, which can be a barrier to more broadly allocating the costs of those facilities among transmission and interconnection customers. Unlike costs, which are clearly defined and easily quantified, the scope of which transmission benefits count for purposes of cost allocation, and how well they need to be documented in order to be allocated to customers, is a distinct

challenge to achieving a fair allocation. Requiring transmission providers to produce overly detailed reports on benefits before the costs of a transmission facility can be allocated to transmission and interconnection customers could lead to cost allocations that undervalue the largest transmission expansions, no matter their efficiency. The task is in striking the right balance to ensure just and reasonable rates and the allocation of transmission costs roughly commensurate with benefits.

88. We also note that, with greater deployment of renewable resources, and in part to the extent that regions focus on a project-specific regional transmission cost allocation method, it is possible that benefits may be distributed unevenly across regions. For example, there are likely zones or sub-zones within a region that are rich in renewable resources and therefore have generation significantly in excess of the local load. These zones, and generators in these zones, may not be the only beneficiaries of regional transmission facilities built to access these resources as customers outside those zones may reap reliability or economic benefits that result from the expanded transmission system and access to low cost resources. We seek comment on whether current regional transmission cost allocation approaches may not adequately address these circumstances and may not provide workable frameworks for the identification of transmission beneficiaries and sharing of benefits.

89. We seek comment on whether there should be reforms to cost allocation in regional transmission planning and cost allocation processes, including considering potentially a portfolio approach to assessing regional transmission facilities and consideration of a minimum set of transmission benefits, while seeking additional information about cost allocation approaches that may inform such reforms. Commenters proposing specific changes to cost allocation should address how such proposals will result in costs being allocated in a manner roughly commensurate with benefits, and demonstrate that costs will not be disproportionately borne by any given class of customers in a manner inconsistent with the requirements of the FPA and precedent. Commenters should also address how such proposals impact customers of load serving entities and whether and how proposed new cost allocation formulae may shift costs to new categories of customers and whether such cost-shifting is just and reasonable and consistent with the requirements of the FPA.

c. Potential Reforms and Request for Comment

90. We seek comment on whether broader transmission benefits should be taken into account when planning the transmission system for anticipated future generation, and how such benefits should be identified and quantified. Some transmission providers,

e.g.,

SPP, MISO, CAISO, and recently the New York Independent System Operator, Inc. (NYISO), have used broader transmission benefits in selecting regional transmission facilities for purposes of cost allocation in their regional transmission planning processes.

91. In addition, under a portfolio approach to regional transmission cost allocation, multiple transmission facilities are considered together, and the collective benefits of the transmission facilities are measured. MISO's MVP and SPP's Balanced Portfolio method are examples of portfolio approaches to regional transmission cost allocation. We seek comment on whether a portfolio approach recognizes that a regional transmission planning process that considers a group of transmission facilities that collectively provide multiple benefits, including reliability, economic, and Public Policy Requirements benefits, among others, may be able to better identify more efficient or cost-effective transmission facilities when compared to a process that focuses only on individual transmission facilities or individual benefits. We seek comment on whether an approach that both estimates broader transmission benefits for regional transmission facilities beyond those that are currently considered and that also allocates the costs for a portfolio of those individual transmission facilities may provide a cost allocation method that better matches benefits to burdens over time.

106

We seek comment on whether such an approach may also be more accurate or less likely to lead to anomalous results.

106

See BNP Paribas Energy,

743 F.3d at 268-69 (framing the cost causation principle “as a matter of making sure that burden is matched with benefit”).

92. At the same time, we seek comment on whether there are circumstances in which the use of criteria other than reliability and economic considerations may result in projects being selected in the regional transmission plan for purposes of cost allocation that do not represent the optimal solution to the reliability or congestion problems identified and thus may not represent the most efficient or cost-effective solution for customers of the load serving entities both inside an RTO/ISO and in non-RTO/ISO region. Any proposals for changes to planning criteria and cost allocation should consider whether such proposals result in unjustly and unreasonably shifting costs to customers. We seek comment on whether the use of planning criteria beyond reliability and economic considerations may place the burden for the costs driven by Public Policy Requirements of one state on customers of load serving entities in non-participating states.

93. We seek comment on the current approaches that transmission providers take in defining transmission benefits for purposes transmission planning and cost allocation. For example, we are interested in how transmission providers calculate adjusted production costs, the extent to which transmission providers go beyond adjusted production costs in identifying transmission benefits, the types of benefits, and the methods for estimating. We also seek comment on the extent to which it may be challenging, for certain types of benefits, to identify the beneficiaries for cost allocation purposes. We seek comment on the extent to which the same set of benefits is currently used in regional transmission planning processes and their associated cost allocation processes, or whether some benefits are identified but not factored into cost allocation. Should the same set of benefits be used in all processes? If not, would it be appropriate to consider different benefits during the transmission planning and cost allocation stages? If so, what would be the basis for doing so?

94. We seek comment on the types of benefits provided by transmission facilities needed to meet the transmission needs of anticipated future generation that are relevant for cost allocation purposes and the manner in which those benefits can be quantified, if at all. This includes consideration of whether there are transmission benefits beyond those that transmission providers already take into account in allocating costs that the Commission should require all transmission providers to consider for regional transmission facilities. In other words, should the Commission require transmission providers to establish a broader set of transmission benefits for purposes of cost allocation than currently in use and, likewise, should the Commission adopt a minimum set of transmission benefits that must be considered? Such benefits could encompass economic benefits (

e.g.,

congestion reduction); resource adequacy benefits (

e.g.,

allowing imports to replace more expensive local generation, lowering required planning targets through increased diversity benefits); and reliability benefits (

e.g.,

avoided or deferred reliability transmission facilities, improved reserves sharing, increased voltage support). And to what extent are there benefits that will differ from region-to-region?

95. If there are types of benefits that cannot be quantified, but which are real and relevant to allocating the costs of regional transmission facilities roughly commensurate with benefits, we seek comment on how transmission providers can document and account for those benefits in crafting a cost allocation method. Similarly, we seek comment on whether the inability to precisely quantify benefits of transmission facilities can be a barrier to the development of those facilities, particularly those with potentially broad transmission benefits. If so, we are interested in what types of transmission facilities are most impacted and what types of benefits are typically associated with those types of transmission facilities, and how those benefits can be justified and quantified.

96. To the extent that there are relevant benefits that are difficult to quantify, we seek comment on ways in which the Commission can consider whether those benefits are appropriately credited to a regional transmission facility and accounted for as part of allocating the costs to beneficiaries. This includes consideration of when benefits of a transmission facility are sufficiently certain to justify a commensurately broad cost allocation, especially where those benefits are not susceptible to precise quantification. We also seek comment on whether it is appropriate to credit benefits that cannot be credibly quantified and whether, and if so, how, it is appropriate to factor such benefits into regional cost allocation.

97. In addition to identifying benefits, we also seek comment on best practices for identifying the beneficiaries of a transmission facility. For example, some interconnection-related network upgrades for generator interconnection may benefit more than a single interconnecting generator, however the scope (temporal and geographic) of such beneficiaries may not be clear. We seek comment on the efficacy and desirability of a regional transmission planning and cost allocation process that seeks to plan for future scenarios, including planning for anticipated future generation. What methods for ascertaining beneficiaries are most effective in allocating the costs of such facilities roughly commensurate with benefits? Are there threshold transmission system conditions that would enable the Commission to reasonably conclude that regional (or some greater or lesser geographical scope) allocation of costs is appropriate (such as the amount of congestion or level of interconnectedness in a particular area)? This necessarily links to our earlier questions about how to quantify benefits and what level of precision is required.

98. Along the same lines of identifying beneficiaries, we seek comment on whether the costs of transmission facilities planned in the regional transmission planning process for which we seek comment in this ANOPR should be allocated to both transmission and interconnection customers. As explained earlier, we are concerned about potential free-rider problems associated with interconnection customers that later connect to transmission facilities planned for anticipated future generation. We are therefore interested in approaches to cost allocation to ensure that both transmission and interconnection customers that benefit from those facilities pay their fair share. While we propose to potentially reform participant funding by interconnection customers of interconnection-related network upgrades, we are also considering how best to allocate costs of regional transmission facilities to interconnection customers (

e.g.,

whether cost allocation methods for regional transmission facilities should allocate a portion of the costs of a regional transmission facility directly to interconnection customers based on, for example, the capacity of the interconnection customer's generating facility).

99. We seek comment on the cost effectiveness of the reforms discussed herein. If the regional transmission planning and cost allocation processes are to consider transmission needs driven by anticipated future generation, is there a tradeoff between facilitating the construction of transmission facilities that are needed to connect such anticipated future generation, and ensuring against building more transmission than is necessary? If so, how should the Commission approach that tradeoff?

3. Participant Funding and Crediting Policy for Funding Interconnection-Related Network Upgrades

100. Since the issuance of Order No. 2003, the composition of the generation fleet has rapidly shifted from predominately large, centralized resources to include a large proportion of smaller renewable generators that, due to their distance from load centers, often require extensive interconnection-related network upgrades to interconnect to the transmission system. The significant interconnection-related network upgrades necessary to accommodate geographically remote generation are a result that the Commission did not contemplate when it established the interconnection pricing policy for interconnection-related network upgrades. Because the large-scale changes since Order No. 2003 may have impacted the underlying rationale for the interconnection pricing policy, we seek comment on whether the Commission should modify the participant funding and crediting policies, as discussed in further detail below.

a. Background

i. Original Rationale for the Order No. 2003 Interconnection-Related Network Upgrade Funding Requirements

101. As discussed above, the Commission in Order No. 2003 described two general approaches for assigning the costs of interconnection-related network upgrades needed to interconnect a generating facility to the transmission system: (1) the crediting policy, whereby the interconnection customer initially funds the interconnection-related network upgrades and is reimbursed through transmission credits;

107

and (2) participant funding, where the costs of interconnection-related network upgrades in RTOs/ISOs are assigned directly to the interconnection customer. Central to discussions of the Commission's interconnection-related network upgrade funding requirements is Order No. 2003's continued prohibition of “and” pricing. This prohibition provides that, when “a Transmission Provider must construct

[interconnection-related] Network Upgrades to provide new or expanded transmission service, the Commission generally allows the Transmission Provider to charge the higher of the embedded costs of the Transmission System with expansion costs rolled in, or incremental expansion costs, but not the sum of the two.”

108

The Commission also explained that allowing the transmission provider to charge either the higher of an embedded cost rate for transmission service or an incremental rate designed to recover the cost of the interconnection-related network upgrades “provides the Transmission Provider with a cost recovery mechanism that ensures that native load and other transmission customers will not subsidize service to the Interconnection Customer.”

109

107

Order No. 2003-B states that “the period for reimbursement may not be longer than the period that would be required if the Interconnection Customer paid for transmission service directly and received credits on a dollar-for-dollar basis, or 20 years [from the generating facility's commercial operation date], whichever is less.” Order No. 2003-B, 109 FERC ¶ 61,287 at PP 3, 36. If credits have not fully reimbursed the upfront payment within 20 years, Order No. 2003 requires “a balloon payment” at the end of year 20.

Id.

P 36. The crediting policy also requires that affected system operators provide credits for transmission service taken on an affected system.

Id.

P 42. Even if the interconnection customer does not take transmission service over the affected system, however, the affected system operator must still provide the 20-year balloon payment to refund any remaining balance to the interconnection customer. Order No. 2003-C, 111 FERC ¶ 61,401 at P 13.

108

Order No. 2003, 104 FERC ¶ 61,103 at n.111.

109

Order No. 2003-A, 106 FERC ¶ 61,220 at P 613.

(a) Crediting Policy

102. The Commission instituted the crediting policy to achieve multiple objectives. First, the Commission found that this policy would avoid prohibited “and” pricing for interconnection-related network upgrades because it ensures that the interconnection customer will not be charged twice for the use of the transmission system by paying both for the incremental cost of the upgrade and an embedded-cost rate (with the cost of that interconnection-related network upgrade rolled in) for use of the transmission system.

110

Also, the Commission stated that the crediting policy was intended to facilitate the efficient construction of interconnection-related network upgrades and enhance competition in bulk power markets by promoting the construction of new generation

111

Furthermore, the Commission found that the crediting policy would ensure comparable treatment for interconnection customers that are not affiliated with the transmission provider, as transmission providers traditionally roll the costs of interconnection-related network upgrades associated with their own generating facilities into their transmission rates.

112

110

Order No. 2003, 104 FERC ¶ 61,103 at P 694.

111

Id.

PP 612, 694.

112

Id.

P 694.

103. Additionally, in Order No. 2003-A, the Commission stated that it does “not believe that the costs of [interconnection-related] Network Upgrades required to interconnect a Generating Facility to the Transmission System of a non-independent Transmission Provider are properly allocable to the Interconnection Customer through direct assignment because upgrades to the transmission grid benefit all customers.”

113

The Commission also stated that the crediting policy has a two-fold purpose. First, by providing the transmission provider with a source of funds to construct the interconnection-related network upgrades, the upfront payment by the interconnection customer alleviates any delay that might result if the transmission provider were forced to secure funding elsewhere. Second, by placing the interconnection customer initially at risk for the full cost of the interconnection-related network upgrades, the upfront payment provides the interconnection customer with a strong incentive to make efficient siting decisions and, in general, to make good faith requests for interconnection service.

114

113

Order No. 2003-A, 106 FERC ¶ 61,220 at P 212. As noted in the discussion below on participant funding, the Commission has allowed direct assignment of interconnection-related network upgrade costs to generators interconnecting to independent transmission providers such as RTOs/ISOs.

114

Id.

P 613.

104. In

NARUC

FERC,

115

multiple petitioners challenged the crediting policy established in Order No. 2003. The petitioners argued that the crediting policy was inconsistent with the cost causation principle because they disagreed with the Commission's conclusions that “[interconnection-related] Network Upgrades benefit the entire network,”

116

and therefore, all transmission customers should essentially pay for those interconnection-related network upgrades through the crediting policy.

117

The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) agreed with the Commission's position and noted that the D.C. Circuit had previously “endorsed the approach of `assign[ing] the costs of system-wide benefits to all customers on an integrated transmission grid.' ”

118

115

475 F.3d 1277.

116

Id.,

475 F.3d at 1285.

117

Id.

(citing

Pub. Serv. Co. of Colo.,

62 FERC ¶ 61,013, at 61,061 (1993)).

118

Id.

(citing

W. Mass. Elec. Co.

FERC,

165 F.3d 922, 927 (DC Cir. 1999)).

(b)

Participant Funding

105. In Order No. 2003, the Commission stated that “under the right circumstances, a well-designed and independently administered participant funding policy for [interconnection-related] Network Upgrades offers the potential to provide more efficient price signals and a more equitable allocation of costs than the crediting approach.”

119

Therefore, the Commission stated that it would provide RTOs/ISOs with the flexibility to propose participant funding for interconnection-related network upgrades for a generator interconnection.

120

In accordance with this flexibility, the Commission did not prescribe specific policies for RTOs/ISOs but instead provided them with the flexibility to adopt policies of their own choosing, subject to Commission approval.

121

Over time, each RTO/ISO sought, and the Commission accepted, independent entity variations to adopt some form of participant funding rather than the crediting policy.

119

Order No. 2003, 104 FERC ¶ 61,103 at P 695.

120

Id.

P 28.

121

Order No. 2003-A, 106 FERC ¶ 61,220 at P 696.

106. The Commission expressed its willingness to consider a well-designed participant funding approach in response to commenter concerns that the crediting policy “mutes somewhat the Interconnection Customer's incentive to make an efficient siting decision that takes new transmission costs into account, and it provides the Interconnection Customer with what many view as an improper subsidy, particularly when the Interconnection Customer chooses to sell its output off-system.”

122

Additionally, while the Commission mandated the crediting policy for non-independent transmission providers, Order No. 2003 acknowledged that the concerns that gave rise to the adoption of the crediting policy do not apply to RTOs/ISOs. For example, Order No. 2003 noted that “a number of aspects of the `but for' approach are subjective, and a Transmission Provider that is not an independent entity has the ability and the incentive to exploit this subjectivity to its own advantage” by, for example, finding “that a disproportionate share of the costs of expansions needed to serve its own power customers is attributable to competing Interconnection Customers.”

123

In contrast, however, the Commission noted that RTOs and ISOs are independent, and neither own nor have affiliates that own generating facilities and thus do not have an incentive to discourage new generation by competitors.

124

122

Order No. 2003, 104 FERC ¶ 61,103 at P 695.

123

Id.

n.111.

124

Order No. 2003-A, 106 FERC ¶ 61,220 at P 691.

107. The Commission also explained that participant funding might speed up the development of new transmission infrastructure. In particular, Order No. 2003 postulated that “participant

funding of [interconnection-related network] upgrades may provide the pricing framework needed to overcome the reluctance of incumbent Transmission Owners in many parts of the country to build transmission, with the result that badly needed transmission infrastructure could be put in place quickly.”

125

Order No. 2003, 104 FERC ¶ 61,103 at P 703.

108. RTOs/ISOs that have adopted a participant funding approach do not reimburse interconnection customers with transmission service credits for the cost of the interconnection-related network upgrades. Instead, the Commission allowed interconnection customers to receive well-defined capacity rights that are created by the interconnection-related network upgrades.

126

As an example, the Commission in Order No. 2003 pointed to PJM Firm Transmission Rights and Capacity Interconnection Rights, which, it stated, are “created by the [interconnection-related] Network Upgrades for which the Interconnection Customer pays, and they are well-defined, long-term and tradeable.”

127

The Commission stated that provision of such “well-defined capacity rights” in lieu of credits does not violate the prohibition of “and” pricing because the “Interconnection Customer pays separate charges for separate services,” namely “an access charge for transmission service that may involve an obligation to pay congestion charges, and in exchange for its `but for' payment, [the interconnection customer] receives these well-defined capacity rights, which provide some protection for having to actually pay the congestion charges.”

128

126

Id.

P 700.

127

Id.

128

Id.

109. Commission precedent makes clear that the purpose of providing “well-defined” rights is not to provide full reimbursement for the costs of interconnection-related network upgrades. In fact, where an RTO/ISO adopts a participant funding approach for interconnection-related network upgrades required to interconnect an interconnection customer, there is no requirement that the capacity rights being awarded for interconnection-related network upgrades have equal value to the cost of the interconnection-related network upgrades because the costs would not exist “but for” the proposed interconnection and are simply part of a project's construction costs and business risk that the interconnection customer must consider.

129

Moreover, RTOs/ISOs are “not required to provide transmission capacity rights where . . . the network upgrades create no additional transmission capability.”

130

To this point, the Commission in

Old Dominion Electric Cooperative

PJM Interconnection, L.L.C.

explained that, while Order No. 2003 “stated that generation interconnection customers would receive capacity rights, those statements were based on the assumption that a network upgrade provided by an interconnection customer would create additional transmission capability beyond that needed to simply interconnect with the grid.”

131

129

PJM Interconnection, L.L.C.,

108 FERC ¶ 61,025, at P 20 (2004);

see also Midwest Indep. Transmission Sys. Operator, Inc.,

114 FERC ¶ 61,106, at P 66 (2006).

130

Old Dominion Elec. Coop.

PJM Interconnection, L.L.C.,

119 FERC ¶ 61,052, at P 18 (2007) (

ODEC

PJM

131

ODEC

PJM,

119 FERC ¶ 61,052 at P 18;