40266 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

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. 

Æ Mail via U.S. Postal Service only: 

Addressed to: Federal Energy 

Regulatory Commission, Office of the 

Secretary, 888 First Street NE, 

Washington, DC 20426. 

Æ 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 .................................................................................................................................................................................................................. 1 

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

A. Regional Transmission Planning and Cost Allocation Process ........................................................................................................................ 6 

1. Regional Transmission Planning Requirements .......................................................................................................................................... 8 

2. Nonincumbent Transmission Developer Reforms ....................................................................................................................................... 9 

3. Regional Transmission Cost Allocation ....................................................................................................................................................... 11 

4. Interregional Transmission Coordination .................................................................................................................................................... 12 

B. Overview of Transmission Planning ................................................................................................................................................................... 13 

1. Reliability Needs ........................................................................................................................................................................................... 14 

2. Economic Needs ............................................................................................................................................................................................ 15 

3. Public Policy Requirement Needs ................................................................................................................................................................ 16 

4. Local Transmission Facilities in the Regional Transmission Planning Process ....................................................................................... 17 

C. Overview of Generator Interconnection .............................................................................................................................................................. 18 

D. Interaction Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes ........................ 23 

E. Current Funding Paradigm .................................................................................................................................................................................. 24 

1. Regional Transmission Cost Allocation ....................................................................................................................................................... 24 

2. Local Transmission Facilities ....................................................................................................................................................................... 25 

3. Interconnection-Related Network Upgrades ................................................................................................................................................ 28 

III. The Potential Need for Reform .................................................................................................................................................................................. 30 

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

Ensure Just and Reasonable Rates ........................................................................................................................................................................ 30 

1. Considering Anticipated Future Generation ................................................................................................................................................ 31 

2. Results of Existing Local and Regional Transmission Planning Processes ............................................................................................... 37 

3. Cost Responsibility for Transmission Facilities and Interconnection-Related Network Upgrades .......................................................... 38 

IV. Consideration of Potential Reforms and Request for Comment .............................................................................................................................. 44 

A. Regional Transmission Planning and Cost Allocation Processes ..................................................................................................................... 44 

1. Potential Reforms and Request for Comment .............................................................................................................................................. 44 

a. Planning for the Transmission Needs of Anticipated Future Generation .......................................................................................... 44 

i. Future Scenarios and Modeling Anticipated Future Generation ......................................................................................................... 46 

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

Demand .................................................................................................................................................................................................... 54 

iii. Incentivizing Regional Transmission Facilities .................................................................................................................................. 61 

iv. Enhanced Interregional or State-to-State Coordination ...................................................................................................................... 62 

b. Coordinating Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes ....... 65

B. Identification of Cost and Responsibility for Regional Transmission Facilities and Interconnection-Related Network Upgrades ............. 69 

1. Relevant Cost Causation Precedent .............................................................................................................................................................. 74 

2. Cost Allocation for Transmission Facilities Planned through the Regional Transmission Planning Process ........................................ 75 

a. Background ............................................................................................................................................................................................. 76 

b. Potential Need for Reform ..................................................................................................................................................................... 83 

c. Potential Reforms and Request for Comment ....................................................................................................................................... 90 

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 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40267 

1 16 U.S.C. 824e. Section 206 requires that 

transmission rates be just and reasonable, and not 

unduly discriminatory or preferential. 

2Transmission 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. v. FERC, 762 F.3d 41 (D.C. Cir. 

2014). 

3Preventing 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). 4Order No. 1000, 136 FERC ¶ 61,051 at P 1. 

5 16 U.S.C. 824e. 

6Standardization 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 

v. FERC, 475 F.3d 1277 (D.C. Cir. 2007) (NARUC 

v. FERC). 

Paragraph Nos. 

(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 

(c) Transmission Providers Provide Upfront Funding for Only Higher Voltage Interconnection-Related Network Upgrades ........... 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 

(c) Interconnection Request Limit ............................................................................................................................................................. 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),1 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. 

2. Approximately 10 years ago, the 

Commission issued Order No. 1000.2

That order stated its purpose generally 

in its introduction: 

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. 890,3 in which the Commission, among 

other things, reformed the pro forma OATT 

to require each public utility transmission 

provider to have a coordinated, open, and 

transparent regional transmission planning 

process. After careful review of the 

voluminous record in this proceeding, the 

Commission concludes that the additional 

reforms adopted herein are necessary at this 

time to ensure that rates for Commissionjurisdictional service are just and reasonable 

in light of changing conditions in the 

industry. In addition, the Commission 

believes that these reforms address 

opportunities for undue discrimination by 

public utility transmission providers.4

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.5

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. 

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. 2003,6 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 


lotter on DSK11XQN23PROD with PROPOSALS2
40268 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

7Public 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 infra P 16. 

8A regional transmission facility is a 

transmission facility located entirely in one 

transmission planning region. Order No. 1000, 136 

FERC ¶ 61,051 at n.374. 

9Under current Commission policy, the costs of 

interconnection-related network upgrades are either 

(1) directly assigned to the interconnection 

customer or (2) funded initially by the 

interconnection customer and reimbursed through 

transmission service credits. 

10Promoting Wholesale Competition Through 

Open Access Non-Discriminatory Transmission 

Services by Public Utilities; Recovery of Stranded 

Costs by Public Utilities and Transmitting Utilities, 

Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996) 

(cross-referenced at 75 FERC ¶ 61,080), order on 

reh’g, Order No. 888–A, FERC Stats. & Regs. 

¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), 

order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248 

(1997), order on reh’g, Order No. 888–C, 82 FERC 

¶ 61,046 (1998), aff’d in relevant part sub nom. 

Transmission Access Policy Study Group v. FERC, 

225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New 

York v. FERC, 535 U.S. 1 (2002). 

11 In this order, we use the term ‘‘transmission 

provider’’ when referring to a public utility that 

owns, controls, or operates transmission facilities. 

The term transmission provider should be read to 

include the transmission owner when the 

transmission owner is separate from the 

transmission provider, as is the case in regional 

transmission organizations (RTOs) and independent 

system operators (ISOs). 

12Order No. 890, 118 FERC ¶ 61,119 at PP 418– 

601. 

13Order No. 1000, 136 FERC ¶ 61,051 at PP 11– 

12, 42–44; Order No. 1000–A, 139 FERC ¶ 61,132 

at PP 3, 4–6. 

14Order No. 1000, 136 FERC ¶ 61,051 at PP 146, 

148. 

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 7 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); 8

(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 nonparticipating states, or whether changes 

to current interconnection cost 

allocation mechanisms may unjustly 

and unreasonably shift costs to 

customers of load serving entities; 9 (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. 

II. Background 

A. Regional Transmission Planning and 

Cost Allocation Process 

6. In 1996, the Commission issued 

Order No. 888 and the accompanying 

pro forma OATT, setting forth certain 

minimum requirements for transmission 

planning.10 In 2007, the Commission 

issued Order No. 890 to remedy flaws in 

the pro forma OATT, and in so doing, 

required coordinated, open, and 

transparent transmission planning on 

both a local and regional level. 

Specifically, the Commission required, 

among other things, that each 

transmission provider’s 11 local 

transmission planning process satisfy 

nine transmission planning principles: 

(1) Coordination; (2) openness; (3) 

transparency; (4) information exchange; 

(5) comparability; (6) dispute resolution; 

(7) regional participation; (8) economic 

planning studies; and (9) cost allocation 

for new projects.12

7. In 2011, the Commission issued 

Order No. 1000 to build on the 

transmission planning requirements of 

Order No. 890. Order No. 1000 included 

a package of reforms to ensure that the 

transmission planning and cost 

allocation mechanisms embodied in the 

pro forma OATT were adequate to 

support the development of more 

efficient or cost-effective transmission 

facilities.13 The reforms in Order No. 

1000 fell into the following categories: 

(1) Regional transmission planning; (2) 

transmission needs driven by Public 

Policy Requirements; (3) nonincumbent 

transmission developer reforms; (4) 

regional and interregional cost 

allocation; and (5) interregional 

transmission coordination. Here we 

provide a brief overview of the Order 

No. 1000 regional transmission planning 

requirements, nonincumbent developer 

reforms, regional transmission cost 

allocation rules, and interregional 

transmission coordination. 

1. Regional Transmission Planning 

Requirements 

8. Order No. 1000 requires that each 

transmission provider participate in a 

regional transmission planning process 

that produces a regional transmission 

plan.14 Through the regional 

transmission planning process, 

transmission providers must evaluate, 

in consultation with stakeholders, 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40269 

15Order No. 1000’s requirement to consider 

transmission needs driven by Public Policy 

Requirements is described below. 

16Order No. 1000, 136 FERC ¶ 61,051 at PP 11, 

148. 

17 Id. P 151. Order No. 890 explains these 

transmission planning principles. 

18For purposes of Order No. 1000, 

‘‘nonincumbent transmission developer’’ refers to 

two categories of transmission developer: (1) A 

transmission developer that does not have a retail 

distribution service territory or footprint; and (2) a 

transmission provider that proposes a transmission 

facility outside of its existing retail distribution 

service territory or footprint, where it is not the 

incumbent for purposes of that project. Id. P 225. 

19 Id. P 313. 

20 Id. PP 5, 63. 

21 Id. PP 225, 323, 325. 

22 Id. P 328; Order No. 1000–A, 139 FERC 

¶ 61,132 at P 452. 

23Order No. 1000, 136 FERC ¶ 61,051 at P 332. 

24 Id. P 558. 

25 Id. P 603. 

26 Id. PP 622, 639. 

27 Id. P 396. 

28For example, Reliability Standard TPL–001–4 

requires that Transmission Planners conduct an 

annual planning assessment of their region’s 

portion of the bulk electric system and document 

summarized results of the steady state analyses, 

short circuit analyses, and stability analyses. TPL– 

001–4 also requires that Transmission Planners 

conduct these analyses using a model of their 

systems operating under a wide variety of potential 

conditions to see under what, if any, conditions the 

system will fail to meet reliability criteria. TPL– 

001–4 lays out the variety of these conditions, 

including system peak, off-peak, single 

contingency, multiple contingencies (both 

sequential and simultaneous), severe contingencies 

on adjacent systems, sensitivity analyses to 

underlying model assumptions, and extreme events. 

29The regional transmission planning process 

will identify the necessary transmission system 

facilities (which have varying costs and lead times 

for when they can be placed into service) that are 

needed to achieve reliable transmission system 

operations. 

alternative transmission solutions that 

might meet the region’s reliability, 

economic, and Public Policy 

Requirements needs 15 more efficiently 

or cost-effectively than solutions that 

transmission providers identified in 

their local transmission planning 

processes.16 Order No. 1000 also 

requires that the regional transmission 

planning process satisfy the Order No. 

890 transmission planning principles.17

Therefore, these transmission planning 

principles, which the Commission 

adopted with respect to local 

transmission planning processes in 

Order No. 890, also apply to the regional 

transmission planning processes 

established in Order No. 1000. 

2. Nonincumbent Transmission 

Developer Reforms 

9. Order No. 1000 institutes a number 

of reforms that seek to ensure that 

nonincumbent transmission developers 

have an opportunity to participate in the 

regional transmission development 

process.18 In particular, Order No. 1000 

requires that each transmission provider 

eliminate provisions in Commissionjurisdictional tariffs and agreements that 

establish a federal right of first refusal 

for an incumbent transmission provider 

with respect to transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation.19 Order 

No. 1000 defines a transmission facility 

selected in a regional transmission plan 

for purposes of cost allocation as one 

that has been selected because it is a 

more efficient or cost-effective solution 

to a regional transmission need.20

10. In addition, Order No. 1000 

requires that each regional transmission 

planning process include not unduly 

discriminatory qualification criteria and 

information requirements for 

transmission developers that want to 

propose a transmission facility for 

selection in the regional transmission 

plan for purposes of cost allocation.21

The regional transmission planning 

process must also have a transparent 

and not unduly discriminatory process 

for evaluating whether to select a 

proposed transmission facility in the 

regional transmission plan for purposes 

of cost allocation.22 Furthermore, the 

regional transmission planning process 

must provide a nonincumbent 

transmission developer with the same 

eligibility as an incumbent transmission 

developer to use a cost allocation 

method(s) for any sponsored 

transmission facility selected in the 

regional transmission plan for purposes 

of cost allocation.23

3. Regional Transmission Cost 

Allocation 

11. Order No. 1000 requires each 

transmission provider to have in place 

a method, or set of methods, for 

allocating the costs of new regional 

transmission facilities selected in the 

regional transmission plan for purposes 

of cost allocation.24 Each regional cost 

allocation method must satisfy six 

regional cost allocation principles,25

including the principle that the cost of 

transmission facilities must be allocated 

to those in the transmission planning 

region that benefit from the facilities in 

a manner that is roughly commensurate 

with estimated benefits.26

4. Interregional Transmission 

Coordination 

12. Order No. 1000 requires each 

transmission provider, through its 

regional transmission planning process, 

to establish further procedures with 

each of its neighboring transmission 

planning regions for the purpose of 

coordinating and sharing the results of 

respective regional transmission plans 

to identify possible interregional 

transmission facilities that could 

address transmission needs more 

efficiently or cost-effectively than 

separate regional transmission facilities. 

The interregional coordination 

processes must provide for: (1) The 

sharing of information regarding the 

respective needs of each region and 

potential solutions to those needs; and 

(2) the identification and evaluation of 

interregional transmission facilities that 

may be more efficient or cost-effective 

solutions to those regional needs.27

B. Overview of Transmission Planning 

13. The next few paragraphs provide 

an overview of how transmission 

providers plan their systems to meet 

their reliability, economic, and Public 

Policy Requirements needs, consistent 

with Order Nos. 890 and 1000. 

1. Reliability Needs 

14. Transmission providers within 

transmission planning regions conduct 

reliability planning studies to help 

ensure the ability of the transmission 

system to serve firm transmission use. 

These studies may extend 10 to 15 years 

into the future depending on the 

transmission planning region’s 

transmission planning process and tests 

for violations of established North 

American Electric Reliability 

Corporation (NERC) reliability 

requirements.28 Additional regional and 

local reliability criteria may also apply 

in specific transmission planning 

regions. In order to meet applicable 

reliability planning criteria, the regional 

transmission planning process focuses 

on studying and producing a 

transmission system that is robust 

enough to be able to withstand a range 

of probable contingencies (e.g., the 

sudden loss of a generator or high 

voltage transmission line) while reliably 

serving customer demand and 

preventing cascading outages.29

Generally, transmission providers 

identify areas not in compliance with 

planning criteria and develop plans to 

achieve compliance. Transmission 

providers examine facilities to mitigate 

identified reliability criteria violations 

for their feasibility, impact, and 

comparative costs, culminating in a 

recommended regional transmission 

plan. 

2. Economic Needs 

15. Transmission providers within 

transmission planning regions also plan 

transmission facilities to meet economic 

needs. In Order No. 1000, the 

Commission recognized that Order No. 

890 placed no affirmative obligation on 


lotter on DSK11XQN23PROD with PROPOSALS2
40270 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

30Order No. 1000, 136 FERC ¶ 61,051 at PP 147– 

148. 

31Order No. 890, 118 FERC ¶ 61,119 at P 549. 

32Order No. 1000, 136 FERC ¶ 61,051 at PP 203, 

222; Order No. 1000–A, 139 FERC ¶ 61,132 at P 208. 

33Order No. 1000, 136 FERC ¶ 61,051 at P 220 

(explaining that the Final Rule is intended to 

‘‘provide flexibility for public utility transmission 

providers to develop procedures appropriate for 

their local and regional transmission planning 

processes’’). 

34 Id. P 215. 

35Order No. 2003, 104 FERC ¶ 61,103 at P 11. 

36 Id. P 9 (citing Tenn. Power Co., 90 FERC 

¶ 61,238 (2000)). 

37 Id. P 10. 

38 Id. P 11. 

39The pro forma LGIP and pro forma LGIA 

govern large generating facilities, which are 

generating facilities that have a generating facility 

capacity of more than 20 MW. 

40For clarity, this ANOPR will refer to these 

facilities as interconnection-related network 

upgrades. 

41 Id. P 21. 

42While we provide a broad description of the 

generator interconnection process under Order No. 

2003 as background here, we recognize that many 

transmission providers have adopted (and the 

Commission has accepted) variations to many of the 

terms in the pro forma LGIP and the pro forma 

LGIA. Consequently, some or many of the details 

of a particular transmission provider’s generator 

interconnection process may vary considerably 

from the broad description provided here. 

43 Id. P 35. 

44Pro forma LGIP Section 3.1. 

transmission providers to perform 

economic planning studies absent a 

request by stakeholders. To remedy this 

deficiency, Order No. 1000 required 

that, in addition to economic planning 

studies requested by stakeholders, 

transmission providers evaluate, 

through a regional transmission 

planning process and in consultation 

with stakeholders, alternative 

transmission solutions that might meet 

the needs of the transmission planning 

region more efficiently or costeffectively than solutions identified by 

individual transmission providers in 

their local transmission planning 

process. These regional transmission 

solutions could include transmission 

facilities needed to meet reliability 

requirements, address economic 

considerations, and/or meet 

transmission needs driven by Public 

Policy Requirements.30 As Order No. 

890 explains, the purpose of economic 

transmission planning is to plan 

transmission to alleviate congestion 

through the integration of new 

generation resources or an expansion of 

the regional transmission system, by an 

amount that justifies its cost, usually by 

a defined threshold.31 However, to 

implement the requirement in Order No. 

1000 to affirmatively plan for economic 

needs, transmission providers 

implemented thresholds that vary across 

the regions. Examples of regional 

transmission facilities driven by 

economic needs include transmission 

facilities that relieve historical or 

projected transmission congestion and 

allow lower-cost power to flow to 

consumers. 

3. Public Policy Requirement Needs 

16. Order No. 1000 requires 

transmission providers to consider 

transmission needs driven by Public 

Policy Requirements in their local and 

regional transmission planning 

processes.32 However, the requirement 

in Order No. 1000 to consider 

transmission needs driven by Public 

Policy Requirements is limited, and the 

Commission provided transmission 

providers with flexibility in how to 

meet the requirement. For example, 

Order No. 1000 does not require that a 

separate class of transmission facilities 

be created in the regional transmission 

planning process to address 

transmission needs driven by Public 

Policy Requirements,33 nor does it 

mandate the consideration of any 

particular transmission need driven by 

a Public Policy Requirement.34 As a 

result, the process for identifying and 

considering such needs varies from 

transmission planning region to 

transmission planning region. 

4. Local Transmission Facilities in the 

Regional Transmission Planning Process 

17. Generally, the transmission 

facilities that transmission providers 

include in their individual local 

transmission plans are incorporated into 

regional transmission plans as inputs, 

with minimal opportunity for 

stakeholder review in the regional 

transmission planning process. That is 

because the analysis of local 

transmission plans in the regional 

transmission planning process is limited 

mainly to a reliability analysis to ensure 

that local transmission plans do not 

negatively affect the reliability of the 

regional transmission system. 

C. Overview of Generator 

Interconnection 

18. In Order No. 2003, the 

Commission recognized a need for a 

single set of interconnection procedures 

for jurisdictional transmission providers 

and a single, uniformly applicable 

interconnection agreement for large 

generators.35 The Commission 

explained that generator 

interconnection is a ‘‘critical component 

of open access transmission service and 

thus is subject to the requirement that 

utilities offer comparable service under 

the OATT.’’ 36 The Commission also 

determined that, because of the 

inefficiency of addressing generator 

interconnection issues on a case-by-case 

basis,37 it was appropriate to establish a 

standard set of generator 

interconnection procedures to 

‘‘minimize opportunities for undue 

discrimination and expedite the 

development of new generation, while 

protecting reliability and ensuring that 

rates are just and reasonable.’’ 38 To this 

end, the Commission adopted the pro 

forma Large Generator Interconnection 

Procedures (LGIP) and pro forma Large 

Generator Interconnection Agreement 

(LGIA) 39 and required that all 

transmission providers’ OATTs 

incorporate the pro forma LGIP and pro 

forma LGIA. 

19. In Order No. 2003, the 

Commission also retained a distinction 

between interconnection facilities, 

which are located between the 

interconnection customer’s generating 

facility and the transmission provider’s 

transmission system, and network 

upgrades,40 which include only 

facilities at or beyond the point where 

the interconnection customer’s 

generating facility interconnects to the 

transmission provider’s transmission 

system.41 This distinction is important 

because the determination of which 

entity is ultimately responsible for the 

cost of a facility can depend on whether 

that facility is an interconnection 

facility or an interconnection-related 

network upgrade. 

20. To initiate the generator 

interconnection process set forth in 

Order No. 2003,42 the interconnection 

customer submits an interconnection 

request associated with its proposed 

generating facility that includes 

preliminary site documentation, certain 

technical information about the 

proposed generating facility, and the 

expected in-service date along with a 

deposit.43 The transmission provider 

uses this information to determine the 

interconnection facilities and 

interconnection-related network 

upgrades necessary to accommodate the 

interconnection request and their 

associated costs.44

21. After the transmission provider 

determines that the interconnection 

request is complete, the interconnection 

request will enter the interconnection 

queue with other pending requests, and 

the transmission provider will assign 

the request a queue position based on 

the date and time of receipt. The queue 

position will determine the order in 

which the transmission provider will 

perform three phases of interconnection 

studies for the interconnection request. 

The three phases in order are: (1) The 

feasibility study; (2) the system impact 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40271 

45Order No. 2003, 104 FERC ¶ 61,103 at PP 35– 

36. The interconnection customer is responsible for 

the costs of interconnection studies and any 

necessary restudies. 

46 Id. P 38. 

47 Id. 

48For example, some transmission providers have 

details regarding what information is included in an 

interconnection study base case in their tariffs, see 

e.g. Sw. Power Pool, Inc., 172 FERC ¶ 61,283, at P10 

(2020), while others limit that information to the 

business practices manuals. See, e.g., NYISO 

Manual 26, Reliability Planning Process Manual at 

15–16. 

49Order No. 1000, 136 FERC ¶ 61,051 at PP 622, 

639. The six Order No. 1000 regional cost allocation 

principles are discussed further below. 

50 Id. P 68. 

51 Id. P 63. 

52Order No. 1000–A, 139 FERC ¶ 61,132 at P 429. 

53 Id. P 190. 

54 Id. PP 366, 379, 425, 428. 

55Order No. 1000, 136 FERC ¶ 61,051 at P 329. 

56We use the term interconnection pricing policy 

to refer collectively to both Order No. 2003’s 

establishment of the crediting policy for financing 

interconnection-related network upgrades and 

Order No. 2003’s allowance of participant funding 

for interconnection-related network upgrades in 

RTOs/ISOs. 

study; and (3) the facilities study, all of 

which are necessary to determine the 

interconnection facilities and 

interconnection-related network 

upgrades needed to accommodate the 

interconnection request and the 

interconnection customer’s cost 

responsibility for these facilities.45

22. At the completion of the facilities 

study, the transmission provider will 

issue a report, which includes a ‘‘best 

estimate of the costs to effect the 

requested interconnection,’’ and provide 

a draft generator interconnection 

agreement to the interconnection 

customer.46 If the interconnection 

customer wishes to proceed, after 

negotiations, the interconnection 

customer enters into a generator 

interconnection agreement with the 

transmission provider or requests that 

the transmission provider file the 

agreement with the Commission 

unexecuted.47

D. Interaction Between the Regional 

Transmission Planning and Cost 

Allocation and Generator 

Interconnection Processes 

23. The interaction between a 

transmission provider’s current 

generator interconnection process and 

its regional transmission planning and 

cost allocation processes appears to be 

limited. The primary interaction is that 

the baseline regional transmission 

planning models generally only 

incorporate interconnection projects 

that are near the end of the 

interconnection process and have 

completed a facilities study. In addition, 

when creating interconnection study 

models, transmission providers 

incorporate transmission planning 

information into the interconnection 

base cases, but what information is 

incorporated varies for each 

transmission provider. The base cases 

for interconnection studies impact the 

cost assignment for interconnection 

customers, often dramatically, and at 

present, most transmission providers’ 

OATTs do not contain requirements for 

what information is included in base 

cases.48

E. Current Funding Paradigm 

1. Regional Transmission Cost 

Allocation 

24. As noted above, Order No. 1000’s 

cost allocation reforms require each 

transmission provider to participate in a 

regional transmission planning process 

that features a regional cost allocation 

method or methods for allocating the 

cost of new regional transmission 

facilities selected in a regional 

transmission plan for purposes of cost 

allocation. The Commission also 

required that such regional cost 

allocation methods satisfy six regional 

cost allocation principles, including the 

principle that the cost of transmission 

facilities must be allocated to those in 

the transmission planning region that 

benefit from the facilities in a manner 

that is roughly commensurate with 

estimated benefits.49

2. Local Transmission Facilities 

25. In Order No. 1000, the 

Commission explained that the local 

transmission planning process is the 

transmission planning process that a 

transmission provider performs for its 

individual retail distribution service 

territory or footprint pursuant to the 

requirements of Order No. 890.50 The 

outcome of the local transmission 

planning processes are local 

transmission facilities. In Order No. 

1000, the Commission defined a local 

transmission facility as a transmission 

facility located solely within a 

transmission provider’s retail 

distribution service territory or footprint 

that is not selected in the regional 

transmission plan for purposes of cost 

allocation.51

26. The Commission clarified that, if 

the transmission provider has a retail 

distribution service territory and/or 

footprint, then only a transmission 

facility that it decides to build within 

that retail distribution service territory 

or footprint, and that is not selected in 

a regional transmission plan for 

purposes of cost allocation, may be 

considered a local transmission facility. 

Further, the Commission explained that, 

in the case of an RTO/ISO whose 

footprint covers the entire region, local 

transmission facilities are defined by 

reference to the retail distribution 

service territories or footprints of its 

underlying transmission owing 

members.52 The Commission did not 

require that the transmission facilities in 

a transmission provider’s local 

transmission plan be subject to approval 

at the regional or interregional level, 

unless that transmission provider seeks 

to have any of those facilities selected 

in the regional transmission plan for 

purposes of cost allocation.53

27. Moreover, local transmission 

facilities planned through a local 

transmission planning process are not 

eligible to use the Order No. 1000 

regional cost allocation method and 

instead their costs are allocated to the 

transmission provider in whose retail 

distribution service territory or footprint 

the local transmission facility is located. 

In support of this, the Commission 

explained that it continues to permit an 

incumbent transmission provider to 

meet its reliability needs or service 

obligations by choosing to build new 

transmission facilities that are located 

solely within its retail distribution 

service territory or footprint as long as 

the transmission provider does not 

receive regional cost allocation for the 

facilities.54 Further, the Commission 

clarified that nothing in Order No. 1000 

restricts an incumbent transmission 

provider from developing a local 

transmission solution that is not eligible 

for regional cost allocation to meet its 

reliability needs or service obligations 

in its own retail distribution service 

territory or footprint.55

3. Interconnection-Related Network 

Upgrades 

28. The Commission’s 

interconnection pricing policy 56 allows 

for two general approaches on how to 

assign the cost of interconnectionrelated network upgrades, one of which 

we refer to as the crediting policy and 

the other as participant funding. We 

will discuss the rationale that the 

Commission provided when accepting 

each of the two approaches in later 

sections. 

29. In Order No. 2003, the 

Commission established the crediting 

policy as a requirement of the 

Commission’s interconnection pricing 

policy. Pursuant to the crediting policy, 

the interconnection customer is solely 

responsible for the costs of 

interconnection facilities, and 

interconnection-related network 

upgrades are funded initially by the 


lotter on DSK11XQN23PROD with PROPOSALS2
40272 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

57Order No. 2003, 104 FERC ¶ 61,103 at P 22. 

58 Id. P 694. ‘‘But for’’ interconnection-related 

network upgrades are those interconnection-related 

network upgrades that would not have been 

constructed ‘‘but for’’ the interconnection request. 

See N.Y. Indep. Sys. Operator, Inc., 122 FERC 

¶ 61,267, at n.3 (2008). 

59The embedded cost pricing ‘‘attempts to 

allocate costs among customers based upon usage.’’ 

Fla. Power & Light Co., 70 FERC ¶ 61,158 (1995). 

Embedded cost rates reflect ‘‘system average costs 

including the cost of the [interconnection-related] 

network upgrades, and incremental cost rates 

‘‘reflect [ ] just the cost of the [interconnectionrelated] network upgrades.’’ See Interstate Power & 

Light Co. v. ITC Midwest, LLC, 144 FERC ¶ 61,052, 

at P 36 (2013) (emphasis added). 

60Order No. 845–B, 166 FERC ¶ 61,092 at P 5; 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’’). 

61We 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. 

interconnection customer (unless the 

transmission provider elects to fund 

them) and the transmission provider 

reimburses the interconnection 

customer through transmission service 

credits.57 The Commission reasoned 

that ‘‘it is appropriate for the 

Interconnection Customer to pay 

initially the full cost of Interconnection 

Facilities and [interconnection-related] 

Network Upgrades that would not be 

needed but for the interconnection.’’ 58

While the interconnection customer 

pays for the costs of the 

interconnection-related network 

upgrades upfront, the transmission 

provider must reimburse the total 

amount that the interconnection 

customer paid for interconnectionrelated network upgrades, plus interest, 

as credits against the charges for 

transmission service taken with respect 

to the interconnection customer’s 

generating facility as such charges are 

incurred. The transmission provider 

recovers the cost of interconnectionrelated network upgrades funded under 

the crediting policy through its 

embedded cost transmission rates.59

The second pricing approach for 

interconnection-related network 

upgrades is called participant funding. 

Participant funding for interconnectionrelated network upgrades refers to the 

direct assignment to a particular 

interconnection customer of the costs of 

interconnection-related network 

upgrades that would not be needed but 

for the interconnection.60 The 

Commission has accepted as just and 

reasonable various participant funding 

approaches proposed by RTOs/ISOs as 

independent entity variations from the 

pro forma requirements of Order No. 

2003. 

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 costeffectively 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 costeffective 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.61

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 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40273 

62Order No. 1000, 136 FERC ¶ 61,051 at P 10. 

63See, 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.’’). 

64Order No. 2003, 104 FERC ¶ 61,103 at P 11. 

65 Id. P 12. 

66 Id. P 695. 

generator interconnection and regional 

transmission planning and cost 

allocation processes. Without cooptimization 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 costeffective 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.62 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. 

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 interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated 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.63 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. 

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.’’ 64 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.’’ 65 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.’’ 66 Also, 

while the crediting policy ‘‘recognizes 

the reliability benefits of a stronger 


lotter on DSK11XQN23PROD with PROPOSALS2
40274 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

67Order No. 2003–A, 106 FERC ¶ 61,220 at P 584. 

transmission infrastructure and more 

competitive power markets that result 

from a policy that facilitates the 

interconnection of new generating 

facilities,’’ 67 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. 

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 longterm scenarios would lead to the 

identification of more efficient or costeffective 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 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40275 

68 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). 

69Stochastic models are frameworks for 

addressing optimization problems that involve 

uncertainty. 

70http://www.ercot.com/committee/crez. 

71https://www.misoenergy.org/planning/ 

planning/multi-value-projects-mvps/. 

scenarios; (4) whether and how 

transmission providers should account 

for an array of different future scenarios 

when identifying more efficient or costeffective 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 68 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. 

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 69 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 cooptimization 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. 

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 ridethrough 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 costeffective 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 70 and 

MISO’s Multi-Value Projects (MVP).71

56. California Independent System 

Operator Corporation (CAISO) offers 

another example of a regional 

transmission planning process 

identifying transmission facilities to 

accommodate renewable resources in 


lotter on DSK11XQN23PROD with PROPOSALS2
40276 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

72Cal. Indep. Sys. Operator Corp., 119 FERC 

¶ 61,061 (2007). 73 Id. P 6. 

74See Texas Commission, Order on Rehearing, 

Docket No. 33672, at 3 (Oct. 7, 2008). 

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.72

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; 73 and (4) 

whether specific proposals are 

consistent with the Commission’s FPA 

section 206 authority. 

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.74 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. 

iii. Incentivizing Regional Transmission 

Facilities 

61. To prioritize regional transmission 

facilities that may have greater benefitto-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 costeffective solution to an identified 

transmission need. 

iv. Enhanced Interregional or State-toState Coordination 

62. We recognize that potential 

reforms discussed for comment above 

may require greater interregional or 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40277 

75See 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 v. FERC, 

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

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 cooptimized? 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 interconnectionrelated 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.75

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 


lotter on DSK11XQN23PROD with PROPOSALS2
40278 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

76Cf. BNP Paribas Energy Trading GP v. 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 v. FERC, 373 

F.3d 1361, 1368 (D.C. Cir. 2004) and Se. Mich. Gas 

Co. v. 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. v. 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. v. 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). 

77 16 U.S.C. 824d, 824e. 

78KN Energy, Inc. v. FERC, 968 F.2d at 1300. 

79S.C. Pub. Serv. Auth., 762 F.3d at 87 (quoting 

NARUC v. FERC, 475 F.3d at 1285). 

80 ICC v. FERC, 576 F.3d at 476. 81 Midwest ISO Transmission Owners v. FERC, 

373 F.3d at 1368. 82 576 F.3d at 477. 83 Id. (citing Midwest ISO Transmission Owners v. 

FERC, 373 F.3d at 1369). 

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.76

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.77 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’’ 78 and that costs ‘‘be 

allocated to those who cause the costs 

to be incurred and reap the resulting 

benefits.’’ 79 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.’’ 80 Courts ‘‘evaluate 

compliance with this . . . principle by 

comparing the costs assessed against a 

party to the burdens imposed or benefits 

drawn by that party.’’ 81 In ICC v. 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.82 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.’’ 83

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 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40279 

84Order No. 1000, 136 FERC ¶ 61,051 at P 499. 

85 Id. PP 9, 482–83. 

86 Id. P 10; Order No. 1000–A, 139 FERC ¶ 61,132 

at P 647. 

87Order No. 1000, 136 FERC ¶ 61,051 at P 637. 

88 Id. P 646. 

89 Id. P 657. 

90 Id. P 668. 

91 Id. P 685. 

92 Id. P 501. 

93Order 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). 

94MISO, FERC Electric Tariff, Attachment FF, 

Section II.C (85.0.0). 

95 Id. Section III.A.2.g. 

96SPP’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. 

97SPP OATT, attach. J (Recovery of Costs 

Associated With New Facilities), Section III.D. 

98Order No. 1000, 136 FERC ¶ 61,051 at P 760. 

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.84 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.85 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.86

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; 87 (3) a benefit to cost 

threshold ratio, if adopted, cannot 

exceed 1.25 to 1; 88 (4) costs must be 

allocated solely within the transmission 

planning region unless another entity 

outside the region voluntarily assumes a 

portion of those costs; 89 (5) the method 

for determining benefits and identifying 

beneficiaries must be transparent; 90 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.91 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.’’ 92 Consistent with this 

notion, the Commission declined to 

require transmission providers to adopt 

a universal or comprehensive definition 

of ‘‘benefits’’ and ‘‘beneficiaries’’ 93 of 

regional transmission facilities, instead 

allowing for regional flexibility and 

examining each region’s definitions on 

compliance. 

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.94 The costs of 

this MVP portfolio are allocated on a 

postage stamp basis across the MISO 

region.95

80. Southwest Power Pool’s (SPP) 

Balanced Portfolio process similarly 

considers broader transmission 

benefits.96 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.97

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.98 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 


lotter on DSK11XQN23PROD with PROPOSALS2
40280 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

99 Id. P 760. 

100Cal. Indep. Sys. Operator Corp., 119 FERC 

¶ 61,061. 

101Cal. Indep. Sys. Operator Corp., 119 FERC 

¶ 61,061, at P 6. 

102Order No. 1000, 136 FERC ¶ 61,051 at P 501. 

103Order No. 890, 118 FERC ¶ 61,119 at P 557. 

104See, 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); 

105Order 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. 

the regional transmission planning 

process.99

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 highvoltage transmission plant of all 

transmission providers, as reflected in 

their transmission revenue requirements 

and in the CAISO transmission access 

charge.101

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

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

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. 

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 interconnectionrelated 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 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40281 

106See 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’’). 

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 subzones 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. 

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 nonparticipating 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., 


lotter on DSK11XQN23PROD with PROPOSALS2
40282 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

107Order 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. 

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-toregion? 

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 InterconnectionRelated 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 interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated 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 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40283 

108Order No. 2003, 104 FERC ¶ 61,103 at n.111. 

109Order No. 2003–A, 106 FERC ¶ 61,220 at P 

613. 

110Order No. 2003, 104 FERC ¶ 61,103 at P 694. 

111 Id. PP 612, 694. 

112 Id. P 694. 

113Order 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. 

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. v. FERC, 165 F.3d 

922, 927 (DC Cir. 1999)). 

119Order No. 2003, 104 FERC ¶ 61,103 at P 695. 120 Id. P 28. 121Order No. 2003–A, 106 FERC ¶ 61,220 at P 

696. 122Order No. 2003, 104 FERC ¶ 61,103 at P 695. 

123 Id. n.111. 

124Order No. 2003–A, 106 FERC ¶ 61,220 at P 

691. 

[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

(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 interconnectionrelated 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 interconnectionrelated 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

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

104. In NARUC v. 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 ‘‘[interconnectionrelated] 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

(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 [interconnectionrelated] 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. 

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 offsystem.’’ 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

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 


lotter on DSK11XQN23PROD with PROPOSALS2
40284 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

125Order No. 2003, 104 FERC ¶ 61,103 at P 703. 

126 Id. P 700. 

127 Id. 

128 Id. 

129PJM 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). 

130Old Dominion Elec. Coop. v. PJM 

Interconnection, L.L.C., 119 FERC ¶ 61,052, at P 18 

(2007) (ODEC v. PJM). 

131ODEC v. PJM, 119 FERC ¶ 61,052 at P 18; see 

also id. P 16 (‘‘Not every system upgrade required 

simply to interconnect a generating facility safely to 

the grid entitles the generator to capacity rights; 

however, a generation interconnection customer 

would be ‘allowed to receive’ capacity rights if a 

[interconnection-related] network upgrade creates 

additional transmission capability.’’). 

132See, e.g., Midcontinent Indep. Sys. Operator, 

Inc., 164 FERC ¶ 61,158, at P 5 (2018) (‘‘MISO’s 

Interconnection Customer Funding Policy . . . 

requiring the interconnection customer to 

‘participant fund’ 90–100 percent of its 

[interconnection-related] network upgrades . . . 

was accepted, under the Order No. 2003 

independent entity variation standard in 2009.’’); 

Midwest Indep. Transmission Sys. Operator, Inc., 

129 FERC ¶ 61,060, at P 8 (2009) (accepting MISO’s 

‘‘proposed change [that] would result in the 

interconnection customer bearing 100 percent of the 

costs of [interconnection-related] network upgrades 

rated below 345 kV and bearing 90 percent of the 

costs of [interconnection-related] network upgrades 

rated at 345 kV and above (with the remaining 10 

percent being recovered on a system-wide basis’’)); 

Midwest Indep. Trans. Sys. Operator, Inc., 114 

FERC ¶ 61,106, at P 62 (2006). 

133Cal. Indep. Sys. Operator Corp., 140 FERC 

¶ 61,070, at PP 24–27 (2012). 

134PJM Interconnection, L.L.C., 108 FERC 

¶ 61,025 (2004); Sw. Power Pool, Inc., 127 FERC 

¶ 61,283 (2009); Sw. Power Pool, Inc., 171 FERC 

¶ 61,272 (2020); N.Y. Indep. Sys. Operator, Inc., 108 

FERC ¶ 61,159 (2004), order on reh’g, 111 FERC 

¶ 61,347 (2005); ISO New Eng. Inc., 133 FERC 

¶ 61,229 (2010). 

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

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 welldefined, 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

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 interconnectionrelated network upgrades have equal 

value to the cost of the interconnectionrelated 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 v. 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

110. Again, each RTO/ISO sought an 

independent entity variation to adopt a 

participant funding approach rather 

than adopt the crediting policy. In 

MISO, an interconnection customer is 

responsible for 100% of 

interconnection-related network 

upgrade costs, with a possible 10% 

reimbursement or ‘‘crediting’’ for 

interconnection-related network 

upgrades that are 345 kV and above.132

In CAISO, the interconnection 

customer’s cost responsibility for a 

particular interconnection-related 

network upgrade depends on how 

CAISO classified the interconnectionrelated network upgrade (i.e., whether 

the interconnection-related network 

upgrade is considered area, local, or 

reliability) and the interconnectionrelated network upgrade’s deliverability 

status (e.g., full capacity, partial 

capacity, or energy-only).133 In CAISO, 

full cash reimbursement is only 

available for the costs of certain 

categories of interconnection-related 

network upgrades, up to $60,000 per 

MW of installed generation capacity, 

and interconnecting generators receive 

congestion revenue rights in exchange 

for funding any upgrades that are not 

eligible for cash reimbursement. SPP, 

NYISO, PJM, and ISO-New England, 

Inc. use a participant funding approach 

where the transmission provider assigns 

100% of the interconnection-related 

network upgrade costs to the 

interconnection customer and the 

interconnection customer may receive 

compensation through transmission 

capacity rights.134

b. Potential Need for Reform 

i. Participant Funding 

111. Since the issuance of Order No. 

2003, changing circumstances have cast 

doubt on whether it continues to be just 

and reasonable to provide RTOs/ISOs 

with the flexibility to adopt participant 

funding approaches for interconnectionrelated network upgrades. We seek 

comment on whether these 

developments suggest that the 

allowance of participant funding for 

interconnection-related network 

upgrades, both as a concept and in its 

application, may no longer be just and 

reasonable. Moreover, it appears that the 

incentives created by participant 

funding in this context may produce 

outcomes that are counter to the 

Commission’s intentions in allowing 

flexibility for RTOs/ISOs to adopt 

participant funding in Order No. 2003. 

112. To begin with, participant 

funding may allocate the costs of 

extensive interconnection-related 

network upgrades entirely to 

interconnection customers without 

accounting for the significant benefits 

that these interconnection-related 

network upgrades may provide to 

transmission customers. As a result, 

there are circumstances where this 

allocation of interconnection-related 

network upgrade costs may not be 

roughly commensurate with the 

distribution of benefits. For instance, a 

large interconnection-related network 

upgrade built on a consistently 

congested portion of the transmission 

system may provide significant 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40285 

135See, e.g., Order No. 1000–A, 139 FERC 

¶ 61,132 at P 562 (‘‘Given the nature of transmission 

operations, it is possible that an entity that uses part 

of the transmission grid will obtain benefits from 

transmission facility enlargements and 

improvements in another part of that grid regardless 

of whether they have a contract for service on that 

part of the grid and regardless of whether they pay 

for those benefits. This is the essence of the ‘free 

rider’ problem the Commission is seeking to 

address through its cost allocation reforms.’’). 

136See Review of Generator Interconnection 

Agreements and Procedures, Technical Conference 

Transcript, Docket No. RM16–12–000 at Tr: 193: 

20–24 (Steve Naumann, Exelon) (filed Aug. 23, 

2016) (‘‘[Y]ou need to also deal with the 

[interconnection] customer who says, ‘Okay, I will 

be perfectly willing to take the risk, but I don’t want 

to pay for a single upgrade more than I have to [to] 

have a the reliability interconnection.’’). 

137Order No. 2003, 104 FERC ¶ 61,103 at P 695. 138 Id. P 702. 

economic and reliability benefits to 

transmission customers. Also, 

transmission customers, in some 

instances, can make use of any excess 

transmission capacity created by a 

participant funded interconnectionrelated network upgrade without paying 

any of the capital costs that are paid for 

through a participant funding approach. 

Allowing transmission customers to 

receive the benefits of interconnectionrelated network upgrades without 

paying for a proportionate share of their 

costs is an example of the ‘‘free rider’’ 

problem that the Commission’s 

‘‘beneficiary pays’’ cost causation 

principle is supposed to avoid.135

113. Furthermore, while the 

interconnection customer may receive 

well-defined capacity rights associated 

with the increased transfer capability 

caused by the interconnection-related 

network upgrade, these well-defined 

capacity rights do not compensate the 

interconnection customer for the broad 

range of benefits that the 

interconnection-related network 

upgrades can provide to the 

transmission system and therefore do 

not solve the ‘‘free rider’’ problem. This 

is because the well-defined capacity 

rights do not capture reductions in 

congestion costs paid by transmission 

customers that were the result of the 

expansion of the transfer capability 

created by the interconnection-related 

network upgrade; nor do they capture 

transmission service charges for use of 

the excess capacity created by the 

interconnection-related network 

upgrade. Instead, well-defined capacity 

rights capture congestion costs paid by 

transmission customers on a going 

forward basis across the relevant 

transmission path on which the 

interconnection-related network 

upgrade increased transmission 

capacity. To the extent that the 

interconnection-related network 

upgrade may have eliminated most of 

the ex ante congestion on the relevant 

paths, the transmission customers that 

transact across such paths and have 

their congestion costs reduced as a 

result of the large interconnectionrelated network upgrade now in service 

will receive this benefit for free in most 

cases. 

114. We seek comment on whether 

costs allocated to interconnection 

customers pursuant to participant 

funding approaches have increased over 

time, and if so, why. We seek comment 

on whether this increase in costs is 

evidence that regional transmission 

planning processes are not building 

adequate transmission system capacity. 

We seek comment on whether the 

Commission’s policies on participant 

funding have impacted the 

interconnection queue, e.g., through 

late-state withdrawals, and if so, how 

and to what degree. In the case that 

there are late-stage withdrawals from 

the interconnection queue, we seek 

comment on the ability of transmission 

providers to efficiently process 

interconnection requests from other 

interconnection customers affected by 

the withdrawal. Finally, we seek 

comment on whether uncertainty 

regarding interconnection costs drives 

up the cost of developing supply 

resources and thereby ultimately 

increases the cost of electricity supply 

for customers. 

115. Participant funding also may 

create a separate incentive for the 

interconnection customer that may 

undermine the development of 

interconnection-related network 

upgrades that produce greater benefits. 

Specifically, the interconnection 

customer, knowing that it will be 

responsible for all interconnectionrelated network upgrade costs, is likely 

to strongly oppose any addition or 

modification to the transmission system 

beyond what is necessary to support its 

own interconnection, even if such 

additions and modifications may 

ultimately benefit it and others by 

providing improved reliability or 

economic outcomes.136

116. An additional rationale that the 

Commission provided in Order No. 

2003 for allowing participant funding 

was the concern that the 

interconnection crediting policy would 

‘‘mute somewhat the Interconnection 

Customer’s incentive to make an 

efficient siting decision that takes 

transmission costs into account.’’ 137

The Commission in Order No. 2003 also 

found that participant funding in RTOs/ 

ISOs is consistent with the policy of 

promoting competitive wholesale 

markets because it causes the 

interconnection customer to face the 

same marginal cost price signal that it 

would face in a competitive market.138

We seek comment on whether to 

reconsider these findings in light of 

current circumstances. 

117. We note, for instance, that the 

Commission’s view of efficient siting of 

generation in Order No. 2003 was from 

a transmission costs perspective, i.e., 

which points of interconnection would 

require the least expensive 

interconnection-related network 

upgrades. We seek comment on whether 

this perspective may be at odds with the 

primary siting considerations for 

renewable generation developers 

decades later. That is, interconnection at 

locations where renewable generation 

may experience higher efficiency factors 

(e.g., because they have abundant wind 

or sun) may still be uneconomic where 

participant funding applies because the 

costs of interconnection-related network 

upgrades for that location may be 

significant and would not be allocated 

beyond the interconnection customer. 

We seek comment on whether 

interconnection at such locations may 

be considered economic, however, if the 

cost of the interconnection-related 

network upgrades were allocated more 

broadly among those that benefit. Thus, 

because the price signal participant 

funding sends does not account for the 

broader economic efficiencies from 

siting renewable generation in fuel-rich 

areas, it can instead encourage the 

development of renewable generation in 

less productive locations. Because 

increased renewable resource 

penetration in RTOs/ISOs is likely to 

continue, it may make less sense to 

retain a policy that encourages 

renewable developers to develop lower 

quality, less dependable renewable 

resources. 

118. Further, given the uncertainty 

created by the RTO/ISO queue backlogs 

and cascading interconnection-related 

network upgrade cost allocations that 

move from withdrawing higher-queued 

interconnection customers to lowerqueued interconnection customers, 

participant funding may no longer 

provide efficient price signals that allow 

generators to act freely to achieve the 

desirable level of entry of new costeffective generating capacity. We 

understand that a contributing factor to 

the interconnection queue backlog is a 

tendency by interconnection customers 

to submit multiple interconnection 

requests at different points of 

interconnection, with the intention of 

discovering the lowest cost site for a 


lotter on DSK11XQN23PROD with PROPOSALS2
40286 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

139As noted below, however, we are exploring 

reforms to the existing crediting policy approach 

(that could be adopted alone or in combination with 

the elimination of participant funding) that could 

reduce the level of upfront funding to be provided 

by the interconnection customers. 

140See, e.g., Review of Generator Interconnection 

Agreements and Procedures, Technical Conference 

Transcript, Docket No. RM16–12–000, at Tr. 25: 8– 

15 (May 13, 2016) (Dean Gosselin, NextEra) (filed 

Aug. 23, 2016) (‘‘I’d like to just talk about what is 

optimal . . . as a developer . . . trying to advance 

[a project] to fruition . . . . I would say for the 

interconnection queue that the initial results closely 

match final results in a defined and reasonable 

timeline, that would be my definition.’’); id. at 

134:5–7 (Omar Martino, EDF Renewable Energy) 

(‘‘[C]osts can change dramatically between [the] 

system impact and [the] facility study.’’). 

project (from an interconnection 

perspective), and then withdrawing 

higher-cost projects from the queue later 

in the process. This tendency can 

require numerous restudies and 

reallocation of interconnection-related 

network upgrade costs, compounding 

the uncertainty surrounding the amount 

of interconnection-related network 

upgrade costs that will be attributable to 

viable projects as the queue progresses. 

119. We seek comment on whether it 

is appropriate to eliminate or reduce 

participant funding for interconnectionrelated network upgrades in RTOs/ISOs 

and whether any specific proposed 

changes to interconnection funding 

mechanisms allocate costs in a manner 

roughly commensurate with benefits 

and are otherwise consistent with the 

Commission’s authority under the FPA 

and do not unjustly or unreasonably 

shift costs to customers of load serving 

entities. 

ii. Crediting Policy 

120. We seek comments on whether 

we should revisit the crediting policy in 

all regions by requiring that 

transmission providers, instead of 

interconnection customers, fund upfront 

all or a portion of the interconnectionrelated network upgrade costs. We 

describe multiple variations of this 

proposal below. Some generation 

developers may find it difficult to 

provide upfront funding for the costs of 

network upgrades when the 

reimbursement period can be as long as 

20 years. Accordingly, we seek 

comment on whether the current 

approach may unjustly and 

unreasonably allocate significant 

financing costs for interconnectionrelated network upgrades to 

interconnection customers when the 

benefits of the interconnection-related 

network upgrades accrue to the broader 

system. We seek comment on whether, 

if interconnection-related network 

upgrade costs are increasing on average, 

it is possible that these upfront funding 

costs may pose an unjust and 

unreasonable barrier to entry for 

generation developers. Given these 

considerations, below we seek comment 

on some potential reforms to the 

crediting policy. 

c. Potential Reforms and Request for 

Comment 

121. We seek comment on whether 

the Commission should eliminate the 

independent entity variations that allow 

RTOs/ISOs to use participant funding 

for interconnection-related network 

upgrades. We also seek comment on 

potential approaches for modifying or 

replacing the existing crediting policy 

for the costs of interconnection-related 

network upgrades in all regions. We 

seek comment on these options and 

invite alternative suggestions by 

commenters that take into consideration 

the concerns discussed above. 

122. Additionally, for each of the 

reforms contemplated below, we seek 

comment on whether there are 

articulable and plausible reasons to 

believe that these reforms would 

allocate the costs of interconnectionrelated network upgrades in a manner 

that is at least roughly commensurate 

with the benefits of those 

interconnection-related network 

upgrades and that do not unjustly and 

unreasonably shift costs to customers of 

load serving entities or are otherwise 

inconsistent with the Commission’s 

statutory authority. 

i. Eliminate Participant Funding for 

Interconnection-Related Network 

Upgrades 

123. We seek comment on whether 

participant funding of interconnectionrelated network upgrades may be unjust 

and unreasonable. We seek comment on 

whether RTOs/ISOs with previously 

approved independent entity variations 

that directly assign some or all the cost 

responsibility for interconnectionrelated network upgrades to 

interconnection customers should be 

required to revise their tariffs to remove 

the participant funding of 

interconnection-related network 

upgrade requirements and instead 

implement the crediting policy as 

prescribed in the pro forma LGIA. 

124. The potential proposal to 

eliminate participant funding of 

interconnection-related network 

upgrades in RTOs/ISOs would 

recognize, however, that simply because 

an interconnection request makes an 

interconnection-related network 

upgrade necessary for interconnection 

(and in that sense, ‘‘causes’’ the need for 

interconnection-related network 

upgrades that would not be needed ‘‘but 

for’’ an interconnection request), an 

interconnection-related network 

upgrade may sufficiently benefit 

transmission customers that it is 

appropriate to allocate the 

interconnection-related network 

upgrade costs more broadly. Also, this 

potential proposal could address the 

free rider problem that is created by 

participant funding of interconnectionrelated network upgrades. We note, 

however, that the specific proposal is to 

eliminate participant funding and 

replace it with the crediting policy, a 

pricing approach that still requires 

interconnection customers to initially 

fund interconnection-related network 

upgrades.139 Moreover, no potential 

reform presented here would modify the 

existing requirement that an 

interconnection customer bear cost 

responsibility for the interconnection 

facilities that would not be needed but 

for its interconnection request. 

125. We seek comment on whether 

the removal of participant funding of 

interconnection-related network 

upgrades may also have the potential to 

increase integration of generation by 

removing the possibly prohibitive cost 

assignment that participant funding can 

place on some interconnection 

customers. Furthermore, it may reduce 

cost uncertainty to those resources in 

the interconnection queue, and by 

extension, increase the likelihood that 

an interconnection request will result in 

a developed generating facility.140

126. Additionally, we seek comment 

on whether eliminating participant 

funding may reduce the queue backlogs 

that plague many regions because 

interconnection customers would have 

less incentive to submit multiple 

interconnection requests in an attempt 

to lower their interconnection costs, and 

may no longer drop out of 

interconnection queues at late stages 

due to unforeseen interconnectionrelated network upgrade cost increases. 

To these points, we seek comment on 

the number of interconnection requests 

that have withdrawn from the queue 

because the direct assignment of 

significant interconnection-related 

network upgrade costs made otherwise 

viable interconnection requests 

uneconomic. 

127. We seek comment on whether 

the independent entity variation granted 

to RTOs/ISOs in Order No. 2003 is no 

longer just and reasonable. In general, 

we seek comment on whether the 

incentives created by participant 

funding of interconnection-related 

network upgrades in RTOs/ISOs may 

produce outcomes that are counter to 

the Commission’s transmission 

planning and cost allocation efforts. 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40287 

141See, e.g., Interstate Power & Light Co. v. ITC 

Midwest, LLC, 144 FERC ¶ 61,052, at P 40 (2013), 

order on reh’g, clarification and compliance, 146 

FERC ¶ 61,113 (2014). See also Sw. Power Pool, 

Inc., 127 FERC ¶ 61,283, at P 5 (2009). 

128. We are aware that there could be 

complications associated with 

implementing the crediting policy in 

RTOs/ISOs with zonal transmission 

rates that do not occur outside RTOs/ 

ISOs. Outside RTOs/ISOs, a single 

transmission provider owns and 

operates its transmission system and 

generally charges a single rate for the 

entire system, regardless of the specific 

transmission customer’s location. In 

contrast, an RTO/ISO operates the 

combined transmission assets of 

multiple transmission owners within its 

footprint at non-pancaked transmission 

rates, and generally has separate 

transmission pricing zones. The 

transmission rates for each zone are 

generally designed to recover the costs 

of transmission facilities located within 

each zone. As a result, we seek 

comment on whether simply applying 

the crediting policy currently used 

outside RTOs/ISOs in RTOs/ISOs may 

disproportionately increase the burden 

to the native load of transmission zones 

where large amounts of interconnectionrelated network upgrades are 

constructed to facilitate the 

interconnection of location-constrained 

resources, which ultimately may benefit 

the entire RTO/ISO footprint. 

129. Under a crediting policy in an 

RTO/ISO, there may be a need for an 

appropriate mechanism to reimburse the 

interconnection customers, including a 

mechanism for determining which 

transmission owner(s) or zonal 

transmission rates will include the 

interconnection-related network 

upgrade costs. For example, there is a 

question of whether it would be just and 

reasonable to allocate the costs only 

within the transmission zone where the 

interconnection-related network 

upgrade is located or more broadly to 

multiple transmission zones.141 We 

therefore seek comment on how to 

implement the crediting policy in 

RTOs/ISOs and what principles should 

be used to guide the application of the 

crediting policy in RTOs/ISOs. 

130. Finally, given the concerns about 

the free-rider problem and whether the 

‘‘well-defined capacity rights’’ received 

by interconnection customers capture 

the benefits the interconnection-related 

network upgrades provide to the system, 

we seek comment on: (1) The value of 

the ‘‘well-defined capacity rights’’ that 

interconnection customers have 

received for funding interconnectionrelated network upgrades; and (2) the 

value of the benefits that 

interconnection-related network 

upgrades have provided to the system, 

such as the value of congestion relieved 

by interconnection-related network 

upgrades. We are also interested in any 

other concerns related to the ‘‘welldefined capacity rights’’ that 

interconnection customers receive and 

the ability of these ‘‘well-defined 

capacity rights’’ to reflect the value of 

the full incremental capacity and 

congestion benefits added to the 

transmission system by the 

interconnection-related network 

upgrades. 

ii. Revisions to the Existing Crediting 

Policy 

131. We seek comment on possible 

revisions to the Order No. 2003 

interconnection crediting policy, which 

requires that interconnection customers 

provide upfront funding for 

interconnection-related network 

upgrades and receive reimbursement 

through transmission service credits or 

a balloon payment after 20 years. We 

enumerate multiple proposals below. 

Not all of these proposals are mutually 

exclusive, and some could be 

implemented in tandem. 

(a) Transmission Providers Provide 

Upfront Funding for All 

Interconnection-Related Network 

Upgrades 

132. Pursuant to this potential 

proposal, each transmission provider 

would provide upfront funding for all 

the interconnection-related network 

upgrades on its transmission system. 

Then, once such an interconnectionrelated network upgrade is in service, 

the transmission provider would be able 

to include the cost of that 

interconnection-related network 

upgrade in its transmission service rate 

base and recover a return on, and of, the 

network upgrade capital costs through 

the cost-of-service transmission rates in 

its OATT. Thus, interconnection 

customers that take transmission service 

on a transmission system would still 

pay for a portion of interconnectionrelated network upgrades through 

transmission rates. We seek comment on 

(1) this approach and (2) how this 

approach could be implemented in a 

just and reasonable manner. 

133. This option would reduce the 

initial financing burden that 

interconnection customers currently 

may encounter when significant 

interconnection-related network 

upgrades are required for their 

interconnection request. Furthermore, 

this option may increase generator 

competition by lowering barriers to 

entry, which in turn will benefit 

customers by creating a more 

competitive market for energy. 

134. There may also be additional 

efficiency benefits to removing the 

crediting policy because the financing of 

interconnection-related network 

upgrades would follow the same 

financing process that the transmission 

owners apply to the other transmission 

infrastructure that they fund and build 

on their system. That is, there could be 

an efficiency gain from using one 

financing process for all transmission 

system facilities instead of the existing 

two: one for interconnection-related 

network upgrades and another for other 

transmission system facilities. In 

addition to that particular inefficiency, 

under the current crediting approach 

applied in non-RTO/ISO regions, each 

interconnection-related network 

upgrade is financed twice—initially by 

the interconnection customer and then 

again by the transmission provider 

when the interconnection customer 

receives credits as it takes transmission 

service or receives a balloon payment 

after 20 years. Without the initial 

funding by the interconnection 

customer, interconnection-related 

network upgrades would only need to 

be financed once. 

(b) Interconnection Customers 

Contribute to the Upfront Funding of 

Interconnection-Related Network 

Upgrades Through a Fee 

135. Another possible reform to the 

current crediting policy is to consider 

the establishment of a non-refundable 

fee to be charged for submitting an 

interconnection request and that is not 

reimbursable through transmission 

service credits. Under this approach, an 

appropriate fee should not be so large 

that it creates barriers to entry for 

smaller developers. Potential benefits of 

this type of fee could include: (1) 

Defraying some of the cost to 

transmission customers for 

interconnection-related network 

upgrades and therefore decreasing the 

overall impact on transmission 

customers of the related potential 

reform to eliminate participant funding 

of interconnection-related network 

upgrades in RTOs/ISOs; (2) 

discouraging the submission of 

speculative interconnection requests; 

and (3) for some variable fees, providing 

a price signal to interconnection 

customers that could incent efficient 

siting decisions where possible. We seek 

comment on (1) whether to impose a 

non-refundable, non-reimbursable fee 

on each submitted interconnection 

request and (2) how this approach could 

be implemented in a just and reasonable 

manner. 


lotter on DSK11XQN23PROD with PROPOSALS2
40288 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

142These non-refundable fees would be in 

addition to, and distinct from, the initial deposit 

submitted with an interconnection request and 

study deposits that are applied toward an 

interconnection customer’s interconnection study 

costs. 

143See, e.g., Old Dominion Elec. Coop. v. FERC, 

898 F.3d 1254, 1260 (D.C. Cir. 2018) (adopting 

Commission finding that ‘‘high-voltage power lines 

produce significant regional benefits’’). 

144MISO Tariff, Attach. FF (Transmission 

Expansion Planning Protocol), Section III.A2.d 

(81.0.0). 

145See Midcontinent Indep. Sys. Operator, Inc., 

172 FERC ¶ 61,095 (2020) (accepting MISO’s 

proposal to change the qualifying voltage threshold 

for a certain class of project from 345 kV to 230 kV). 

136. We seek comment on two 

specific versions of this approach. First, 

we seek comment on the potential 

establishment of a fixed fee applied to 

each interconnection request, which 

would be the same for all 

interconnection requests, irrespective of 

the generating facility’s capacity or 

project location. We seek comment on 

whether establishing a fixed fee would 

be appropriate and, if so, the 

appropriate amount of such a fee. 

137. Second, we seek comment on the 

potential establishment of a variable fee 

applied to each interconnection request. 

The amount of the variable fee could 

depend upon the generating facility 

capacity associated with the 

interconnection request and/or the 

identified interconnection-related 

network upgrades. For example, the fee 

could be based on a percentage of the 

estimated interconnection-related 

network upgrade costs or be calculated 

based on the generating facility capacity 

and/or the voltage rating of the 

interconnection-related network 

upgrade. We seek comment on the 

appropriate size of this fee and the 

structure of the fee, if the Commission 

were to require one. We also seek 

comment on whether it is possible to 

use a percentage of interconnectionrelated network upgrade cost estimates 

for this fee, and if so, at which point in 

the generator interconnection process a 

transmission provider would calculate 

that cost. 

138. Finally, we seek comment on 

whether such a fee should be 

established at the outset of the generator 

interconnection process, or whether an 

escalating fee should be imposed as the 

interconnection request moves through 

the study process. For example, a 

smaller fee could be required for entry 

into the feasibility study phase, with a 

larger fee for the system impact study 

phase and the largest fee required to 

enter the facilities study.142 In this 

manner, speculative projects could be 

discouraged from entering the later 

stages of the generator interconnection 

process, while still allowing 

interconnection customers to use the 

feasibility study process as it was 

designed, to determine project 

feasibility for a broader range of project 

sizes and locations. 

(c) Transmission Providers Provide 

Upfront Funding for Only Higher 

Voltage Interconnection-Related 

Network Upgrades 

139. We seek comment on whether it 

would be appropriate to require 

transmission providers to fund upfront 

the costs of any interconnection-related 

network upgrade that is rated at or 

above a certain voltage threshold. 

Interconnection customers would be 

responsible for upfront funding the cost 

of interconnection-related network 

upgrades below that threshold and be 

reimbursed through transmission 

service credits pursuant to the crediting 

policy. 

140. Because higher voltage 

transmission facilities tend to produce 

greater and broader benefits to 

transmission systems than lower voltage 

transmission facilities, this option may 

better satisfy the requirement that the 

allocation of costs be at least roughly 

commensurate with the distribution of 

benefits.143 Thus, where an 

interconnection-related network 

upgrade’s voltage exceeds a defined 

threshold and is likely to produce 

system-wide benefits, it may be 

appropriate to require that transmission 

providers fund the costs of such 

interconnection-related network 

upgrades upfront. 

141. The Commission could also 

adopt a modified version of this 

approach by requiring transmission 

providers to upfront fund the portion of 

the costs of higher voltage 

interconnection-related network 

upgrades that exceeds a pre-determined 

cost threshold. For example, the 

Commission could require transmission 

providers to upfront fund the costs of a 

345 kV interconnection-related network 

upgrade that exceed $10 million. 

Pursuant to this modified version, in 

this example of a 345 kV 

interconnection-related network 

upgrade, the Commission would require 

the interconnection customer to fund all 

network upgrade costs up to $10 million 

and require the transmission provider to 

provide upfront funding for all 

interconnection-related network 

upgrade costs above the $10 million 

threshold. Even in this situation, 

however, the transmission provider 

would still have to provide transmission 

service credits to reimburse the 

interconnection customer for its $10 

million subject to the crediting policy. 

142. We note that the Commission has 

approved a version of this cost sharing 

approach in MISO, albeit in the context 

of responsibility for payment of 

interconnection-related network 

upgrade costs themselves and not just 

the upfront funding of them as 

discussed here. MISO’s tariff provides 

for some cost sharing for 

interconnection-related network 

upgrades under which transmission 

providers recover the costs of 10% of 

interconnection-related network 

upgrades rated 345 kV and above on a 

system-wide basis while directly 

assigning through participant funding 

90% of the costs of such upgrades to the 

interconnection customer whose 

interconnection required the network 

upgrade.144 Furthermore, on multiple 

occasions, the Commission has 

permitted RTOs/ISOs to define different 

transmission facility categories and 

adopt different cost allocation methods 

for transmission facilities based on the 

transmission facility’s voltage 

threshold.145

143. If the Commission were to split 

the upfront funding responsibility for 

interconnection-related network 

upgrades between the transmission 

provider and the interconnection 

customer, it may be useful to create a 

split based on voltage. For example, 

adopting an interconnection-related 

network upgrade voltage threshold to be 

funded upfront by the transmission 

provider has the potential to 

significantly reduce interconnectionrelated network upgrade financing costs 

by eliminating interconnection 

customers’ need to fund upfront the 

likely more expensive higher voltage 

interconnection-related network 

upgrades. It could be appropriate to 

require the transmission provider to 

fund upfront the cost of higher voltage 

interconnection-related network 

upgrades because higher voltage 

transmission facilities are likely to 

produce greater region-wide benefits 

than lower voltage ones. 

144. Whatever the selected voltage 

threshold might be, interconnection 

customers would still be required to 

upfront fund the costs of 

interconnection-related network 

upgrades (subject to the crediting 

policy) that do not meet that threshold. 

Thus, the selection of a voltage 

threshold would necessarily exclude 

from transmission provider upfront 

funding some interconnection-related 

network upgrades that produce regional 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40289 

146Order No. 2003, 104 FERC ¶ 61,103 at P 65. 

147For the purpose of this order, we will refer to 

this time period as the sunset period. 

148See NYISO Tariff, attach S (Rules to Allocate 

Responsibility for the Cost of New Interconnection 

Facilities), Section 25.7.2; see also MISO Tariff, 

Attach. FF Section III.A.2.d.2 (81.0.0). 

transmission benefits. We think it 

important to ensure that, if the 

Commission requires that transmission 

providers establish a voltage threshold 

for sharing the responsibility to fund 

upfront the cost of interconnectionrelated network upgrades, then the 

voltage threshold should be based upon 

the likelihood that interconnectionrelated network upgrades that meet that 

threshold produce more transmission 

benefits than interconnection-related 

network upgrades below that threshold. 

Furthermore, we recognize that there is 

some tension between such an 

approach, which would eliminate the 

requirement that interconnection 

customers upfront fund some 

interconnection-related network 

upgrades based on voltage, thus 

reducing the interconnection customers’ 

financing costs only on larger 

interconnection-related network 

upgrades, and Order No. 2003’s general 

acknowledgement that interconnectionrelated network upgrades, regardless of 

voltage or size, ‘‘benefit all users.’’ 146

Additionally, if the Commission 

adopted this option, in order to avoid 

the responsibility to upfront fund, 

transmission providers will have an 

incentive to identify a lower voltage 

interconnection-related network 

upgrade rather than identifying a higher 

voltage project that may be more 

efficient or cost-effective. 

145. We seek comment on: (1) This 

approach; (2) the appropriate voltage 

threshold and any pre-determined cost 

threshold; and (3) how this approach 

could be implemented in a just and 

reasonable manner. 

(d) Allocate the Upfront Cost of 

Interconnection-Related Network 

Upgrades on a Percentage Basis 

146. We seek comment on whether to 

reduce the allowable percentage of 

interconnection-related network 

upgrade costs that interconnection 

customers must fund upfront (i.e., from 

100% to a lower percentage). The 

crediting policy would apply to the 

portion of the interconnection-related 

network upgrade costs that the 

interconnection customer upfront funds. 

To allow flexibility, we seek comment 

on whether an interconnection customer 

should have the option to elect to 

upfront fund 100% of the 

interconnection-related network 

upgrade if it chooses. 

147. This method could benefit both 

the interconnection customer and the 

transmission provider. With the ability 

to provide partial to full upfront funding 

for interconnection-related network 

upgrades, interconnection customers 

will have the ability to retain some 

control over the speed of 

interconnection-related network 

upgrade construction because they will 

be able to provide initial funding in 

cases where the transmission owner 

does not have the funding readily on 

hand to pay for certain construction 

milestones. Transmission providers will 

benefit because this construct will retain 

the price signal to interconnection 

customers regarding siting decisions, as 

interconnection customers would still 

have to upfront fund (i.e., finance) the 

costs of more expensive larger 

interconnection-related network 

upgrades associated with their 

interconnection requests and the costs 

related to financing interconnectionrelated network upgrades (e.g., interest 

payments due on the loan) should 

increase as the costs of the 

interconnection-related network 

upgrades increase. 

148. We note that adoption of the 

transmission planning and cost 

allocation reforms discussed above is 

likely to result in the development of 

regional transmission facilities intended 

to accommodate significant amounts of 

generation, and thus, has the potential 

to reduce the need for more extensive 

and costly interconnection-related 

network upgrades relative to those 

identified in the generator 

interconnection process at present. 

Thus, the adoption of this generator 

interconnection reform, in conjunction 

with the regional transmission planning 

and cost allocation reforms discussed 

above, could result in a significant 

reduction in interconnection customer 

financing costs while still maintaining a 

price signal for siting decisions. 

149. We seek comment on: (1) This 

approach; (2) the appropriate percentage 

for the interconnection customer’s 

upfront funding; and (3) how this 

approach could be implemented in a 

just and reasonable manner. As part of 

this inquiry, we are interested in 

hearing perspectives on the extent to 

which partial upfront funding by an 

interconnection customer may preserve 

or reduce the incentive for that 

customer to efficiently site a project. We 

seek comment on whether there are 

there other mechanisms, beyond 

customer upfront funding, that may 

incent a customer to site efficiently, and 

that could be adopted in conjunction 

with the elimination of participant 

funding. 

iii. Additional Considerations 

(a) Interconnection-Related Network 

Upgrade Cost Sharing 

150. If the Commission does not 

eliminate participant funding of 

interconnection-related network 

upgrades, we seek comment regarding 

potential cost-sharing measures to 

account for the fact that later-in-time 

interconnection customers may accrue 

benefits from interconnection-related 

network upgrades built to accommodate 

a prior interconnection request. That is, 

if a later-in-time interconnection 

customer benefits from the 

interconnection-related network 

upgrades required to interconnect an 

earlier-in-time interconnection 

customer, the later-in-time 

interconnection customers may also be 

assigned a portion of those costs. The 

transmission provider could require the 

allocation of costs in proportion to the 

benefits that the later-in-time 

interconnection customers receive from 

network upgrades or be based on a 

different method, such as a percent 

share based on usage. To make this 

approach workable, the transmission 

provider could also dictate a point after 

which a later-in-time interconnection 

customer would be insulated from 

bearing the costs of a specific 

interconnection-related network 

upgrade, e.g., prohibiting allocation of 

interconnection-related network 

upgrade costs to interconnection 

customers that enter the queue five 

years or more after the interconnectionrelated network upgrade’s 

energization.147 As we noted above, the 

Commission has previously approved 

tariff provisions pursuant to which 

earlier-in-time interconnection 

customers receive a form of 

reimbursement for the network upgrade 

costs from later-in-time customers.148

We note that the sharing of costs 

between earlier-in-time and later-intime interconnection customers would 

only apply in situations where the 

earlier-in-time interconnection customer 

was assigned any of the costs of the 

interconnection-related network 

upgrade under the participant funding 

framework. We seek comment on a just 

and reasonable method to calculate cost 

sharing for shared network upgrades. 

We also seek comment on whether to 

require, and the appropriate duration of, 

a time after which a later-in-time 

interconnection customer would not be 


lotter on DSK11XQN23PROD with PROPOSALS2
40290 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

149Order No. 2003 defined two categories of 

interconnection facility: (1) Transmission provider’s 

interconnection facilities, which refer to all 

facilities and equipment owned, controlled or 

operated by the transmission provider from the 

point of change of ownership to the point of 

interconnection, including any modifications, 

additions or upgrades to such facilities and 

equipment;’’ and (2) interconnection customer’s 

interconnection facilities, which are located 

between the generating facility and the point of 

change of ownership and which the interconnection 

customer must design, procure, construct, and own. 

See pro forma LGIA art. 1 (Definitions); pro forma 

LGIA art. 5.10. 

150Order No. 2003, 104 FERC ¶ 61,103 at P 353; 

Reform of Generator Interconnection Procedures 

and Agreements, Order No. 845, 163 FERC ¶ 61,043, 

at P 85 (2018), order on reh’g, Order No. 845–A, 166 

FERC ¶ 61,137, order on reh’g, Order No. 845–B, 

168 FERC ¶ 61,092 (2019). Stand alone network 

upgrades refer to interconnection-related network 

upgrades ‘‘that are not part of an Affected System 

that an Interconnection Customer may construct 

without affecting day-to-day operations of the 

Transmission System during their construction. 

Both the Transmission Provider and the 

Interconnection Customer must agree as to what 

constitutes Stand Alone Network Upgrades and 

identify them in Appendix A to the Standard Large 

Generator Interconnection Agreement.’’ See pro 

forma LGIP Section 1 (Definitions). 

allocated the costs of an 

interconnection-related network 

upgrade. 

(b) Option To Build 

151. Order No. 2003 established, and 

Order No. 845 expanded, the 

interconnection customer’s option to 

build transmission provider’s 

interconnection facilities 149 and stand 

alone network upgrades.150 In a nonRTO/ISO, if an interconnection 

customer elects to exercise the option to 

build, the interconnection customer 

assumes the responsibility to design, 

procure, and construct the transmission 

provider’s interconnection facilities and 

stand alone network upgrades and is 

repaid by the transmission provider 

pursuant to the crediting policy. 

152. Importantly, the option to build 

allows interconnection customers to 

have some control over their own 

timelines and construction schedules 

and potentially achieve cost savings 

associated with the design, 

procurement, and construction of the 

transmission provider’s interconnection 

facilities and stand alone network 

upgrades. If the Commission revises the 

requirement that interconnection 

customers upfront fund all or some of 

the costs all of interconnection-related 

network upgrades, corresponding 

changes may be necessary to the option 

to build provisions as they apply to 

stand alone network upgrades to 

recognize that an interconnection 

customer that wants to exercise the 

option to build would no longer be 

responsible to upfront fund the full cost 

of those network upgrades. Therefore, 

we seek comment on what changes may 

be necessary to ensure that the option to 

build provisions remain just and 

reasonable and to retain flexibility for 

interconnection customers in light of 

the potential change to the funding 

policy. 

(c) Interconnection Request Limit 

153. We understand that a 

contributing factor to the 

interconnection queue backlog is a 

tendency by interconnection customers 

to submit multiple interconnection 

requests at different points of 

interconnection, with the intention of 

discovering the lowest cost location to 

site the generating facility (from an 

interconnection perspective), and then 

withdrawing higher-cost 

interconnection requests from the queue 

later in the process. We also understand 

that, absent an appropriately-sized 

penalty (or reasonable restriction) 

associated with submitting an 

interconnection request and then 

subsequently withdrawing such an 

interconnection request, there still may 

be an incentive to submit speculative 

interconnection requests under any of 

the potential interconnection reforms 

discussed above. Therefore, we seek 

comment on whether there should 

penalties for submitting speculative 

requests, how such should be defined, 

and whether there should be a limit on 

the number of interconnection requests 

that a developer can submit in an 

interconnection queue study year and 

how narrowly such a limit should apply 

(e.g., by transmission provider or by 

transmission pricing zone). We also seek 

comment on how to determine a just 

and reasonable limit to the number of 

interconnection requests. Finally, we 

seek comment on how to address 

interconnection requests made by 

affiliated companies and whether those 

interconnection requests should count 

against the limit to the number of 

interconnection requests if one is 

imposed. 

(d) Fast-Track for Interconnection of 

Generating Facilities Committed to 

Regional Transmission Facilities 

154. As discussed above, we seek 

comment on the model established by 

ERCOT to construct the CREZ 

transmission projects. For those 

transmission projects to be approved, 

ERCOT required a certain percentage of 

capacity to be reserved by generation 

developers with existing projects, 

projects under construction, projects 

with signed interconnection agreements, 

or posted collateral. In the case that this 

model may improve the coordination 

between transmission planning and the 

development of future generation, it 

may become important to streamline the 

generator interconnection process for 

generating facilities that are committed 

to interconnecting to these transmission 

facilities. 

155. Therefore, we seek comment on 

whether a fast-track generator 

interconnection process should be 

developed to facilitate interconnection 

of generating facilities that have firmly 

committed to connecting to new 

regional transmission facilities. An 

example of such a fast-track option may 

be to allow the transmission provider to 

perform a limited system impact study 

for only the cluster of generating 

facilities committed under the regional 

transmission planning process and to 

move to the facilities study without 

waiting for earlier studies to complete. 

We recognize that the timeline for 

transmission facility permitting and 

construction often far exceeds that of 

the generator interconnection and 

construction process but seek comment 

nonetheless on whether a faster 

generator interconnection process in 

this scenario would be beneficial. 

156. We seek comment on whether 

such a process would constitute 

inappropriate ‘‘queue jumping,’’ or 

instead would be more appropriately 

viewed as an extension of the 

previously approved first-ready, firstserved queueing practice. In this case, 

are generating facilities that have put up 

financial collateral to ensure that a 

regional transmission facility is 

constructed to serve them appropriately 

considered ‘‘ready’’ projects? We seek 

comment on the feasibility of 

establishing such a proposal, as well as 

the implications on the rest of the 

generator interconnection queue and on 

any legal challenges related to a 

potential ‘‘queue jumping’’ concern. 

(e) Fast-Track for Interconnection of 

‘‘Ready’’ Generating Facilities 

157. In addition to considering a fasttrack generator interconnection process 

for interconnection customers that have 

committed financially to new regional 

transmission facilities, we are 

considering whether allowing a fasttrack for ‘‘ready’’ interconnection 

requests would remove barriers to entry 

for interconnection requests that have 

met certain readiness criteria. For 

example, interconnection requests for 

which the developer has already 

executed a power purchase agreement 

or that have been chosen in a state or 

utility request for proposals may be 

appropriately deemed more ‘‘ready’’ 

than projects that enter the 

interconnection queue without either 

contractual arrangement. Another 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40291 

151Commission staff led a workshop in 2019 to 

explore the role, benefits, and challenges of GridEnhancing Technologies. FERC, Grid-Enhancing 

Technologies, Notice of Workshop, Docket No. 

AD19–19–000 (Sept. 9, 2019). 

example of an interconnection request 

that demonstrates a higher degree of 

readiness could be one sited at a 

previously developed point of 

interconnection that can make use of 

existing interconnection facilities. Such 

interconnection requests may be 

considered more ready because they 

have more ready access to the 

transmission system. Both of these 

examples could be considered more 

ready than interconnection requests 

proposed at points of interconnection 

where the interconnection customer or 

the transmission provider must acquire 

new rights-of-way, permits, and 

agreements with landowners, or that 

face other obstacles to rapid 

development. We seek comment on 

which types of interconnection requests 

could be considered more ‘‘ready’’ and 

able to advance through the 

interconnection queue more quickly, as 

well as comments on the just and 

reasonable structure for such a fast-track 

option. We also seek comment on how 

to implement such a proposal in a 

manner that is not unduly 

discriminatory. As in the prior proposed 

reform, we seek comment on how to 

address possible concerns related to 

what some may consider ‘‘queue 

jumping’’ or whether appropriate factors 

may justify such measures. 

(f) Grid-Enhancing Technologies 

158. We seek comment on whether 

there is the potential for Grid-Enhancing 

Technologies not only to increase the 

capacity, efficiency, and reliability of 

transmission facilities, but, in so doing, 

also to reduce the cost of 

interconnection-related network 

upgrades.151 In light of the potential of 

Grid-Enhancing Technologies, we seek 

comment on whether the Commission 

should require that transmission 

providers consider Grid-Enhancing 

Technologies in interconnection studies 

to assess whether their deployment can 

more cost-effectively facilitate 

interconnections. To the extent 

transmission providers currently 

consider Grid-Enhancing Technologies 

in the generator interconnection 

process, what, if any, shortcomings exist 

in that consideration? If the Commission 

were to require greater consideration of 

Grid-Enhancing Technologies, how 

should it do so? What, if any, challenges 

exist in establishing such a requirement 

and how might these challenges be 

addressed? 

C. Enhanced Transmission Oversight 

159. The potential for a significant 

investment in the transmission system 

in the coming years underscores the 

importance of ensuring that ratepayers 

are not saddled with costs for 

transmission facilities that are unneeded 

or imprudent. As part of this package of 

potential reforms, we are considering 

whether reforms may be needed to 

enhance oversight of transmission 

planning and transmission providers’ 

spending on transmission facilities to 

ensure that transmission rates remain 

just and reasonable. 

1. Potential Need for Reform 

160. As discussed above, the 

electricity sector is in the midst of a 

fundamental transition as the generation 

mix shifts rapidly from largely 

centralized resources located close to 

population centers towards renewable 

resources located far from customers. 

Potential reforms to regional 

transmission planning and cost 

allocation and generator interconnection 

should help protect customers 

throughout this transition by directing 

planning toward the more efficient or 

cost-effective transmission facilities. 

Nevertheless, particularly in light of 

potential costs of new transmission 

infrastructure that may be needed to 

meet the needs of the changing resource 

mix, we seek comment on whether 

additional measures may be necessary 

to ensure that the planning processes for 

the development of new transmission 

facilities, and the costs of the facilities, 

do not impose excessive costs on 

consumers. 

161. We seek comment on whether 

the relatively large investment in 

transmission facilities resulting from the 

regional transmission planning and cost 

allocation processes reflects the more 

efficient or cost-effective solutions for 

meeting transmission needs, including 

those associated with a changing 

resource mix. The transparency with 

which transmission needs are identified 

and transmission facilities approved is 

an important element in ensuring that 

excessive costs are not being imposed 

on consumers. Although Order No. 890 

requires that transmission planning 

processes comply with the transmission 

planning principles, including 

transparency and openness, 

transmission providers comply with 

those requirements in various ways. 

162. We seek comment on whether 

the current transmission planning 

processes provide sufficient 

transparency for stakeholders to 

understand how best to obtain 

information and fully participate in the 

various processes. For example, we seek 

comment whether in non-RTO/ISO 

regions individual transmission owning 

members’ local transmission planning 

processes may not be as well publicized 

or follow as well understood processes 

to provide information as in RTO/ISO 

regions. We seek comment on whether 

this may result in material costs being 

imposed on consumers with limited 

visibility into the actual need for a local 

transmission facility or support for a 

specific local transmission solution. We 

also seek comment on whether, in light 

of the significant potential costs of 

transmission and this potential deficit 

in transparency, customers and other 

stakeholders might benefit from 

enhanced oversight over identification 

and costs of transmission facilities. 

2. Potential Reforms and Request for 

Comment 

a. Independent Transmission Monitor 

163. We seek comment on which 

potential measures the Commission 

could take to ensure that there is 

appropriate oversight over how new 

regional transmission facilities are 

identified and paid for. For example, we 

seek comment on whether, to improve 

oversight of transmission facility costs, 

it would be appropriate for the 

Commission to require that transmission 

providers in each RTO/ISO, or more 

broadly, in non-RTO/ISO transmission 

planning regions, establish an 

independent entity to monitor the 

planning and cost of transmission 

facilities in the region. 

164. We seek comment on the 

Commission’s authority to require an 

independent entity to monitor 

transmission spending in each 

transmission planning region, as well as 

the role that such monitor(s) would 

play. For example, this independent 

transmission monitor might potentially 

review transmission planning processes, 

planning criteria that lead to the 

identification of particular transmission 

needs and facilities, as well as the rules 

and regulations governing such 

processes. Additionally, the 

independent transmission monitor 

could review transmission provider 

spending on transmission facilities and 

identify instances of potentially 

excessive transmission facility costs, 

including through inefficiencies 

between local and regional transmission 

planning processes. Further, the 

independent transmission monitor 

could identify instances in which 

transmission facilities were selected in 

the regional transmission plan for cost 

allocation when it may not be clear that 

such projects were the more efficient or 


lotter on DSK11XQN23PROD with PROPOSALS2
40292 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

152This is different than the safeguards provided 

under the transmission formula rate protocols that 

have been implemented for formula rates in 

transmission providers’ OATTs. The transmission 

formula rate protocols are generally designed to 

provide interested parties sufficient opportunity to 

obtain and review information necessary to evaluate 

the implementation of the formula rate, which 

allows public utilities to recover the cost for 

transmission facilities that are already constructed 

and placed in service, except in limited 

circumstances (e.g., a transmission provider may 

recover a return on costs of plant that is in the 

process of construction by receiving regulatory 

approval to include such costs of construction work 

in progress in rate base under its formula rate). The 

protocols outline the process for the annual formula 

rate informational filing at the Commission, 

transparency around the transmission formula rate 

information exchange, the scope of participation, 

and the ability of customers to challenge 

transmission providers’ implementation of the 

formula rate. See Midwest Indep. Transmission Sys. 

Operator, Inc., 139 FERC ¶ 61,127 (2012); Midwest 

Indep. Transmission Sys. Operator, Inc., 143 FERC 

¶ 61,149 (2013); Midcontinent Indep. Sys. Operator, 

Inc., 146 FERC ¶ 61,212 (2014); Midcontinent 

Indep. Sys. Operator, Inc., 150 FERC ¶ 61,025 

(2015). 

cost-effective transmission solutions, or 

were approved for regional cost 

allocation when credible less-costly 

alternatives were available. If the 

independent transmission monitor 

identifies such examples, it could make 

a referral to the Commission. The 

Commission could then conduct a 

review of the relevant transmission 

planning processes and/or transmission 

facility costs under section 206 of the 

FPA. We seek comment on the proposal 

outlined in this paragraph. 

165. We seek comment on whether 

the independent transmission monitor’s 

review could potentially focus on the 

transmission planning process and costs 

of transmission facilities before 

construction starts.152 We seek comment 

on whether and how the Commission 

might modify the regional transmission 

planning and cost allocation processes 

or rate recovery rules and procedures so 

as to facilitate such up-front review. 

166. We also seek comment on how 

an independent transmission monitor 

could approach cost oversight. One 

possible method would be to scrutinize 

the relevant regional transmission 

plan(s) to determine whether a different 

portfolio of local and regional 

transmission facilities would lead to 

higher net benefits. With regard to 

individual transmission facilities 

selected via the regional transmission 

planning processes or chosen through 

the local transmission planning 

processes, the independent entity could 

provide information to assist the 

Commission in determining whether the 

selection of a given transmission facility 

warrants additional Commission review. 

Such assistance may include the 

development of independent cost 

estimates for transmission facilities. 

Given the challenges of reviewing all 

transmission facilities, we seek 

comment on whether it would be useful 

for the Commission or the independent 

entity to develop criteria (such as a 

minimum spending threshold) to 

determine which transmission facilities 

should be subject to review. 

167. We seek comment on tools that 

could be developed to assist such a 

transmission monitor or the 

Commission in reviewing transmissionrelated spending. For example, such a 

monitor might develop benchmark cost 

estimates that would be independent of 

cost estimates developed by a 

transmission provider, which could 

serve as a mechanism to assess 

performance for each transmission 

provider for the applicable transmission 

facilities. The independent transmission 

monitor could create separate estimates 

for regional versus local transmission 

facilities and classify facility costs by 

criteria (such as voltage level), with 

estimates based on well-established 

methods using the best information 

available just prior to the start of 

construction to minimize the error in 

cost estimation. The Commission could 

then review the costs for transmission 

facilities that significantly exceed the 

cost estimates, either sua sponte or on 

the recommendation of the independent 

transmission monitor or a third party. 

An independent transmission monitor 

could also seek information from 

transmission providers regarding the 

variances between actual and estimated 

costs for selected regional transmission 

facilities and use this information in its 

assessment of whether further 

Commission review is recommended. 

168. We seek comment on whether an 

independent transmission monitor 

should provide advice on the design 

and implementation of the regional 

transmission planning and cost 

allocation processes in addition to 

oversight of the regional transmission 

planning process and the costs of the 

development of individual transmission 

facilities. The independent transmission 

monitor could review the design of the 

regional transmission planning and cost 

allocation processes on an ongoing basis 

and highlight areas where 

improvements could be made (for 

example, optimization between local 

and regional transmission planning). 

The independent transmission monitor 

could also review mechanisms used in 

transmission planning processes, such 

as adjusted production cost modeling 

tools, and assess the extent to which 

modifications to such mechanisms 

might yield more efficient transmission 

spending decisions. 

169. The independent transmission 

monitor could also identify and report 

on situations in which non-wires 

alternatives could more cost-effectively 

address transmission system needs. We 

seek comment on the value of such 

reporting and whether such information 

could improve the ability for states to 

participate in the regional transmission 

planning process and provide a greater 

opportunity for input. Similarly, we 

seek comment on whether an 

independent transmission monitor or 

other oversight mechanism should 

evaluate and report on transmission 

providers’ consideration of GridEnhancing Technologies in the 

transmission planning process. If so, 

how should that evaluation be 

conducted and what information should 

be reported? 

170. Additionally, we seek comment 

on whether oversight of the planning 

and approval of local transmission 

facilities is necessary to ensure that 

transmission rates are just and 

reasonable. We seek comment on 

whether an independent transmission 

monitor should evaluate whether the 

transmission needs identified in the 

local transmission planning processes 

could be better considered during 

regional transmission planning 

processes to allow for the identification 

of more efficient or cost-effective 

transmission solutions. In addition, we 

seek comment on whether oversight 

should consider the development and 

application of transmission planning 

criteria. Finally, we encourage 

commenters to identify any other factors 

that they believe the Commission 

should consider for oversight within the 

local transmission planning process. At 

the same time, we seek comment on 

whether such a role for a federallyregulated regional transmission monitor 

would improperly or inappropriately 

expand the role of federal regulation 

over local utility regulation and/or 

potentially increase administrative and 

legal costs of local transmission 

planning with no commensurate 

benefits for customers. More broadly, 

we seek comment on whether there is a 

need to delineate more clearly the 

oversight roles of federal and state 

regulators over local transmission 

planning. 

171. In addition, we seek comment on 

whether there is sufficient clarity on the 

roles and responsibilities between state 

and federal regulators regarding the 

local transmission planning criteria and 

the development of local transmission 

facilities (e.g., ‘‘Supplemental Projects’’ 

in PJM). We seek comment on whether 

such transmission facilities require 

additional oversight and whether 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40293 

153Order No. 1000, 136 FERC ¶ 61,050 at P 148. 

154SPP, Governing Documents Tariff, Bylaws, 

Section 7.2 (Regional State Committee) (1.0.0). 

155New Eng. Power Co., Opinion No. 295, 42 

FERC ¶ 61,016, at 61,081–82, order on reh’g, 

Opinion No. 295–A, 43 FERC ¶ 61,285 (1988). The 

Commission also allows recovery under section 205 

of return on 50% of investment costs incurred to 

construct transmission facilities (and other nonpollution control plant) through the inclusion of 

Construction Work in Progress (CWIP) in rate base 

during the construction period, provided certain 

conditions are met. Construction Work In Progress 

Continued 

additional coordination among state and 

federal regulators would be beneficial. 

Similarly, we seek comment on whether 

and how greater oversight may improve 

coordination between individual 

transmission provider’s planning 

processes and regional transmission 

planning processes. Order No. 1000 

requires the evaluation of ‘‘alternative 

transmission solutions that might meet 

the needs of the transmission planning 

region more efficiently or costeffectively than solutions identified by 

individual public utility transmission 

providers.’’ 153 We seek comment on 

whether current rules and processes are 

adequately aligned with and facilitate 

such consideration or evaluation, and if 

not, whether there are oversight 

measures or other mechanisms, 

including via an independent 

transmission monitor, that could better 

facilitate the consideration of more 

efficient or cost-effective alternatives. 

For example, we seek comment on 

whether individual transmission 

provider practices regarding retirement 

and replacement of transmission 

facilities sufficiently align with the 

directive to ensure evaluation of 

alternative transmission solutions and 

whether these practices sufficiently 

consider the more efficient or costeffective ways to serve future needs. We 

also seek comment on whether 

sufficient transparency exists in 

retirement decisions to allow for such 

regional assessment. We seek comment 

on what role can or should an 

independent transmission monitor play 

in facilitating enhanced coordination. 

172. Furthermore, we seek comment 

on whether additional transparency 

measures are appropriate or should be 

in place for transmission providers, 

including those outside of RTO/ISO 

regions. If so, we seek comment on 

whether the Commission should apply 

transparency measures, some of which 

are currently utilized within RTO/ISO 

regions (e.g., dedicated transmission 

planning web pages, requirements to 

publish and detail full transmission 

plan at end of each transmission 

planning cycle, scorecards), or consider 

different or new transparency measures 

for transmission providers outside of 

RTO/ISO regions. We seek comment on 

whether new or different transparency 

measures are needed within the RTO/ 

ISO regions. 

173. An independent transmission 

monitor would not replace the 

Commission’s rate jurisdiction but 

instead could provide the Commission 

with an additional means of ensuring 

that rates are just and reasonable. With 

respect to other aspects of prudence, or 

transmission facility selection against 

alternatives, the independent 

transmission monitor would not 

supplant the Commission’s authority 

with respect to prudence, but could 

inform the Commission as to whether a 

further review is warranted; the final 

determination on whether costs are 

prudently incurred remains with the 

Commission. Similarly, the record 

created by the independent 

transmission monitor could help the 

Commission in ensuring that the design 

of the regional transmission planning 

and cost allocation processes remain 

just and reasonable and not unduly 

discriminatory or preferential. 

174. We seek comment on (1) the 

independent transmission monitor 

proposal, and (2) any alternative options 

for improving oversight of transmission 

costs or the effectiveness of 

transmission planning processes. 

Additionally, we seek comment on 

whether the concerns regarding 

transmission oversight are best 

addressed by an independent entity 

similar to the role of an independent 

market monitor, or whether the 

concerns can be adequately addressed 

by the RTO/ISO or transmission 

providers in non-RTO/ISO regions, or 

through another approach. 

175. We also seek comment on (1) 

how an independent transmission 

monitor (or set of regional monitors) 

would be created or authorized; (2) 

whether a single monitor should be 

appointed for each transmission region, 

or instead a given monitor might review 

transmission across several regions; (3) 

the Commission’s authority to require 

an independent transmission monitor in 

all transmission planning regions; (4) 

how this entity would work in practice, 

in both the RTO/ISO and non-RTO/ISO 

regions; and (5) the scope of review 

such monitor(s) should be charged with 

carrying out, including whether such 

monitoring should extend to oversight 

of the generator interconnection 

process. 

b. State Oversight 

176. Another way to add oversight to 

the transmission planning and cost 

allocation processes could be to involve 

state commissions in those processes. 

By way of example, SPP has a Regional 

State Committee (RSC), which provides 

collective state regulatory agency input 

in areas under the RSC’s primary 

responsibilities and on matters of 

regional importance related to the 

development and operation of the bulk 

electric transmission system. Pursuant 

to the SPP Bylaws, ‘‘with respect to 

transmission planning, the RSC will 

determine whether transmission 

upgrades for remote resources will be 

included in the regional transmission 

planning process and the role of 

transmission owners in proposing 

transmission upgrades in the regional 

planning process.’’ 154

177. We seek comment on whether 

this type of model, or other models that 

may be proposed, could be expanded to 

other regions and other topics; for 

example, whether a state-led committee 

could: Provide insight into regional 

transmission facility costs and cost 

allocation methods; evaluate whether 

the transmission needs identified in the 

local transmission planning processes 

could be better considered during 

regional transmission planning 

processes; inform the Commission as to 

whether a further review is warranted of 

whether incurred costs are prudent; or 

provide the Commission with an 

additional means of ensuring that rates 

are just and reasonable. We also seek 

comment on how such a model may be 

combined with other oversight tools or 

mechanisms explored herein. For 

example, given state regulatory 

authority over the approval of non-wires 

solutions, can or should a regional state 

committee play a role in identifying 

circumstances under which a non-wires 

solution would be the more efficient or 

cost-effective solution to solving an 

identified regional transmission need, 

and facilitating a process by which the 

relevant state regulator could be given 

an opportunity to approve such a 

solution? 

c. Limitation on Recovery of Costs for 

Abandoned Projects 

178. There is always a risk that once 

approved, a regional project may be 

abandoned before going into service for 

a variety of reasons including a failure 

to obtain all necessary state and federal 

approvals, including, for example, state 

certificates of public convenience and 

necessity. The Commission’s general 

policy for recovery of the costs of 

abandoned plant under section 205 of 

the FPA allows recovery of and return 

on 50% of the prudently incurred 

investment costs incurred in connection 

with the abandoned plant.155 In 


lotter on DSK11XQN23PROD with PROPOSALS2
40294 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

for Public Utilities; Inclusion of Costs in Rate Base, 

Order No. 298, 48 FR 24,323 (June 1, 1983), FERC 

Stats. & Regs. ¶ 30,455, order on reh’g, Order No. 

298–A, 48 FR 46,012 (Oct. 11, 1983), FERC Stats. 

& Regs., ¶ 30,500 (1983), order on reh’g, Order No. 

298–B, 48 FR 55,281 (Dec. 12, 1983), FERC Stats. 

& Regs. ¶ 30,524 (1983) (Order No. 298). 

156Promoting Transmission Investment through 

Pricing Reform, Order No. 679, 116 FERC ¶ 61,057, 

order on reh’g, Order No. 679–A, 117 FERC ¶ 61,345 

(2006), order on reh’g, 119 FERC ¶ 61,062 (2007). 

addition, the Commission may grant as 

an incentive under section 219 of the 

FPA for transmission facilities meeting 

the qualifications for the incentive, 

recovery of 100% of prudently-incurred 

costs related to such facilities if they are 

abandoned for reasons beyond the 

control of the transmission owner.156 In 

light of potential costs of new regional 

transmission infrastructure and the 

corresponding risk that some of those 

projects may be abandoned, we seek 

comment on whether the Commission 

should revisit its policies regarding 

abandoned plant to better protect 

consumers from increased costs due to 

never-built transmission facilities. 

179. For example, one proposal to 

protect consumers would be to limit the 

recovery of costs through abandonment 

by allowing only the recovery of some 

portion of actual development or precommercial costs, and/or no recovery of 

a return on equity on such costs prior 

to the project receiving all necessary 

regulatory approvals. We therefore seek 

comment on this or other proposals to 

limit the amount that can be recovered 

for regional transmission facilities that 

are abandoned prior to going into 

service. Commenters are, of course, 

welcome to address all issues and 

concerns pertinent to such proposals. 

d. Additional Oversight Approaches 

180. Finally, we seek comment on 

additional oversight approaches the 

Commission might take to ensure that 

wholesale transmission spending is cost 

effective. For example, performancebased regulation. We ask how 

performance-based regulation may be 

designed to ensure that rates are just 

and reasonable, ensure reliability of the 

transmission system, promote regional 

expansion of transmission facilities for 

a sufficiently wide range of future 

scenarios, including anticipated future 

generation, and encourage transmission 

provider participation. 

D. Transition 

181. To implement any of the 

proposals outlined above, transmission 

providers must transition to new 

interconnection pricing paradigms and 

new regional transmission planning and 

cost allocation processes. Therefore, we 

seek comment on appropriate transition 

plans, including treatment of 

interconnection customers in the 

various stages of the generator 

interconnection process and those that 

have already interconnected as well as 

when the more holistic regional 

transmission planning and cost 

allocation processes would begin 

(including when the broader category of 

regional transmission facilities would be 

established). 

182. The Commission also seeks input 

as to the length of time that might be 

necessary to implement any reforms that 

result from this process. Specifically, 

the Commission requests input as to 

how much time transmission providers 

might need to develop compliance 

filings related to all of the proposals in 

this ANOPR. 

V. Comment Procedures 

183. The Commission invites 

interested persons to submit comments 

on these matters and any related matters 

or alternative proposals that 

commenters may wish to discuss. 

Comments are October 12, 2021 and 

Reply Comments are due November 9, 

2021. Comments must refer to Docket 

No. RM21–17–000 and must include the 

commenter’s name, the organization 

they represent, if applicable, and their 

address in their comments. All 

comments will be placed in the 

Commission’s public files and may be 

viewed, printed, or downloaded 

remotely as described in the Document 

Availability section below. Commenters 

on this proposal are not required to 

serve copies of their comments on other 

commenters 

184. The Commission encourages 

comments to be filed electronically via 

the eFiling link on the Commission’s 

website at https://www.ferc.gov. The 

Commission accepts most standard 

word processing formats. Documents 

created electronically using word 

processing software must be filed in 

native applications or print-to-PDF 

format and not in a scanned format. 

Commenters filing electronically do not 

need to make a paper filing. 

185. Commenters that are not able to 

file comments electronically may file an 

original of their comment by USPS mail 

or by courier-or other delivery services. 

For submission sent via USPS only, 

filings should be mailed to: Federal 

Energy Regulatory Commission, Office 

of the Secretary, 888 First Street NE, 

Washington, DC 20426. Submission of 

filings other than by USPS should be 

delivered to: Federal Energy Regulatory 

Commission, 12225 Wilkins Avenue, 

Rockville, MD 20852. 

VI. Document Availability 

186. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the internet through the 

Commission’s Home Page (https://

www.ferc.gov). At this time, the 

Commission has suspended access to 

the Commission’s Public Reference 

Room due to the President’s March 13, 

2020 proclamation declaring a National 

Emergency concerning the Novel 

Coronavirus Disease (COVID–19). 

187. From the Commission’s Home 

Page on the internet, this information is 

available in its eLibrary. The full text of 

this document is available in the 

eLibrary in PDF and Microsoft Word 

format for viewing, printing, and/or 

downloading. To access this document 

in eLibrary, type the docket number of 

this document excluding the last three 

digits in the docket number field. 

188. User assistance is available for 

eLibrary and the Commission’s website 

during normal business hours from the 

Commission’s Online Support at 202– 

502–6652 (toll free at 1–866–208–3676) 

or email at ferconlinesupport@ferc.gov, 

or the Public Reference Room at (202) 

502–8371, TTY (202) 502–8659. Email 

the Public Reference Room at 

public.referenceroom@ferc.gov. 

By direction of the Commission. 

Chairman Glick and Commissioner 

Clements are concurring with a joint 

separate statement attached. 

Commissioner Chatterjee is not 

participating. Commissioner Danly is 

concurring with a separate statement. 

Commissioner Christie is concurring 

with a separate statement. 

Issued: July 15, 2021. 

Debbie-Anne A. Reese, 

Deputy Secretary. 

Department of Energy 

Federal Energy Regulatory Commission 

Building for the Future Through Electric 

Regional Transmission Planning and 

Cost Allocation and Generator 

Interconnection 

Docket No. RM21–17–000 

GLICK, Chairman, CLEMENTS, 

Commissioner, concurring: 

1. The generation resource mix is 

changing rapidly. Due to a myriad of 

factors—including improving 

economics, customer and corporate 

demand for clean energy, public utility 

commitments and integrated resource 

plans, as well as federal, state, and local 

public policies—renewable resources in 

particular are coming online at an 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40295 

1See, e.g., Joseph Rand et al., Queued Up: 

Characteristics of Power Plants Seeking 

Transmission Interconnection as of the End of 2020, 

Lawrence Berkeley National Laboratory, May 2021, 

https://eta-publications.lbl.gov/sites/default/files/ 

queued_up_may_2021.pdf; Electric Power Monthly, 

Table 6.1 Electric Generating Summer Capacity 

Changes (MW), U.S. Energy Information 

Administration, (Mar. 2021 to Apr. 2021), https:// 

www.eia.gov/electricity/monthly/epm_table_

grapher.php?t=table_6_01. 

2 Joint Federal-State Task Force on Electric 

Transmission, 175 FERC ¶ 61,224 (2021). 

3 2018 Renewable Energy Data Book at 26, NREL, 

https://www.nrel.gov/docs/fy20osti/75284.pdf. 

Wind and solar resources, in particular, have grown 

at a disproportionate rate, with solar generation 

capacity increasing roughly 5,000% from 1,054 MW 

to 51,899 MW nationwide, and wind generation 

capacity more than tripling from 31,155 MW to 

96,442 MW. 

4See Joseph Rand, Queued Up: Characteristics of 

Power Plants Seeking Transmission Interconnection 

as of the End of 2020, Lawrence Berkeley National 

Laboratory, May 2021, https://etapublications.lbl.gov/sites/default/files/queued_up_

may_2021.pdf. Equally important, this shift is 

taking place across the country, not just in a few 

areas. For example, as of the issuance of this 

ANOPR, in Midcontinent Independent System 

Operator, Inc. (MISO), solar and wind projects 

comprise 80% of all active projects in the current 

interconnection queue, or about 73 GW of total 

capacity. MISO, Generator Interconnection Queue— 

Active Projects Map, https://

giqueue.misoenergy.org/PublicGiQueueMap/ 

index.html. Similarly, in PJM Interconnection, 

L.L.C. (PJM), solar and wind projects with a total 

capacity of 62 GW comprise 79% of all active 

projects in the current interconnection queue as of 

the issuance of this ANOPR. PJM, New Services 

Queue, https://www.pjm.com/planning/servicesrequests/interconnection-queues.aspx. In California 

Independent System Operator Corporation (CAISO), 

renewable and storage capacity of 23 GW comprise 

78% of all active projects in the current 

interconnection queue as of the issuance of this 

ANOPR. CAISO, Generator Interconnection Queue, 

https://www.caiso.com/Documents/ 

ISOGeneratorInterconnectionQueueExcel.xls. 

5See, e.g., Lazard’s Levelized Cost of Energy 

Analysis—Version 14.0, at 9 (Oct. 19, 2020), https:// 

www.lazard.com/perspective/levelized-cost-ofenergy-and-levelized-cost-of-storage-2020/#:∼:text=

Lazard’s%20latest%20annual%20Levelized% 20

Cost,build%20basis%2C%20continue%20to

%20maintain; Ryan Wiser et al., Expert elicitation 

survey predicts 37% to 49% declines in wind 

energy costs by 2050, Lawrence Berkeley National 

Laboratory (Apr. 2021), https://etapublications.lbl.gov/sites/default/files/wind_lcoe_

elicitation_ne_pre-print_april2021.pdf (finding that 

the decrease in levelized cost of energy for wind 

power from 2015–2020 outpaced the decrease 

predicted by experts, and that experts continue to 

predict significant declines in levelized cost of 

energy). 

6See Lazard’s Levelized Cost of Energy 

Analysis—Version 14.0, at 3, 7 (Oct. 19, 2020), 

https://www.lazard.com/perspective/levelized-costof-energy-and-levelized-cost-of-storage-2020/#:∼:

text=Lazard’s%20latest%20annual%20Levelized% 

20Cost,build%20basis%2C%20continue%20to

%20maintain. 

7See, e.g., Deloitte Resources 2020 Study at 22, 

https://www2.deloitte.com/content/dam/insights/ 

us/articles/6655_Resources-study-2020/DI_

Resources-study-2020.pdf (showing that U.S. 

corporate renewable generation purchase power 

agreements increased from 0.3 GW in 2009 to 13.6 

GW in 2019); Kevin O’Rourke & Charles Harper, 

Corporate Renewable Procurement and 

Transmission Planning: Communicating Demand to 

RTOs Necessary to Secure Future Procurement 

Options, A Renewable America (October 2018), 

https://acore.org/wp-content/uploads/2020/04/

Corporates-Renewable-Procurement-andTransmission-Report.pdf (indicating that a group of 

corporations, forming the Renewable Energy Buyers 

Alliance, has set a goal to purchase 60 GW of new 

renewable energy capacity in the U.S. by 2025); 

Stanley Porter et al., Utility Decarbonization 

Strategies, Renew, Reshape, and Refuel to Zero, 

Deloitte Insights (Sept. 2021), https://

www2.deloitte.com/us/en/insights/industry/powerand-utilities/utility-decarbonization-strategies.html 

(indicating that 43 of 55 utilities surveyed have 

emissions reductions targets and 22 have net-zero 

or carbon-free electricity goals); Esther Whieldon, 

Path to net zero: 70% of biggest US utilities have 

deep decarbonization targets, S&P Global Market 

Intelligence (Dec. 9, 2020) at 3–6, https://

www.spglobal.com/marketintelligence/en/newsinsights/latest-news-headlines/path-to-net-zero-70-

of-biggest-us-utilities-have-deep-decarbonizationtargets-61622651 (indicating that review of utilities’ 

climate goals decarbonization plans, as of December 

2020, shows that 70% of the 30 largest utilities have 

net-zero carbon targets or are moving to comply 

with similarly aggressive state mandates); see also 

Rich Glick and Matthew Christiansen, FERC and 

Climate Change, 40 Energy L.J. 1, 7–12 (2019) (‘‘The 

growth of renewable resources is also a function of 

consumers’ desire for clean energy. Customers— 

including residential, commercial, and even 

industrial consumers—are increasingly demanding 

that their energy come from renewable or zeroemissions sources’’). 

unprecedented rate.1 As a result, the 

transmission needs of the electricity 

grid of the future are going to look very 

different than those of the electricity 

grid of the past. 

2. We are concerned that the current 

approach to transmission planning and 

cost allocation cannot meet those future 

transmission needs in a manner that is 

just and reasonable and not unduly 

discriminatory or preferential. In 

particular, we believe that the status 

quo approach to planning and allocating 

the costs of transmission facilities may 

lead to an inefficient, piecemeal 

expansion of the transmission grid that 

would ultimately be far more expensive 

for customers than a more forwardlooking, holistic approach that 

proactively plans for the transmission 

needs of the changing resource mix. A 

myopic transmission development 

process that leaves customers paying 

more than necessary to meet their 

transmission needs is not just and 

reasonable. 

3. In that regard, we are pleased to see 

the Commission taking a consensus first 

step toward updating its rules and 

regulations to ensure that we are 

meeting the nation’s evolving 

transmission needs in a cost-effective 

and efficient fashion. Today’s action 

complements our recently established 

joint federal-state task force with the 

National Association of Regulatory 

Utility Commissioners,2 which we 

expect to produce a robust dialogue on 

many of the issues addressed herein. In 

our view, this advance notice of 

proposed rulemaking (ANOPR) is just 

the first step. Ensuring that transmission 

rates remain just and reasonable will 

require further action, including reforms 

to interregional transmission planning 

and cost allocation, as well as other 

reforms to our regional transmission 

planning and cost allocation and 

generator interconnection processes 

beyond those contemplated herein. 

Nevertheless, we believe that today’s 

unanimous Commission action 

represents a solid foundation for an 

expeditious inquiry into how we can 

regulate to achieve the transmission 

needs of our changing electricity system 

in a manner consistent with our 

statutory obligations under the Federal 

Power Act. 

* * * * * 

4. The generation mix is shifting 

rapidly from large resources located 

close to population centers toward 

renewable resources, often combined 

with onsite storage, that tend to be 

located where their fuel source is best— 

i.e., where the wind blows hardest or 

the sun shines brightest. According to 

the National Renewable Energy 

Laboratory (NREL), total renewable 

generation capacity nearly doubled from 

2009 to 2018, increasing from 11.7% of 

total generation capacity to 20.5%.3 And 

that is just the beginning: Of the roughly 

750 GW of generation in 

interconnection queues around the 

country, nearly 700 GW are renewable 

resources,4 providing every reason to 

believe that the dramatic shift toward 

renewable generation will only 

accelerate in the years ahead. 

5. That shift is the result of many 

factors. First and foremost, the cost of 

renewable resources is plummeting. For 

example, in its annual report on the 

levelized cost of energy, Lazard found 

that between 2009 to 2020, the levelized 

cost of energy from unsubsidized wind 

generation and unsubsidized utilityscale solar generation decreased by 71% 

and 90%, respectively 5—enough to 

make utility-scale solar and wind 

generation cost-competitive with central 

station fossil generation sources in 

many parts of the country.6 Moreover, 

customers—both residential and 

commercial—are increasingly 

demanding clean energy, particularly 

energy from renewable resources— 

which is itself causing utilities and 

independent power producers to 

attempt to send large quantities of 

renewable energy onto the grid.7 In 

addition, dozens of the biggest utilities 

in the country have established their 

own decarbonization goals, the 

achievement of which will require their 


lotter on DSK11XQN23PROD with PROPOSALS2
40296 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

8See, e.g., Corporate Renewable Procurement and 

Transmission Planning: Communicating Demand to 

RTOs Necessary to Secure Future Procurement 

Options, A Renewable America, October 2018, 

https://acore.org/wp-content/uploads/2020/04/

Corporates-Renewable-Procurement-andTransmission-Report.pdf; Esther Whieldon, Path to 

net zero: 70% of biggest US utilities have deep 

decarbonization targets, S&P Global Market 

Intelligence, Dec. 9, 2020, at 3–6, https://

www.spglobal.com/marketintelligence/en/newsinsights/latest-news-headlines/path-to-net-zero-70- 

of-biggest-us-utilities-have-deep-decarbonizationtargets-61622651. 

9Nat’l Conference of State Legislatures, State 

Renewable Portfolio Standards and Goals (Nov. 7, 

2021), https://www.ncsl.org/research/energy/

renewable-portfolio-standards.aspx#:∼:text=Thirty

%20states%2C%20Washington%2C%20DC

%2C,have%20set%20renewable%20energy

%20goals. Renewable portfolio standards are 

policies that are designed to increase the amount of 

renewable energy sources used for electricity 

generation. 

10See, e.g., Berkeley Lab, U.S. Renewables 

Portfolio Standards: 2019 Annual Status Update 

(Aug. 2019), https://emp.lbl.gov/publications/usrenewables-portfolio-standards-2. 

11Carbon Pricing in Organized Wholesale Elec. 

Markets, 175 FERC ¶ 61,036, at P 2 (2021) 

(‘‘Thirteen states—California, Hawaii, Maine, 

Maryland, Massachusetts, Nevada, New Jersey, New 

Mexico, New York, Oregon, Vermont, Virginia, and 

Washington—and the District of Columbia have 

adopted clean energy or renewable portfolio 

standards of 50% or greater.’’). In addition, ‘‘a 

number of states—including Colorado, Connecticut, 

Nevada, Rhode Island, and Wisconsin—have 

established 100% clean electricity goals or targets 

by executive order or other non-binding 

commitment.’’ See id. At the local level, cities and 

counties are also accelerating clean energy 

commitments. Kelly Trumbull et al., Progress 

Toward 100% Clean Energy in Cities and States 

Across the U.S., University of California—Los 

Angeles Luskin Center for Innovation (November 

2019) at 10, https://innovation.luskin.ucla.edu/wpcontent/uploads/2019/11/100-Clean-EnergyProgress-Report-UCLA-2.pdf (finding over 200 cities 

and counties across 37 U.S. states have 100 percent 

clean energy commitments). 

12National Resources Defense Council (NRDC), 

NRDC’s 8th Annual Energy Report: Slow and 

Steady Will Not Win the Climate Race (Dec. 2, 

2020), https://www.nrdc.org/resources/nrdcs-8thannual-energy-report-slow-and-steady-will-not-winrace?nrdcpreviewlink=rmmB6NM6zpiOTruhuObZ

JdH92bCOvmZTY1hx72xCSzQ#renewables. 

13 16 U.S.C. 824e. 

14See generally Eric Larson et al., Net-Zero 

America: Potential Pathways, Infrastructure, and 

Impact (2020), Princeton_NZA_Interim_Report_15_

Dec_2020_FINAL.pdf (discussing different 

pathways for meeting decarbonization goals, 

including differing approaches to transmission 

investment). 

15See Transmission Planning and Cost Allocation 

by Transmission Owning and Operating Public 

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

11 (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. v. FERC, 762 F.3d 

41 (D.C. Cir. 2014). 

16Cf. BNP Paribas Energy Trading GP v. FERC, 

743 F.3d 264, 268–269 (D.C. Cir. 2014) (‘‘[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 

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

Se. Michigan Gas Co. v. FERC, 133 F.3d 34, 41 (D.C. 

Cir. 1998))). 

own significant investment in 

renewable generation.8

6. Finally, federal, state, and local 

policymakers have adopted a range of 

public policies that are driving the 

changing resource mix. For example, 30 

states and the District of Columbia have 

adopted renewable portfolio standards,9

with those standards contributing to 

roughly 50% of the total growth in 

renewable generation over the last two 

decades.10 In addition, several states 

have doubled down on the clean energy 

transition by enacting measures that 

require that most or all of their 

electricity come from zero emissions 

resources.11 All told, ‘‘states and 

utilities that have committed to 

transitioning to 100 percent clean power 

serve nearly 83 million households and 

businesses, representing around 50 

percent of all U.S. electricity demand in 

2019.’’ 12

7. Dramatic changes in the resource 

mix inevitably come with similarly 

dramatic changes in transmission needs. 

As noted, the increasingly costcompetitive renewable resources that 

customers and public policies demand 

tend to be developed farther away from 

customers where their fuel sources are 

strong and development costs are low 

rather than in close proximity to their 

ultimate customers. As a result, the 

future resource mix will likely present 

new transmission needs, different from 

those of the large resources located close 

to population centers that have 

dominated electricity generation in the 

past. Meeting those transmission needs 

will likely require both the 

infrastructure necessary to interconnect 

new resources to the transmission 

system efficiently and the infrastructure 

necessary to reliably move the 

electricity produced by those resources 

to where it is needed. This could make 

it considerably more expensive than 

necessary to bring in the low-cost 

generation demanded by customers and 

meet federal, state, and local public 

policies. 

8. This Commission cannot sit idly 

by. Our role is to ensure just and 

reasonable rates and support reliability 

in light of changes in the market, not to 

pretend those changes are not 

happening. We are concerned that, in 

light of evolving transmission needs, the 

current regional transmission planning 

and cost allocation and generator 

interconnection processes may no 

longer ensure just and reasonable rates 

for transmission service.13 In particular, 

we are concerned that existing regional 

transmission planning processes may be 

siloed, fragmented, and not sufficiently 

forward-looking, such that transmission 

facilities are being developed through a 

piecemeal approach that is unlikely to 

produce the type of transmission 

solutions that could more efficiently 

and cost-effectively meet the needs of 

the changing resource mix. Regional 

transmission planning processes 

generally do little to proactively plan for 

the resource mix of the future, including 

both commercially established 

resources, such as onshore wind and 

solar, as well as emerging ones, such as 

offshore wind. We are also concerned 

that current regional transmission 

planning processes are not sufficiently 

integrated with the generator 

interconnection processes, and are 

overwhelmingly focused on relatively 

near-term transmission needs, and that 

attempting to meet the needs of the 

changing resource mix through such a 

short-term lens will lead to inefficient 

transmission investments. As a result, 

under the status quo, customers could 

end up paying far more to meet their 

transmission needs than they would 

under a more forward-looking approach 

that identifies the more efficient or costeffective investments in light of the 

changing resource mix.14

9. Relatedly, we are also concerned 

that the current approach to 

transmission planning and cost 

allocation is failing to adequately 

identify the benefits and allocate the 

costs of new transmission infrastructure. 

Although the regional transmission 

planning process considers transmission 

needs driven by reliability, economics, 

and Public Policy Requirements,15 those 

transmission needs are often viewed in 

isolation from one another and the cost 

allocation methods for projects selected 

to meet those needs are similarly siloed. 

As a result, the status quo may be 

disproportionately producing 

transmission facilities that address a 

narrow set of needs, providing 

comparatively modest benefits, but at a 

still-substantial total cost instead of 

developing the type of transmission 

infrastructure that could provide the 

most significant benefits for customers. 

In the same vein, we are also concerned 

that many customers who share in the 

diverse array of benefits that 

transmission infrastructure can offer 

may not be paying their fair share, as 

required by the cost causation 

principle.16

10. In addition, we are concerned 

that, largely due to the potential 

shortcomings with the current regional 

transmission planning and cost 

allocation processes, transmission 

infrastructure is increasingly being 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 40297 

17Cf., e.g., California ex rel. Lockyer v. FERC, 383 

F.3d 1006, 1017 (9th Cir. 2004) (rejecting ‘‘an 

interpretation [that] comports neither with the 

statutory text nor with the Act’s ‘primary purpose’ 

of protecting consumers’’); City of Chicago v. FPC, 

458 F.2d 731, 751 (D.C. Cir. 1971) (‘‘[T]he primary 

purpose of the Natural Gas Act is to protect 

consumers.’’ (citing, inter alia, City of Detroit v. 

FPC, 230 F.2d 810, 815 (D.C. Cir. 1955)). 18See supra n.2. 

1See, e.g., PacifiCorp, 171 FERC ¶ 61,112 (2020) 

(Danly, Comm’r, concurring). 

developed through the generator 

interconnection process. That means 

that infrastructure with potentially 

significant benefits for a broad range of 

entities may be developed through a 

process that focuses exclusively on the 

needs of a comparatively small number 

of interconnection customers—a 

dynamic that is almost sure to result in 

comparatively inefficient investment 

decisions. The participant funding 

approach to financing interconnectionrelated network upgrades will often 

mean that the interconnection 

customer(s) alone must pay for all—or 

the vast majority—of the costs of that 

transmission infrastructure, even where 

it provides significant benefits to other 

entities. That, in turn, may cause those 

interconnection customers to withdraw 

projects from the queue, causing 

considerable uncertainty and delay, and 

may mean that net beneficial 

transmission infrastructure is never 

developed due to a misalignment in 

how that infrastructure would be paid 

for. 

11. Finally, we are also concerned 

that the Commission’s current approach 

to overseeing transmission investment 

may not adequately protect consumers. 

While transmission infrastructure can 

provide a broad spectrum of benefits, it 

is itself a significant investment that 

represents a major component of 

customers’ electric bills. The 

Commission must vigorously oversee 

the rules governing how transmission 

projects are planned and paid for if we 

are to satisfy our responsibility to 

protect customers from excessive rates 

and charges.17 The potential bases for 

invigorating our oversight of 

transmission spending contemplated in 

today’s order have the potential to go a 

long way toward ensuring that we fulfill 

that function. 

12. Today’s action plants the seeds for 

addressing the concerns outlined above. 

A forward-looking, holistic approach to 

transmission planning has the potential 

to identify the more efficient or costeffective solutions for meeting the 

transmission needs of the changing 

resource mix, including those resources 

that are not yet under development. 

Such an approach would allow 

transmission planners to proactively 

identify the areas of the transmission 

grid that will have significant 

transmission needs and select the more 

efficient or cost-effective solution to 

meet those needs, including needs 

driven by resources that are not yet in 

operation or even under development. 

Doing so has the potential to address the 

transmission needs of the future 

generation mix while costing customers 

considerably less than they would pay 

to meet those same needs under the 

status quo. That, in our view, is what is 

necessary to ensure that the rates for 

transmission service remain just and 

reasonable as the resource mix changes. 

13. We anticipate that this effort will 

be the Commission’s principal focus in 

the months to come. In addition to 

reviewing the record assembled in 

response to today’s order, we intend to 

explore technical conferences and other 

avenues for augmenting that record— 

including through the joint federal-state 

task force 18—before proceeding to 

reform our rules and regulations. We 

recognize that the issues addressed 

herein are highly technical, complex 

problems that do not lend themselves to 

easy solutions. That being said, we also 

recognize the urgent need to address the 

transmission needs of the changing 

resource mix and appreciate that we do 

not have the luxury of sitting back and 

debating these issues ad nauseum. 

* * * * * 

14. The electricity sector is at a 

pivotal moment. With the clean energy 

transition gaining steam, we can either 

continue with the status quo, trying to 

meet the transmission needs of the 

future by building out the grid in a 

myopic, piecemeal fashion, or we can 

start holistically and proactively 

planning for those future transmission 

needs. We believe that today’s advance 

notice of proposed rulemaking 

represents an important and essential 

first step in the right direction and 

toward the type of transmission 

planning and cost allocation paradigm 

that is necessary to protect customers, 

support reliability, and ensure just and 

reasonable rates. 

For these reasons, we respectfully 

concur. 

lllllllllllllllllllll

Richard Glick, 

Chairman. 

lllllllllllllllllllll

Allison Clements, 

Commissioner. 

Department of Energy 

Federal Energy Regulatory Commission 

Building for the Future Through Electric 

Regional Transmission Planning and 

Cost Allocation and Generator 

Interconnection 

Docket No. RM21–17–000 

(Issued July 15, 2021) 

DANLY, Commissioner, concurring: 

1. I concur with the issuance of this 

Advance Notice of Proposed 

Rulemaking (ANOPR) because the 

Commission is always entitled to solicit 

comments on possible changes to 

existing rules and a number of the 

questions raised here are worthy of 

consideration. 

2. I write separately to highlight one 

overarching concern. The ANOPR poses 

several questions where the answer is 

‘‘no.’’ Many of the contemplated 

proposals would exceed or cede our 

jurisdictional authority, violate cost 

causation principles, create stifling 

layers of oversight and ‘‘coordination,’’ 

trample transmission owners’ rights, 

force neighboring states’ ratepayers to 

shoulder the costs of other states’ public 

policy choices, treat renewables as a 

new favored class of generation with 

line-jumping privileges, and perhaps 

inadvertently lead to much less 

transmission being built and at much 

greater all-in cost to ratepayers. 

3. There are obviously problems with 

the existing transmission regime. I, for 

example, have long been troubled by 

interconnection logjams and have 

wondered whether we are needlessly 

propping up fantasy projects while 

viable projects get lost in the crowd.1

This is but one example; there are any 

number of other critical transmission 

planning reforms that bear investigation. 

4. My hope therefore is that 

commenters will supply us with a full 

record on each issue raised in the 

ANOPR: Whether and why the existing 

rule works or not, and whether and why 

the possible reform may work or not. 

With every proposed change, I 

specifically solicit comments on two 

subjects. First: Is the contemplated 

reform a proper exercise of the 

Commission’s authority, i.e., is it within 

our jurisdiction? That is always the 

threshold question before we turn to 

policy. Second: what will be the 

ultimate effect on ratepayers? I fear that 

in the enthusiasm to build transmission, 

many may tout the benefits of new 

transmission while overlooking the 

costs that will eventually be borne by 

ratepayers. No proposed policy, 


lotter on DSK11XQN23PROD with PROPOSALS2
40298 Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules 

1ANOPR at P 4 (‘‘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 those proposals and welcome commenters to 

offer additional or alternative proposals for 

consideration.’’). 

however worthy, can evade our 

statutory duty to ensure that rates are 

just and reasonable. 

5. I encourage everyone with an 

interest to file. I look forward to learning 

from the parties that submit comments 

and to engaging with my colleagues to 

consider whether there are legally 

durable, economically sound reforms 

that we might consider to improve the 

reliability of the transmission system at 

just and reasonable rates. 

For these reasons, I respectfully 

concur. 

lllllllllllllllllllll

James P. Danly, 

Commissioner. 

Department of Energy 

Federal Energy Regulatory Commission 

Building for the Future Through Electric 

Regional Transmission Planning and 

Cost Allocation and Generator 

Interconnection 

Docket No. RM21–17–000 

(Issued July 15, 2021) 

CHRISTIE, Commissioner, concurring: 

1. I concur with today’s ANOPR 

because approximately ten years after 

the Commission issued Order No. 1000, 

it is appropriate to review the 

implementation of that order, assess the 

successes and problems that have 

become evident over the past decade, 

and consider reforms and revisions to 

existing regulations governing regional 

transmission planning and cost 

allocation. This consideration of 

potential reforms is especially timely as 

the transmission system faces the 

challenge of maintaining reliability 

through the changing generation mix 

and efforts to reduce carbon emissions. 

2. The broad goal of the Commission’s 

regulation of our nation’s power grid 

under the Federal Power Act (FPA) is to 

ensure a reliable power supply to 

consumers, which includes residential 

customers as well as the businesses 

providing jobs for tens of millions of 

Americans, at just and reasonable rates. 

Transmission is one of the three 

essential elements of a reliable power 

system, along with generation and 

distribution, so continually working to 

make America’s transmission system 

more reliable, more efficient, and more 

cost-effective is our job at FERC. 

3. As with Order No. 1000, the 

statutory framework governing our 

potential actions in this proceeding 

remains section 206 of the FPA, which 

requires us to ensure that all 

transmission planning processes and 

cost allocation mechanisms subject to 

our jurisdiction result in jurisdictional 

services being provided at rates, terms 

and conditions that are just, reasonable, 

and not unduly discriminatory or 

preferential. Any proposals ultimately 

adopted by this Commission for reforms 

or revisions to existing regulations must 

be consistent with this authority. 

4. As Paragraph 4 of the ANOPR 

makes clear,1 we have not 

predetermined that any specific 

proposal in this ANOPR has already 

been or will ultimately be approved. 

Rather, we seek comment from all 

interested persons and organizations on 

the wide range of proposals contained 

herein, as well as the submission of 

alternative proposals. Today is the 

beginning of a long process and I look 

forward to hearing from all concerned. 

5. Similarly, my concurrence to issue 

today’s ANOPR does not represent an 

endorsement at this point in the process 

of any one or more of the proposals 

included in the order. This ANOPR 

contains a number of good proposals, 

some potentially good proposals 

(depending on how they are fleshed 

out), and frankly, some proposals that 

are not—and may never be—ready for 

prime time, or could potentially cause 

massive increases in consumers’ bills 

for little to no commensurate benefit or 

inappropriately expand the role of 

federal regulation over local utility 

regulation. Given the early stage of this 

process, however, I agree it is 

worthwhile to submit a broad range of 

proposals to the public for comment in 

the hope that the final result will be a 

more reliable, more efficient, and more 

cost-effective transmission system. 

For these reasons, I respectfully 

concur. 

lllllllllllllllllllll

Mark C. Christie, 

Commissioner. 

[FR Doc. 2021–15512 Filed 7–26–21; 8:45 am] 

BILLING CODE 6717–01–P 


lotter on DSK11XQN23PROD with PROPOSALS2